-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, C1O8aWrmGwGQ57EFcDL5H9GmVr3tX1wwlWwJHS4wAwWEy1ywZjRXU/0o2L1zsNCn 10YuBh3xF7UG5FioKwpaRA== 0000004904-04-000091.txt : 20040507 0000004904-04-000091.hdr.sgml : 20040507 20040507170252 ACCESSION NUMBER: 0000004904-04-000091 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20040331 FILED AS OF DATE: 20040507 FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMERICAN ELECTRIC POWER CO INC CENTRAL INDEX KEY: 0000004904 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 134922640 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03525 FILM NUMBER: 04789940 BUSINESS ADDRESS: STREET 1: 1 RIVERSIDE PLAZA CITY: COLUMBUS STATE: OH ZIP: 43215 BUSINESS PHONE: 614-716-1193 MAIL ADDRESS: STREET 1: 1 RIVERSIDE PLAZA CITY: COLUMBUS STATE: OH ZIP: 43215 FORMER COMPANY: FORMER CONFORMED NAME: KINGSPORT UTILITIES INC DATE OF NAME CHANGE: 19660906 10-Q 1 q10410q.txt 10Q

FORWARD-LOOKING INFORMATION This report made by AEP and certain of its subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of 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 Weather conditions. o Available sources and costs of fuels. o Availability of generating capacity and the performance of AEP's generating plants. o The ability to recover regulatory assets and stranded costs in connection with deregulation. o New legislation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon and other substances. o Resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery for environmental compliance). o Oversight and/or investigation of the energy sector or its participants. o Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp.). o AEP's ability to reduce its operation and maintenance costs. o The success of disposing of investments that no longer match AEP's business model. o AEP's ability to sell assets at acceptable prices and on other acceptable terms. o International and country-specific developments affecting foreign investments including the disposition of any foreign investments. o The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns. o Inflationary trends. o AEP's ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas, and other energy-related commodities. o Changes in the creditworthiness and number of participants in the energy trading market. o Changes in the financial markets, particularly those affecting the availability of capital and AEP's ability to refinance existing debt at attractive rates. o Actions of rating agencies, including changes in the ratings of debt and preferred stock. o Volatility and changes in markets for electricity, natural gas, and other energy-related commodities. o Changes in utility regulation, including the establishment of a regional transmission structure. o Accounting pronouncements periodically issued by accounting standard-setting bodies. o The performance of AEP's pension plan. o Prices for power that AEP generates and sells at wholesale. o Changes in technology and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS ----------------------------------------------------------------------- RESULTS OF OPERATIONS - --------------------- AEP's principal operating business segments and their major activities are: o Utility Operations: o Domestic generation of electricity for sale to retail and wholesale customers o Domestic electricity transmission and distribution o Investments-Gas Operations:* o Gas pipeline and storage services o Investments-UK Operations:** o International generation of electricity for sale to wholesale customers o Coal procurement and transportation to AEP plants and third parties o Investments-Other: o Coal mining, bulk commodity barging operations and other energy supply related businesses * Operations of Louisiana Intrastate Gas were classified as discontinued during 2003. ** UK Operations were classified as discontinued during 2003. For information on our strategic outlook, see "Management's Financial Discussion and Analysis of Results of Operations", including "Business Strategy", in our 2003 Annual Report. American Electric Power Company's consolidated Net Income for the three months ended March 31, 2004 and 2003 were as follows (Earnings and Average Shares Outstanding in millions):

First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Income Before Discontinued Operations and Cumulative Effect of Accounting Changes decreased $2 million to $291 million in 2004 compared to 2003. Net Income for 2004 of $278 million or $0.70 per share includes a loss, net of taxes, on discontinued operations of $13 million. Net Income for 2003 of $440 million or $1.24 per share includes a loss, net of taxes, from discontinued operations of $46 million and a favorable impact of $193 million, net of tax, from implementing accounting pronouncements related to risk management contracts and asset retirement obligations. During the fourth quarter of 2003 we concluded that the UK Operations and LIG were not part of our core business, and we began actively marketing each of these investments for sale. The UK Operations consist of our generation and trading operations that sell to wholesale customers and our coal procurement and transportation operations. We continue to seek buyers for our UK Operations. LIG's operations include 2,000 miles of intrastate gas pipelines, gas processing facilities and a 9 billion cubic feet natural gas storage facility. The pipeline and processing operations of LIG were sold in April 2004 (see Note 7). Average shares outstanding increased to 395 million in 2004 from 356 million in 2003 due to a common stock issuance in March 2003. The additional average shares outstanding decreased our 2004 earnings per share by $0.08. Our results of operations are discussed below according to our operating segments. Utility Operations - ------------------ Summary of Selected Sales Data For Utility Operations For the Three Months Ended March 31, 2004 and 2003 2004 2003 ------- ------- Energy Summary (in millions of KWH) Retail Residential 13,442 13,513 Commercial 8,827 8,891 Industrial 12,434 12,612 Miscellaneous 743 695 ------- ------- Total 35,446 35,711 ------- ------- Wholesale 19,341 20,359 ------- ------- 2004 2003 ------- ------- Weather Summary (in degree days) Eastern Region Actual - Heating 1,864 2,028 Normal - Heating* 1,806 ** Actual - Cooling 3 1 Normal - Cooling* 3 ** Western Region Actual - Heating 553 684 Normal - Heating* 634 ** Actual - Cooling 56 24 Normal - Cooling* 49 ** *Normal Heating/Cooling represents the 30-year average of degree days. **Not meaningful. First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Income from Utility Operations, before the 2003 $236 million cumulative effect of accounting changes, decreased $7 million to $299 million in 2004. A $32 million increase in gross margins and a $12 million decrease in other expenses offset a $51 million increase in operations and maintenance expense. Our gross margin, defined as utility revenues net of related fuel and purchased power, increased as follows: o Residential demand decreased slightly over the prior year as a consequence of milder weather, while slightly lower commercial and industrial demand resulted from the continued slow economic recovery in our regions. Our reduced demand was offset by increases in fuel recoveries, coming from lower 2004 fuel disallowances in Texas when compared to 2003. The net impact of lower demand and higher fuel recoveries was a slightly improved retail energy contribution to earnings. o Beginning in 2004, we no longer recognize revenues for excess cost over market-based stranded costs, resulting in $56 million of lower regulatory deferrals for excess cost over market-based stranded costs which reduced earnings. For the years 2003 and 2002, we recognized the non-cash provisions for stranded cost recovery in Texas as a regulatory asset for 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 a PUCT model. o Margins from off-system sales for 2004 were $50 million better than in 2003 due to favorable power and coal optimization activity. Utility operating expenses increased as follows: o Maintenance and Other Operation expense increased $51 million due to the timing of tree trimming activity and planned plant outages in 2004 compared to 2003. These increases were offset, in part, by the changes in accounting treatment for our Gavin Scrubber Leases. o Depreciation and Amortization expense increased $15 million due, in part, to the change in our accounting treatment for Gavin Scrubber Leases when we adopted the provisions of a new accounting interpretation (FIN 46) in the second half of 2003. The accounting change caused similar offsetting decreases in Maintenance and Other Operation expenses. Investments - Gas Operations - ---------------------------- First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Our $10 million loss from our Gas Operations before discontinued operations and cumulative effect of accounting changes compares with an $18 million loss recorded in the first quarter of 2003. Gross margins improved year-over-year, excluding the effect of one time accounting adjustments, and operating expenses have decreased as a result of the reduction in our trading activities. Investments - UK Operations - --------------------------- First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Our UK Operations (all classified as Discontinued Operations) incurred a loss of $12 million for 2004 compared with a loss of $40 million in 2003, before the cumulative effect of accounting changes. During late 2003, we concluded that the UK Operations were not part of our core business and we began actively marketing our investment. As a result, we impaired certain U.K. investments in the fourth quarter of 2003 based on bids received from interested buyers. Our UK Operations gross margins from generation increased $45 million in 2004, reflecting the improvement in wholesale electricity prices in the U.K. but were offset by a $49 million increase in losses from coal and freight contracts. These losses resulted from adverse price movements during the quarter. The decrease in the overall UK Operations loss was driven by an $8 million decrease in trading expenses, a $5 million decrease in depreciation from the cessation of plant depreciation, a $12 million decrease in interest expense and a $7 million decrease in tax expense. Investments - Other - ------------------- First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Income before discontinued operations and cumulative effect of accounting changes from our Other Investments segment decreased by $9 million to $11 million in 2004. The decrease was primarily due to a $26 million nonrecurring gain from the sale of Mutual Energy recorded in 2003. This was offset by a $4 million increase in results at AEP Coal and an increase in income in our independent power producer and wind farm investments. The majority of the AEP Coal assets were sold in April 2004 (see Note 7). All Other - --------- Our parent company's 2004 expenses decreased $6 million over 2003 primarily from lower interest costs due to decreased debt at the parent level and reduced reliance on short-term borrowings. FINANCIAL CONDITION - ------------------- We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.

In addition to the impact of our $901 million in cash flows from operations and a reduction in dividends paid, we reduced long-term debt by $334 million. We also improved our percentage of common equity outstanding to total capitalization, in part through the issuance of $10 million of new common equity. As a consequence of the capital changes during the quarter, we improved our ratio of debt to total capital. In April 2004, we retired approximately $76.2 million of long-term debt using the net cash proceeds from the sale of LIG Pipeline assets. Liquidity - --------- Liquidity, or access to cash, is an important factor in determining our financial stability due to volatility in wholesale power prices and the effects of credit rating downgrades. We are committed to preserving an adequate liquidity position. Credit Facilities - ----------------- We manage our liquidity by maintaining adequate external financing commitments. We had an available liquidity position, at March 31, 2004, of approximately $3.6 billion as illustrated in the table below.

Debt Covenants - -------------- Our revolving credit agreements require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating our outstanding debt and other capital is contractually defined. At March 31, 2004, this percentage was 57.6%. Non-performance of these covenants may result in an event of default under these credit agreements. At March 31, 2004, we were in compliance with the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or certain obligations of our subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million would cause an event of default under these credit agreements and permit the lenders to declare the amounts outstanding thereunder payable. Our commercial paper backup facilities generally prohibit new borrowings if we experience a material adverse change in our business or operations. We may, however, make new borrowings under these facilities if we experience a material adverse change so long as the proceeds of such borrowings are used to repay outstanding commercial paper. Under an SEC order, AEP and our utility subsidiaries cannot incur additional indebtedness if the issuer's common equity would constitute less than 30% (25% for TCC) of its capital. In addition, this order restricts us and our utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization. Credit Ratings - -------------- We continue to take steps to improve our credit quality, including plans during 2004 to further reduce our outstanding debt through the use of proceeds from our planned dispositions. If we receive a downgrade in our credit ratings by one of the nationally recognized rating agencies listed below, our borrowing costs would increase. 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 Cash Flow - --------- Our cash flows are a major factor in managing and maintaining our liquidity strength.

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provide necessary working capital and help us meet other short-term cash needs. We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a utility money pool which funds the utility subsidiaries and a non-utility money pool which funds the majority of the non-utility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in the non-utility money pool for regulatory or operational reasons. We generally use short-term borrowings to fund working capital needs, 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. Money pool and external borrowings may not exceed SEC authorized limits. Operating Activities - -------------------- Three Months Ended March 31, 2004 2003 ---- ---- (in millions) Net Income $278 $440 Plus: Discontinued Operations 13 46 ----- ----- Income from Continuing Operations 291 486 Noncash Items Included in Earnings 208 73 Changes in Assets and Liabilities 402 203 ----- ----- Net Cash Flows From Operating Activities $901 $762 ===== ===== 2004 Operating Cash Flow - ------------------------ Our cash flows from operating activities were $901 million for the first quarter 2004. We produced income from continuing operations of $291 million during the period. Income from continuing operations for the period included noncash expense items of $267 million for depreciation, amortization and deferred taxes. In addition, there is a current period impact for a net $59 million balance sheet change for risk management contracts that are marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. The other changes in assets and liabilities represent those items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are changes in accounts receivable and accounts payable of $83 million, and an increase in the balance of accrued taxes of $189 million. 2003 Operating Cash Flow - ------------------------ Income from continuing operations was $486 million for the first quarter of 2003. Income from continuing operations for the period included noncash items of $247 million for depreciation, amortization, and deferred taxes, and $193 million related to the cumulative effect of an accounting change. There was a current period impact for a net $19 million balance sheet change for risk management contracts that were marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. The other activity in the asset and liability accounts related to the wholesale capacity auction true-up asset (ECOM) of $56 million, deposits associated with risk management activities of $201 million, and seasonal increases in accrued taxes of $206 million. Investing Activities - -------------------- Three Months Ended March 31, 2004 2003 ---- ---- (in millions) Construction Expenditures $(309) $(292) Investment in Discontinued Operations, net 7 (749) Proceeds from Sale of Assets 40 35 Other 8 5 ------ -------- Net Cash Flows Used for Investing Activities $(254) $(1,001) ====== ======== Our cash flows used for investing activities decreased $747 million from the same period in the prior year primarily due to investments made in our U.K. operations during the first quarter of 2003 that did not recur during the first quarter of 2004. Financing Activities - -------------------- Three Months Ended March 31, 2004 2003 ---- ---- (in millions) Issuances of Common Stock $10 $1,143 Issuances/Retirements of Debt, net (444) (186) Retirement of Preferred Stock (4) - Dividends (138) (203) ------ ------- Net Cash Flows From (Used for) Financing Activities $(576) $754 ====== ======= Our cash flow for financing activities in 2004 decreased $1.3 billion from the $754 million net cash inflow recorded in the first quarter of 2003. During the first quarter of 2003 we issued $1,143 million of common stock and subsequent to the first quarter of 2003, we reduced our dividend. This compares to only $10 million of cash proceeds from the issuance of common in the first quarter of 2004. During the first three months of 2004, we retired approximately $414 million of long-term debt, excluding $25 million related to an asset sale, and decreased our short-term debt by $103 million. We also issued approximately $73 million of long-term debt including $54 million of pollution control bonds (installment purchase contracts) at SWEPCo. These activities were supported by the generation of $901 million in cash flow from operations. See Note 10 "Financing Activities" for further information regarding issuances and retirements of debt instruments during the first quarter of 2004. Off-balance Sheet Arrangements - ------------------------------ We enter into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. Our off-balance sheet arrangements have not changed significantly from year-end 2003 and are comprised of a sale of receivables agreement maintained by AEP Credit, a sale and leaseback transaction entered into by AEGCo and I&M with an unrelated unconsolidated trustee, and an agreement with an unrelated, unconsolidated leasing company to lease coal-transporting aluminum railcars. Our current plans limit the use of off-balance sheet financing entities or structures, except for traditional operating lease arrangements and sales of customer accounts receivable that are entered into in the normal course of business. For complete information on each of these off-balance sheet arrangements see the "Minority Interest and Off-balance Sheet Arrangements" in "Management's Financial Discussion and Analysis of Results of Operations" section of the 2003 Annual Report. Other - ----- Power Generation Facility - ------------------------- We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, own and finance a non-regulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to us. The Facility is a "qualifying cogeneration facility" for purposes of PURPA. Commercial operation of the Facility as required by the agreements between Juniper, AEP and The Dow Chemical Company (Dow) was achieved on March 18, 2004. The initial term of the lease commenced on March 18, 2004, and we may extend the lease term for up to 30 years. The lease of the Facility is reported as an owned asset under a lease financing transaction. Therefore, the asset and related liability for the debt and equity of the facility are recorded on AEP's balance sheet. Juniper is an unaffiliated limited partnership, 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 arranged to finance the Facility with debt financing up to $494 million and equity up to $31 million from investors with no relationship to AEP or any of AEP's subsidiaries. At March 31, 2004, Juniper's acquisition costs for the Facility totaled $516 million, and we estimate total costs for the completed Facility to be approximately $525 million. For the 30-year extended lease term, the majority of base lease rental is a variable rate obligation indexed to three-month LIBOR (1.11% as of March 31, 2004). Consequently, as market interest rates increase, the base rental payments under the lease will also increase. Juniper is currently planning to refinance by June 30, 2004. The Facility is collateral for the debt obligation of Juniper. An additional rental prepayment (up to $396 million) may be due on June 30, 2004 unless Juniper has refinanced its present debt financing on a long-term basis. At March 31, 2004 and December 31, 2003, we reflected $396 million as long-term debt due within one year. Our maximum required cash payment as a result of our financing transaction with Juniper is $396 million as well as interest payments during the lease term. Due to the treatment of the Facility as a financing of an owned asset, the recorded liability of $516 million is greater than our maximum possible cash payment obligation to Juniper. Dow will use a portion of the energy produced by the Facility and sell the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as non-conforming. Commercial operation for purposes of the PPA began April 2, 2004. On September 5, 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We allege that TEM has breached the PPA, and we are seeking a determination of our rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of AEP breaches. If the PPA is deemed terminated or found to be unenforceable by the court, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover claimed termination value damages from TEM. The corporate parent of TEM has provided a limited guaranty. On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the "creation of protocols" was not subject to arbitration, but did not rule upon the merits of TEM's claim that the PPA is not enforceable. On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the "Commercial Operations Date." Despite OPCo's prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo's tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for them under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo (i) was suspending performance of its obligations under PPA, (ii) would be seeking a declaration from the New York federal court that the PPA has been terminated and (iii) would be pursuing against TEM and Tractebel SA under the guaranty damages and the full termination payment value of the PPA. SIGNIFICANT FACTORS - ------------------- Progress Made on Announced Divestitures - --------------------------------------- We are continuing with our announced plan to divest significant components of our non-regulated assets, including certain domestic and international unregulated generation, part of our gas pipeline and storage business, a coal business and certain independent power producers (IPPs). Pushan Power Plant - ------------------ In December 2003, we signed an agreement to sell our interest in the Pushan Power Plant in Nanyang, China to our minority interest partner. The sale was completed in March 2004 and the effect of the sale on our first quarter results of operations was not significant. Texas Generation - ---------------- We made progress on our planned divestiture of certain Texas generation assets by (1) announcing in January 2004 that we had signed an agreement to sell TCC's 7.8% share of the Oklaunion Power Station for approximately $43 million, subject to closing adjustments, (2) announcing in February 2004 that we had signed an agreement to sell TCC's 25.2% share of the South Texas Project nuclear plant for approximately $333 million, subject to closing adjustments, and (3) announcing in March 2004 that we had signed an agreement to sell TCC's remaining generating assets, including eight natural gas plants, one coal-fired plant and one hydro plant for approximately $430 million, subject to closing adjustments. Subject to certain co-owners' rights of first refusal, we expect all of our announced sales to close before the end of 2004, after receiving appropriate regulatory approvals and clearances. We will file with the Public Utility Commission of Texas to recover net stranded costs associated with each of the sales pursuant to Texas restructuring legislation. AEP Coal - -------- In 2003, as a result of management's decision to exit our non-core business, we retained an advisor to facilitate the sale of AEP Coal. In March 2004, an agreement was reached to sell assets, exclusive of certain reserves and related liabilities, of the mining operations of AEP Coal. The sale closed in April 2004 and the effect of the sale on second quarter of 2004 results of operations should not be significant. Gas Operations - -------------- During the third quarter of 2003, management hired advisors to review business options regarding various investment components of our Investments-Gas Operations segment. We continue to evaluate the merits of retaining our interest in Houston Pipe Line, which is part of our Investments-Gas Operations segment. In February 2004, we signed an agreement to sell the pipeline assets of LIG. The sale was completed in early April 2004 and the impact on results of operations in the second quarter of 2004 is not expected to be significant. We continue to market the remaining LIG gas storage assets. IPP Investments - --------------- During the third quarter of 2003, we initiated an effort to sell four domestic IPP investments. In accordance with accounting principles generally accepted in the United States of America, we were required to measure the impairment of each of these four investments individually. Based on studies using market assumptions, which indicated that two of the facilities had declines in fair value that were other than temporary in nature, we recorded an impairment of $70 million pre-tax ($45.5 million net of tax) in the third quarter of 2003. During the fourth quarter of 2003, we distributed an information memorandum related to the planned sale of our interest in these IPPs. In March 2004, we entered into an agreement to sell the four IPP investments for a sales price of $156 million, subject to closing adjustments. We expect the transaction will result in a pre-tax gain of approximately $100 million (primarily related to the two facilities in Florida which were not impaired) when the sale is expected to close later in 2004. UK Operations - ------------- During the fourth quarter of 2003, we engaged an advisor for the disposition of our U.K business. In connection with the evaluation of this business, we recorded a pre-tax charge of $577.4 million during the fourth quarter of 2003 based on indications of value received from potential buyers. We continue to work towards identifying a buyer for these assets and plan to dispose of them during 2004. Other - ----- We continue 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. We believe our non-core assets are stated at fair value. However, we may realize losses from operations or losses upon disposition of these assets that, in the aggregate, could have a material impact on our results of operations, cash flows and financial condition. RTO Formation - ------------- 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 our subsidiaries' transmission systems to RTOs. In addition, legislation in some of our states requires RTO participation. The status of the transfer of functional control of our subsidiaries' transmission systems to RTOs or the status of our participation in RTOs has not changed significantly from our disclosure as described in "RTO Formation" within the "Management's Financial Discussion and Analysis of Results of Operations" section of the 2003 Annual Report. In November 2003, the FERC preliminarily found that we must fulfill our CSW merger condition to join an RTO by integrating into PJM (transmission and markets) by October 1, 2004. FERC based their order on PURPA 205(a), which allows FERC to exempt electric utilities from state law or regulation in certain circumstances. An ALJ held hearings on issues including whether the laws, rules, or regulations of Virginia and Kentucky prevent us from joining an RTO and whether the exceptions under PURPA 205(a) apply. The FERC ALJ affirmed the FERC's preliminary findings in March 2004. The FERC has not issued a final order in this matter. In April 2004, we reached an agreement with interveners to settle the RTO issues in Kentucky. The KPSC is expected to consider the settlement agreement in May 2004. Litigation - ---------- We continue to be involved in various litigation matters as described in the "Significant Factors - Litigation" section of Management's Financial Discussion and Analysis of Results of Operations in our 2003 Annual Report. The 2003 Annual Report should be read in conjunction with this report in order to understand other litigation matters that did not have significant changes in status since the issuance of our 2003 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition. Other matters described in the 2003 Annual Report that did not have significant changes during the first quarter of 2004, that should be read in order to gain a full understanding of our current litigation include: (1) Bank of Montreal Claim, (2) Shareholders' Litigation, (3) Cornerstone Lawsuit, and (4) Texas Commercial Energy, LLP Lawsuit. Federal EPA Complaint and Notice of Violation - --------------------------------------------- See discussion of New Source Review Litigation within "Significant Factors - Environmental Matters." Enron Bankruptcy - ---------------- In 2002, certain of our subsidiaries filed claims against Enron and its subsidiaries in the bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, certain of our subsidiaries 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 from Enron remained unsettled at the date of Enron's bankruptcy. Bammel storage facility and HPL indemnification matters - In connection with the 2001 acquisition of HPL, we entered into a prepaid arrangement under which we acquired exclusive rights to use and operate the underground Bammel gas storage facility and appurtenant pipelines pursuant to an agreement with BAM Lease Company. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years. In January 2004, we filed an amended lawsuit against Enron and its subsidiaries in the U.S. Bankruptcy Court claiming that Enron did not have the right to reject the Bammel storage facility agreement or the cushion gas use agreement, described below. In April 2004, AEP and Enron entered into a settlement agreement under which we will acquire title to the Bammel gas storage facility and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF) of natural gas currently used as cushion gas for $115 million. AEP and Enron will mutually release each other from all claims associated with the Bammel facility, including our indemnity claims. The proposed settlement is subject to Bankruptcy Court approval. The parties respective trading claims and Bank of America's (BOA) purported lien on approximately 55 BCF of natural gas in the Bammel storage reservoir (as described below) are not covered by the settlement agreement. Right to use of cushion gas agreements - In connection with the 2001 acquisition of HPL, we also entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 BCF of cushion gas (10.5 BCF and 55 BCF as described in the preceeding paragraph) required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. At the time of our acquisition, Enron and the BOA Syndicate also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement. After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. In July 2002, the BOA Syndicate filed a lawsuit against HPL in the state court of Texas seeking a declaratory judgment that they have a valid and enforceable security interest in gas purportedly in the Bammel storage reservoir. In December 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows and financial condition. In October 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron's financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In February 2004, Enron, in connection with BOA's dispute, filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements. We have objected to Enron's attempted rejection of these agreements. Management is unable to predict the outcome of these proceedings or the impact on results of operations, cash flows or financial condition. Commodity trading settlement disputes - In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP's offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas related trading transactions. AEP has asserted its right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. Enron bankruptcy summary - The amount expensed in prior years in connection with the Enron bankruptcy 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. As noted above, Enron has challenged our offsetting of receivables and payables and there is a dispute regarding the cushion gas agreement. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. Energy Market Investigations - ---------------------------- 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 (CFTC), 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 and 2004. On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas in violation of the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and disgorgement of benefits. The case is in the initial pleading stage with our response to the complaint currently due on May 18, 2004. Although management is unable to predict the outcome of this case, we recorded a provision in 2003 and the action is not expected to have a material effect on results of operations. In January 2004, the CFTC issued a request for documents and other information in connection with a CFTC investigation of activities affecting the price of natural gas in the fall of 2003. We are responding to that request. Management cannot predict whether these governmental agencies will take further action with respect to these matters. TEM Litigation - -------------- See discussion of TEM litigation within the "Power Generation Facility" section of "Financial Condition - Other" within Management's Financial Discussion and Analysis of Results of Operations. Environmental Matters - --------------------- As discussed in our 2003 Annual Report, there are new environmental control requirements that we expect will result in substantial capital investments and operational costs through 2010. The sources of these future requirements include: o Legislative and regulatory proposals to adopt stringent controls on sulfur dioxide (SO2), nitrogen oxide (NOx) and mercury emissions from coal-fired power plants, o New Clean Water Act rules to reduce the impacts of water intake structures on aquatic species at certain of our power plants, and o Possible future requirements to reduce carbon dioxide emissions to address concerns about global climatic change. This discussion updates certain events occurring in 2004 and adds an estimate of future capital expenditures for the Clean Water Act rule. You should also read the "Significant Factors - Environmental Matters" section within Management's Financial Discussion and Analysis of Results of Operations in our 2003 Annual Report for a complete description of all material environmental matters affecting us, including, but not limited to, (1) the current air quality regulatory framework, (2) estimated air quality environmental investments, (3) superfund and state remediation, (4) global climate change, and (5) costs for spent nuclear fuel and decommissioning. Future Reduction Requirements for SO2, NOx, and Mercury - ------------------------------------------------------- In 1997, the Federal EPA adopted new, more stringent national ambient air quality standards for fine particulate matter and ground-level ozone. The Federal EPA is in the process of developing final designations for fine particulate matter and ground-level ozone non-attainment areas. The Federal EPA finalized designations for ozone non-attainment areas on April 15, 2004. On the same day, the Administrator of the Federal EPA signed a final rule establishing the elements that must be included in state implementation plans (SIPs) to achieve the new standards, and setting deadlines ranging from 2008 to 2015 for achieving compliance with the final standard, based on the severity of non-attainment. All or parts of 474 counties are affected by this new rule, including many urban areas in the Eastern United States. The Federal EPA identified SO2 and NOx emissions as precursors to the formation of fine particulate matter. NOx emissions are also identified as a precursor to the formation of ground-level ozone. As a result, requirements for future reductions in emissions of NOx and SO2 from our generating units are highly probable. In addition, the Federal EPA proposed a set of options for future mercury controls at coal-fired power plants. Regulatory Emissions Reductions - ------------------------------- On January 30, 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% each in emissions of SO2, NOx and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components: o The Federal EPA proposed an interstate air quality rule for reducing SO2 and NOx emissions across the eastern half of the United States (29 states and the District of Columbia) to address attainment of the fine particulate matter and ground-level ozone national ambient air quality standards. These reductions could also satisfy these states' obligations to make reasonable progress towards the national visibility goal under the regional haze program. o The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units. The interstate air quality rule would require affected states to include, in their SIPs, a program to reduce NOx and SO2 emissions from coal-fired electric utility units. SO2 and NOx emissions would be reduced in two phases, which would be implemented through a cap-and-trade program. Regional SO2 emissions would be reduced to 3.9 million tons by 2010 and to 2.7 million tons by 2015. Regional NOx emissions would be reduced to 1.6 million tons by 2010 and to 1.3 million tons by 2015. Rules to implement the SO2 and NOx trading programs have not yet been proposed. On April 15, 2004, the Federal EPA Administrator signed a proposed rule detailing how states should analyze and include "Best Available Retrofit" requirements for individual facilities in their SIPs to address regional haze. The guidance applies to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain regulated pollutants in specific industrial categories, including utility boilers. The Federal EPA included an alternative "Best Available Retrofit" program based on emissions budgeting and trading programs. For utility units that are affected by the January 24, 2004 Interstate Air Quality Rule (IAQR), described above, the Federal EPA proposed that participation in the trading program under the IAQR would satisfy any applicable "Best Available Retrofit" requirements. To control and reduce mercury emissions, the Federal EPA published two alternative proposals. The first option requires the installation of maximum achievable control technology (MACT) on a site-specific basis. Mercury emissions would be reduced from 48 tons to approximately 34 tons by 2008. The Federal EPA believes, and the industry concurs, that there are no commercially available mercury control technologies in the marketplace today that can achieve the MACT standards for bituminous coals, but certain units have achieved comparable levels of mercury reduction by installing conventional SO2 (scrubbers) and NOx (SCR) emission reduction technologies. The proposed rule imposes significantly less stringent standards on generating plants that burn sub-bituminous coal or lignite, which standards potentially could be met without installation of mercury control technologies. The Federal EPA recommends, and we support, a second mercury emission reduction option. The second option would permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. This approach would coordinate the reduction requirements for mercury with the SO2 and NOx reduction requirements imposed on the same sources under the proposed interstate air quality rule. Coordination is significantly more cost-effective because technologies like scrubbers and SCRs, which can be used to comply with the more stringent SO2 and NOx requirements, have also proven highly effective in reducing mercury emissions on certain coal-fired units that burn bituminous coal. The second option contemplates reducing mercury emissions from 48 million tons to 34 million tons by 2010 and to 15 million tons by 2018. A supplemental proposal including unit-specific allocations and a framework for the emissions budgeting and trading program preferred by the Federal EPA was published in the Federal Register on March 16, 2004. Comments on both the initial proposal and the supplemental notice are due on or before June 29, 2004. The Federal EPA's proposals are the beginning of a lengthy rulemaking process, which will involve supplemental proposals on many details of the new regulatory programs, written comments and public hearings, issuance of final rules, and potential litigation. In addition, states have substantial discretion in developing their rules to implement cap-and-trade programs, and will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. As a result, the ultimate requirements may not be known for several years and may depart significantly from the original proposed rules described here. While uncertainty remains as to whether future emission reduction requirements will result from new legislation or regulation, it is certain under either outcome that we will invest in additional conventional pollution control technology on a major portion of our fleet of coal-fired power plants. Finalization of new requirements for further SO2, NOx and/or mercury emission reductions will result in the installation of additional scrubbers, SCR systems and/or the installation of emerging technologies for mercury control. New Source Review Litigation - ---------------------------- Under the Clean Air Act (CAA), 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 Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other unaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the CAA. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications relate to costs that were incurred at our generating units over a 20-year period. We are unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the CAA proceedings. We are also 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. If 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. Clean Water Act Regulation - -------------------------- On February 16, 2004, the Federal EPA signed a rule pursuant to the Clean Water Act that will require all large existing, once-through cooled power plants to meet certain performance standards to reduce the mortality of juvenile and adult fish or other larger organisms pinned against a plant's cooling water intake screens. All plants must reduce fish mortality by 80% to 95%. A subset of these plants that are located on sensitive water bodies will be required to meet additional performance standards for reducing the number of smaller organisms passing through the water screens and the cooling system. These plants must reduce the rate of smaller organisms passing through the plant by 60% to 90%. Sensitive water bodies are defined as oceans, estuaries, the Great Lakes, and small rivers with large plants. These rules will result in additional capital and operation and maintenance expenses to ensure compliance. The capital cost of compliance for our facilities, based on the Federal EPA's estimates in the rule, is $193 million. Any capital costs associated with compliance activities to meet the new performance standards would likely be incurred during the years 2008 through 2010. We have not independently confirmed the accuracy of the Federal EPA's estimate. The rule has provisions to limit compliance costs. We may propose less costly site-specific performance criteria if our compliance cost estimates are significantly greater than the Federal EPA's estimates or greater than the environmental benefits. The rule also allows us to propose mitigation (also called restoration measures) that is less costly and has equivalent or superior environmental benefits than meeting the criteria in whole or in part. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Management's Financial Discussion and Analysis of Results of Operations" in the 2003 Annual Report 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. Other Matters - ------------- As discussed in our 2003 Annual Report, there are several "Other Matters" affecting us, including FERC's proposed standard market design and FERC's market power mitigation efforts. These were no significant changes to the status of FERC's proposed standard market design. The current status of FERC's market power mitigation efforts is described below. FERC Market Power Mitigation - ---------------------------- A FERC order issued in November 2001 on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power system's status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. AEP and two unaffiliated utilities were required to submit generation market power analyses within sixty days of the FERC's order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. Management is unable to predict the outcome of these actions by the FERC or their affect on future results of operations and cash flows. 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. We have established policies and procedures which allow us to identify, assess, and manage market risk exposures in our day-to-day operations. Our risk policies have been reviewed with our Board of Directors and approved by our Risk Executive Committee. Our Chief Risk Officer administers our risk policies and procedures. The Risk Executive Committee establishes risk limits, approves risk policies, and assigns responsibilities regarding the oversight and management of risk and monitors risk levels. Members of this committee receive daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. Our committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers. We actively participate in the Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around risk management contracts. The CCRO is composed of the chief risk officers of major electricity and gas companies in the United States. The CCRO adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported. Implementation of the disclosures is voluntary. We support the work of the CCRO and have embraced the disclosure standards. The following tables provide information on our risk management activities. Mark-to-Market Risk Management Contract Net Assets (Liabilities) - ---------------------------------------------------------------- This table provides detail on changes in our 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 risk management contracts and related derivatives that settled during 2004 and were entered into prior to 2004. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value at inception of long-term contracts entered into with customers during 2004. 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 entered into in 2004. (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. (f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed in detail within the following pages. (g) See Note 7 for discussion of Assets Held for Sale.

Reconciliation of MTM Risk Management Contracts to Consolidated Balance Sheets As of March 31, 2004 Risk Management Cash Flow Assets Held Contracts* Hedges for Sale Consolidated ---------- --------- ----------- ------------ (in millions) Current Assets $1,132 $25 $(297) $860 Non Current Assets 692 1 (120) 573 -------- ------ ------ -------- Total Assets $1,824 $26 $(417) $1,433 -------- ------ ------ -------- Current Liabilities $(1,085) $(116) $461 $(740) Non Current Liabilities (520) (13) 134 (399) -------- ------ ------ -------- Total Liabilities $(1,605) $(129) $595 $(1,139) -------- ------ ------ -------- Total Net Assets (Liabilities) $219 $(103) $178 $294 ======== ====== ====== ======== *Excluding Cash Flow Hedges.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities) - ---------------------------------------------------------------------------- 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) 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. (c) Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet - -------------------------------------------------------------------------- We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk. We employ 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. We do not hedge all interest rate risk. We employ 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. We do not hedge all foreign currency exposure. The tables below provide detail on effective cash flow hedges under SFAS 133 included in our balance sheet. The data in the first table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, the table does not provide a full picture of our hedging activity. This table further indicates what portions of these hedges are expected to be reclassified into net income in the next 12 months. The second table provides the nature of changes from December 31, 2003 to March 31, 2004. Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with accounting principles generally accepted in the United States of America, all amounts are presented net of related income taxes.

(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 cash flow hedges not yet reclassified into net income, pending the hedged items 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 - ----------- We limit credit risk by assessing creditworthiness of potential counterparties before entering into transactions with them and continue to evaluate their creditworthiness after transactions have been initiated. Only after an entity has met our internal credit rating criteria will we extend unsecured credit. We use 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. Our independent analysis, in conjunction with the rating agencies' information, is used to determine appropriate risk parameters. We also require cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business. We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. Except for one counterparty who has a net exposure of approximately $45 million, we believe that credit exposure with any one counterparty is not material to our financial condition at March 31, 2004. At March 31, 2004, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 20% expressed in terms of net MTM assets and net receivables. The increase in non-investment grade credit quality was largely due to an increase to coal exposures related to domestic MTM coal transactions and coal and freight exposures related to our U.K. investments. These increases were driven by the continued high levels of prices for coal and freight. As of March 31, 2004, the following table approximates our counterparty credit quality and exposure based on netting across commodities and instruments:

Generation Plant Hedging Information - ------------------------------------ This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged. This information is forward-looking and provided on a prospective basis through December 31, 2006. Please note that this table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. "Estimated Plant Output Hedged," represents the portion of megawatt hours of future generation/production for which we have sales commitments or estimated requirement obligations to customers. Generation Plant Hedging Information Estimated Next Three Years As of March 31, 2004 Remainder 2004 2005 2006 ---- ---- ---- Estimated Plant Output Hedged 88% 91% 91% VaR Associated with Risk Management Contracts - --------------------------------------------- We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at March 31, 2004, a near term typical change in commodity prices is not expected to have a material effect on our 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 Three Months Ended Twelve Months Ended March 31, 2004 December 31, 2003 --------------------------- ---------------------------- (in millions) (in millions) End High Average Low End High Average Low --- ---- ------- --- --- ---- ------- --- $2 $19 $10 $2 $11 $19 $7 $4 The 2004 first quarter High VaR was due to the wind-down of the London risk management activities. These activities were concluded by the end of the quarter. Our VaR model results are adjusted using standard statistical treatments to calculate the CCRO VaR reporting metrics listed below.

We utilize 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 and a one-year holding period. The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $0.843 billion at March 31, 2004 and $1.013 billion at December 31, 2003. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not materially affect our results of operations or consolidated financial position. We are 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 a settlement agreement in West Virginia. To the extent the fuel supply of the generating units in these states is not under fixed-price long-term contracts, we are subject to market price risk. We continue to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. Fuel clauses are active again in Michigan and Indiana, effective January 1, 2004 and March 1, 2004, respectively. We employ risk management contracts including 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. We engage in risk management of electricity, gas and to a lesser degree other commodities, principally coal and freight. As a result, we are subject to price risk. The amount of risk taken is controlled by risk management operations and our Chief Risk Officer and his staff. When risk management activities exceed 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.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED LONG-TERM DEBT March 31, 2004 and December 31, 2003 (Unaudited) 2004 2003 ---- ---- (in millions) TOTAL LONG-TERM DEBT OUTSTANDING -------------------------------- First Mortgage Bonds $835 $940 Installment Purchase Contracts 1,990 2,026 Notes Payable 1,491 1,518 Senior Unsecured Notes 7,857 7,997 Securitization Bonds 718 746 Notes Payable to Trust 331 331 Equity Unit Senior Notes 345 345 Long-term DOE Obligation (a) 227 226 Other Long-term Debt 21 21 Equity Unit Contract Adjustment Payments 16 19 Unamortized Discount (net) (64) (68) -------- -------- TOTAL 13,767 14,101 Less Portion Due Within One Year 1,904 1,779 -------- -------- TOTAL LONG-TERM PORTION $11,863 $12,322 ======== ======== (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation with the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. I&M is the only AEP subsidiary that generated electric power with nuclear fuel prior to that date. Trust fund assets of $269 million and $262 million related to this obligation are included in Spent Nuclear Fuel and Decommissioning Trusts in the Consolidated Balance Sheets at March 31, 2004 and December 31, 2003, respectively. AMERICAN ELECTRIC POWER, INC. AND SUBSIDIARY COMPANIES INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Significant Accounting Matters 2. New Accounting Pronouncements 3. Rate Matters 4. Customer Choice and Industry Restructuring 5. Commitments and Contingencies 6. Guarantees 7. Dispositions, Discontinued Operations and Assets Held for Sale 8. Benefit Plans 9. Business Segments 10. Financing Activities AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SIGNIFICANT ACCOUNTING MATTERS ------------------------------ General - ------- The accompanying unaudited interim financial statements should be read in conjunction with the 2003 Annual Report as incorporated in and filed with our 2003 Form 10-K. In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. Other Income (Expense), Net The following table provides the components of Other Income (Expense), Net as presented on our Consolidated Statements of Operations: Three Months Ended March 31, 2004 2003 ---- ---- (in millions) Other Income: Interest and Dividend Income $6 $5 Equity Earnings 7 1 Non-operational Revenue 29 28 Gain on Sale of REPs (Mutual Energy Companies) - 39 Other 38 37 ---- ---- Total Other Income 80 110 ---- ---- Other Expense: Non-operational Expenses 24 26 Other 7 18 --- ---- Total Other Expense 31 44 ---- ---- Total Other Income (Expense), Net $49 $66 ==== ==== Components of Accumulated Other Comprehensive Income (Loss) - ----------------------------------------------------------- The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income (Loss): March 31, December 31, 2004 2003 --------- ------------ Components - ---------- (in millions) Foreign Currency Translation Adjustments $118 $110 Unrealized Losses on Securities Available for Sale (1) (1) Unrealized Losses on Cash Flow Hedges (72) (94) Minimum Pension Liability (424) (441) ------ ------ Total $(379) $(426) ====== ====== We expect to reclassify approximately $59 million of net losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at March 31, 2004 to Net Income during the next twelve months at the time the hedged transactions affect net income. Five years approximates the maximum period over which an exposure to a variability in future cash flows is hedged. The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ due to market price changes. In addition, during the first quarter 2004, we reclassified $23 million from Accumulated Other Comprehensive Income (Loss) related to minimum pension liability to regulatory assets ($35 million) and deferred income taxes ($12 million) as a result of authoritative letters issued by the FERC and the Arkansas and Louisiana commissions. 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. 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 expense in our accompanying Consolidated Statements of Operations. As of March 31, 2004 and December 31, 2003, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $897 million and $845 million, respectively, of which $767 million and $720 million relating to the Cook Plant was recorded in Spent Nuclear Fuel and Decommissioning Trusts in our Consolidated Balance Sheets. The fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities for the South Texas Project totaling $130 million and $125 million as of March 31, 2004 and December 31, 2003, respectively, was classified as Assets Held for Sale in our Consolidated Balance Sheets. Reclassifications - ----------------- Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income. 2. NEW ACCOUNTING PRONOUNCEMENTS ----------------------------- FIN 46 (revised December 2003) "Consolidation of Variable Interest Entities" (FIN 46R) - ---------------------------------------------------------------------------- We implemented FIN 46R, "Consolidation of Variable Interest Entities," effective March 31, 2004 with no material impact to our financial statements. FIN 46R is a revision to FIN 46 which interprets the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FASB Staff Position No. 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003 - ------------------------------------------------------------------------------ In accordance with FASB Staff Position No. 106-1, in December 2003 we elected to defer accounting for any effects of the prescription drug subsidy under the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act) until the FASB issues authoritative guidance on the accounting for the federal subsidy. Our measurements of the accumulated postretirement benefit obligation and periodic postretirement benefit cost included in these financial statements do not reflect any potential effects of the Act. We cannot determine what impact, if any, new authoritative guidance on the accounting for the federal subsidy may have on our results of operations or financial condition. Future Accounting Changes - ------------------------- The Financial Accounting Standards Board's (FASB's) standard-setting process is ongoing and 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. The FASB is currently working on projects related to accounting for stock compensation, pension plans, property, plant and equipment, earnings per share calculations and related tax impacts. We also expect to see more projects as a result of the FASB's desire to converge International Accounting Standards with those generally accepted in the United States of America. The ultimate pronouncements resulting from these and future projects could have an impact on our future results of operations and financial position. 3. RATE MATTERS ------------ As discussed in our 2003 Annual Report, our subsidiaries are involved in rate proceedings in the FERC and several state jurisdictions. The Rate Matters note within our 2003 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material rate matters still pending, without significant changes since year-end. The following sections discuss current activities. TNC Fuel Reconciliations - ------------------------ In 2002, TNC filed with the PUCT to reconcile fuel costs, requesting 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 deferred 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 for under-recovered fuel costs as of the end of the reconciliation period. The under-recovery balance at December 31, 2001 for TNC's service within SPP was $0.7 million including interest. In March 2003, the ALJ in this proceeding filed a Proposal for Decision (PFD) with a recommendation that TNC's under-recovered retail fuel balance be reduced. In March 2003, TNC established a reserve of $13 million based on the recommendations in the PFD. In May 2003, the PUCT reversed the ALJ on certain matters and remanded TNC's final fuel reconciliation to the ALJ to consider two issues. The remand issues are the sharing of off-system sales margins from AEP's trading activities with customers 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. The PUCT proposed that the sharing of off-system sales margins for periods beyond the termination of the fuel factor should be recognized in the final fuel reconciliation proceeding. 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. While 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, an additional provision of $10 million was recorded in December 2003. On December 3, 2003, the ALJ issued a PFD in the remand phase of the TNC fuel reconciliation recommending additional disallowances for the two remand issues. TNC filed responses to the PFD and the PUCT announced a final ruling in the fuel reconciliation proceeding on January 15, 2004 accepting the PFD. TNC received a written order in March 2004 and increased the reserve by $1.5 million. In March 2004, various parties, including TNC, requested a rehearing of the PUCT's ruling. In February 2002, TNC received a final order from the PUCT in a previous fuel reconciliation covering the period July 1997 to June 2000 and reflected the order in its financial statements. This final order was appealed to the Travis County District Court. In May 2003, the District Court upheld the PUCT's final order. That order was appealed to the Third Court of Appeals. In March 2004, the Third Court of Appeals heard oral arguments. A decision is pending. TCC Fuel Reconciliation - ----------------------- In 2002, TCC filed its final fuel reconciliation with the PUCT to reconcile fuel costs to be included in its deferred over-recovery balance in the 2004 true-up proceeding. This reconciliation covers the period of July 1998 through December 2001. 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. Based on the PUCT ruling in the TNC proceeding relating to similar issues, TCC established a reserve for potential adverse rulings of $81 million during 2003. On February 3, 2004, the ALJ issued a PFD recommending that the PUCT disallow $140 million in eligible fuel costs including some new items not considered in the TNC case, and other items considered but not disallowed in the TNC ruling. Based on an analysis of the ALJ's recommendations, TCC established an additional reserve of $13 million during the first quarter of 2004. The over-recovery balance and the provisions total $163 million including interest at March 31, 2004. At this time, management is unable to predict the outcome of this proceeding. An adverse ruling from the PUCT, disallowing amounts in excess of the established reserve 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 4 "Customer Choice and Industry Restructuring." SWEPCo Texas Fuel Reconciliation - -------------------------------- In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in SPP. This reconciliation covers the period of January 2000 through December 2002. During the reconciliation period, SWEPCo incurred $435 million of Texas retail eligible fuel expense. In November 2003, intervenors and the PUCT Staff recommended fuel cost disallowances of more than $30 million. In December 2003, SWEPCo agreed to a settlement in principle with all parties in the fuel reconciliation. The settlement provides for a disallowance in fuel costs of $8 million which was recorded in December 2003. In addition, the settlement provides for the deferral as a regulatory asset of costs of a new lignite mining agreement in excess of a specified benchmark for lignite at SWEPCo's Dolet Hills Plant. The settlement provides for recovery of the deferred costs over a period ending in April 2011 as cost savings are realized under the new mining agreement. The settlement also will allow future recovery of litigation costs associated with the termination of a previous lignite mining agreement if we achieve future cost savings. In April 2004, the PUCT approved the settlement. TCC Rate Case - ------------- On June 26, 2003, the City of McAllen, Texas requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC passed similar rate review resolutions. In Texas, municipalities have original jurisdiction over rates of electric utilities within their municipal limits. Under Texas law, TCC must provide support for its rates to the municipalities. TCC filed the requested support for its rates based on a test year ending June 30, 2003 with all of its municipalities and the PUCT on November 3, 2003. TCC's proposal would decrease its wholesale transmission rates by $2 million or 2.5% and increase its retail energy delivery rates by $69 million or 19.2%. On February 9, 2004, eight intervening parties filed testimony recommending reductions to TCC's requested $67 million rate increase. The recommendations range from a decrease in existing rates of approximately $100 million to an increase in TCC's current rates of approximately $27 million. The PUCT Staff filed testimony, on February 17, 2004, recommending reductions to TCC's request of approximately $51 million. TCC's rebuttal testimony was filed on February 26, 2004. The PUCT held hearings in March 2004 and is expected to issue a decision in June 2004. Management is unable to predict the ultimate effect of this proceeding on TCC's rates or its impact on TCC's results of operations, cash flows and financial condition. Louisiana Compliance Filing - --------------------------- In October 2002, SWEPCo filed with the Louisiana Public Service Commission (LPSC) detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of their order approving the merger between AEP and CSW. The LPSC's merger order also provides that SWEPCo's base rates are capped at the present level through mid 2005. In April 2004, SWEPCo filed updated financial information with a test year ending December 31, 2003 as required by the LPSC. Both filings indicated that SWEPCo's current rates should not be reduced. If, after review of the updated information, the LPSC disagrees with our conclusion, they could order SWEPCo to file all documents for a full cost of service revenue requirement review in order to determine whether SWEPCo's capped rates should be reduced which would adversely impact results of operations and cash flows. PSO Fuel and Purchased Power - ---------------------------- PSO had a $44 million under-recovery of fuel costs resulting from a 2002 reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO filed with the Corporation Commission of the State of Oklahoma (OCC) seeking recovery of the $44 million over an 18-month period. In August 2003, the OCC Staff filed testimony recommending PSO be granted recovery of $42.4 million over three years. In September 2003, the OCC expanded the case to include a full review of PSO's 2001 fuel and purchased power practices. PSO filed its testimony in February 2004. An intervenor and the OCC Staff filed testimony in April 2004. The intervenor suggested $8.8 million related to the 2002 reallocation not be recovered from customers. The Attorney General of Oklahoma also filed a statement of position, indicating allocated trading margins were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and could more than offset the $44 million 2002 allocation. The intervenor and the OCC Staff also believed trading margins were allocated incorrectly. Under the intervenor's recalculation of margin allocation, PSO's amount of recoverable fuel would be decreased approximately $6.8 million for 2000 and $10.7 million for 2001. OCC Staff calculates the 2001 amount at $8.8 million. They also recommend recalculation of fuel for years subsequent to 2001 using the same methods. Hearings are scheduled to occur in June 2004. Management believes that fuel costs have been prudently incurred consistent with OCC rules, and that the allocation of trading margins pursuant to the agreements is correct. If the OCC determines, as a result of the review that a portion of PSO's fuel and purchased power costs should not be recovered, there will be an adverse effect on PSO's results of operations, cash flows and possibly financial condition. 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). In July 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 $31 million of RTO formation and integration costs and related carrying charges through March 31, 2004. As a result of the subsequent delay in the integration of AEP's East transmission system into PJM, FERC declined to rule, in its July 2003 order, 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 plan to apply for permission to transfer the deferred formation/integration costs to a regulatory asset prior to integration with PJM. In August 2003, the Virginia SCC filed a request for rehearing of the July 2003 order, arguing that FERC's action was an infringement on state jurisdiction, and that FERC should not have treated Alliance RTO startup costs in the same manner as PJM integration costs. On October 22, 2003, FERC denied the rehearing request. In its July 2003 order, FERC indicated that it would review the deferred costs 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 East companies' portion of the OATT at the time they join PJM. Presently, retail base rates are frozen or capped and cannot be increased for retail customers of CSPCo, I&M and OPCo. We intend to file an application 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. The AEP East companies are scheduled to join PJM in October 2004, although there are pending proceedings at the FERC and in Virginia and Kentucky concerning our integration into PJM. Therefore, 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. If the AEP East companies do not obtain regulatory approval to join PJM, we are committed to reimburse PJM for certain project implementation costs (presently estimated at $24 million for our share of the entire PJM integration project). Management intends to seek recovery of the deferred RTO formation/integration costs and project implementation cost reimbursements, if incurred. 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. In the first quarter of 2003, the state of Virginia enacted legislation preventing APCo from joining an RTO prior to July 1, 2004 and thereafter only with the approval of the Virginia SCC, but required such transfers by January 1, 2005. In January 2004, APCo filed with the Virginia SCC a cost/benefit study covering the time period through 2014 as required by the Virginia SCC. The study results show a net benefit of approximately $98 million for APCo over the 11-year study period from AEP's participation in PJM. A hearing for this proceeding is scheduled in July 2004. In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack of evidence that it would benefit Kentucky retail customers. In August 2003, KPCo sought and was granted a rehearing to submit additional evidence. In December 2003, AEP filed with the KPSC a cost/benefit study showing a net benefit of approximately $13 million for KPCo over the five-year study period from AEP's participation in PJM. In April 2004, we reached an agreement with interveners to settle the RTO issues in Kentucky. The KPSC is expected to consider the agreement in May. In September 2003, the IURC issued an order approving I&M's transfer of functional control over its transmission facilities to PJM, subject to certain conditions included in the order. The IURC's order stated that AEP shall request and the IURC shall complete a review of Alliance formation costs before any deferral of the costs for future recovery. In November 2003, the FERC issued an order preliminarily finding that AEP must fulfill its CSW merger condition to join an RTO by integrating into PJM (transmission and markets) by October 1, 2004. The order was based on PURPA 205(a), which allows FERC to exempt electric utilities from state law or regulation in certain circumstances. The FERC set several issues for public hearing before an ALJ. Those issues include whether the laws, rules, or regulations of Virginia and Kentucky are preventing AEP from joining an RTO and whether the exceptions under PURPA 205(a) apply. The FERC ALJ affirmed the FERC's preliminary findings in March 2004. FERC has not issued a final order in this matter. FERC Order on Regional Through and Out Rates - -------------------------------------------- In July 2003, the FERC issued an order directing PJM and the Midwest Independent System Operator (ISO) to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed Midwest ISO and PJM expanded regions (RTO Footprint). The elimination of the T&O rates 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 T&O rates. The FERC also found that the T&O 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 RTO Footprint. FERC initiated an investigation and hearing in regard to these rates. In November 2003, the FERC adopted a new regional rate design and directed each transmission provider to file compliance rates to eliminate T&O rates prospectively within the region and simultaneously implement new seams elimination cost allocation (SECA) rates to mitigate the lost revenues for a two-year transition period beginning April 1, 2004. The FERC was expected to implement a new rate design after the two-year period. As required by the FERC, we filed compliance tariff changes in January 2004 to eliminate the T&O charges within the RTO Footprint. Various parties raised issues with the SECA rate orders and FERC implemented settlement procedures before an ALJ. In March 2004, the FERC approved a settlement that delays elimination of T&O rates until December 1, 2004 and provides principles and procedures for a new rate design for the RTO Footprint, to be effective on December 1, 2004. The settlement also provides that if the process does not result in the implementation of a new rate design on December 1, then the SECA rates will be implemented and will remain in effect until a new rate is implemented by the FERC. If implemented, the SECA rate would not be effective beyond March 31, 2006. The AEP East companies received approximately $157 million of T&O rate revenues from transactions delivering energy to customers in the RTO Footprint for the twelve months ended December 31, 2003. At this time, management is unable to predict whether the new rate design will fully compensate the AEP East companies for their lost T&O rate revenues and, consequently, their impact on our future results of operations, cash flows and financial condition. Indiana Fuel Order - ------------------ On July 17, 2003, I&M filed a fuel adjustment clause application requesting authorization to implement the fixed fuel adjustment charge (fixed pursuant to a prior settlement of the Cook Nuclear Plant Outage) for electric service for the billing months of October 2003 through February 2004, and for approval of a new fuel cost adjustment credit for electric service to be applicable during the March 2004 billing month. The Cook settlement agreement provided for the fixed rate to end in February 2004. In another agreement in connection with a planned corporate separation I&M agreed, contingent on implementing the corporate separation, to a new freeze conditionally beginning March 2004 and continuing through December 2007. On August 27, 2003, the IURC issued an order approving the requested fixed fuel adjustment charge for October 2003 through February 2004. The order further stated that certain parties must negotiate the appropriate action on fuel after March 1, 2004. Negotiations with the parties to determine a resolution of this issue are ongoing. The IURC ordered the fixed fuel adjustment charge remain in place, on an interim basis, for March and April 2004. In April 2004, the IURC issued an order that extended the interim fuel factor for May through September 2004, subject to true-up following the resolution of issues in the corporate separation agreement. The IURC also issued an order that reopens the corporate separation docket to investigate issues related to the corporate separation agreement. Michigan 2004 Fuel Recovery Plan - -------------------------------- A Michigan Public Service Commission's (MPSC) December 16, 1999 order approved a Settlement Agreement regarding the extended outage of the Cook Plant and fixed I&M Power Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers rate areas through December 2003. In accordance with the settlement, PSCR Plan cases were not required to be filed through the 2003 plan year. As required, I&M filed its 2004 PSCR Plan with the MPSC on September 30, 2003 seeking new fuel and power supply recovery factors to be effective in 2004. A public hearing of this case occurred on March 10, 2004 and a MPSC order is expected during the second half of 2004. As allowed by Michigan law, the proposed factors were effective on January 1, 2004, subject to review and possible adjustment based on the results of the MPSC order. 4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING ------------------------------------------ As discussed in our 2003 Annual Report, we are affected by customer choice initiatives and industry restructuring. The Customer Choice and Industry Restructuring note in our 2003 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant current events related to customer choice and industry restructuring. OHIO RESTRUCTURING - ------------------ The Ohio Electric Restructuring Act of 1999 (Ohio Act) provides for a Market Development Period (MDP) during which retail customers can choose their electric power suppliers or receive Default Service at frozen generation rates from the incumbent utility. The MDP began on January 1, 2001 and is scheduled to terminate no later than December 31, 2005. The Public Utilities Commission of Ohio (PUCO) may terminate the MDP 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 MDP, 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 receive Default Service, which must be offered by the incumbent utility at market rates. On December 17, 2003, the PUCO adopted a set of rules concerning the method by which it will determine market rates for Default Service following the MDP. The rule provides for a Market Based Standard Service Offer which would be a variable rate based on a transparent forward market, daily market, and/or hourly market prices. The rule also requires a fixed-rate Competitive Bidding Process for residential and small nonresidential customers and permits a fixed-rate Competitive Bidding Process for large general service customers and other customer classes. Customers who do not switch to a competitive generation provider can choose between the Market Based Standard Service Offer or the Competitive Bidding Process. Customers who make no choice will be served pursuant to the Competitive Bidding Process. On February 9, 2004, CSPCo and OPCo filed their rate stabilization plan with the PUCO addressing rates following the end of the MDP, which ends December 31, 2005. If approved by the PUCO, rates would be established pursuant to the plan for the period from January 1, 2006 through December 31, 2008 instead of the rates discussed in the previous paragraph. The plan is intended to provide rate stability and certainty for customers, facilitate the development of a competitive retail market in Ohio, provide recovery of environmental and other costs during the plan period and improve the environmental performance of AEP's generation resources that serve Ohio customers. The plan includes annual, fixed increases in the generation component of all customers' bills (3% annually for CSPCo and 7% annually for OPCo), and the opportunity for additional generation-related increases upon PUCO review and approval. For residential customers, however, if the temporary 5% generation rate discount provided by the Ohio Act were eliminated on June 30, 2004, the fixed increases would be 1.6% for CSPCo and 5.7% for OPCo. The generation-related increases under the plan would be subject to caps. The plan would maintain distribution rates through the end of 2008 for CSPCo and OPCo at the level effective on December 31, 2005. Such rates could be adjusted for specified reasons. Transmission charges can be adjusted to reflect applicable charges approved by the FERC related to open access transmission, net congestion, and ancillary services. The plan also provides for continued recovery of transition regulatory assets and deferral of regulatory assets in 2004 and 2005 for RTO costs and carrying charges on certain required expenditures. Management cannot predict whether the plan will be approved as submitted or its impact on results of operations and cash flows. As provided in stipulation agreements approved by the PUCO in 2000, we are deferring customer choice implementation costs and related carrying costs that are in excess of $40 million. The agreements provide for the deferral of these costs as a regulatory asset until the next distribution base rate cases. The February 2004 filing provides for the continued deferral of customer choice implementation costs during the rate stabilization plan period. At March 31, 2004, we have incurred $69 million and deferred $29 million of such costs. Recovery of these regulatory assets will be subject to PUCO review in future Ohio filings for new distribution rates. If the rate stabilization plan is approved, it would defer recovery of these amounts until after the end of the rate stabilization period. Management believes that the customer choice implementation costs were prudently incurred and the deferred amounts 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 - ------------------- Texas Legislation enacted in 1999 provided the framework and timetable to allow retail electricity competition for all customers. On January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in the SPP area of Texas until at least January 1, 2007. The Texas Legislation, among other things: o provides for the recovery of regulatory assets and other stranded costs through securitization and non-bypassable wires charges; o requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility; o provides for an earnings test for each of the years 1999 through 2001 and; o provides for a 2004 true-up proceeding. See 2004 true-up proceeding discussion below. The Texas Legislation required vertically integrated utilities to legally separate their generation and retail-related assets from their transmission and distribution-related assets. Prior to 2002, TCC and TNC functionally separated their operations to comply with the Texas Legislation requirements. AEP formed new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1, 2002 (the start date of retail competition). In December 2002, AEP sold the affiliated REPs to an unaffiliated company. TEXAS 2004 TRUE-UP PROCEEDING - ----------------------------- A 2004 true-up proceeding will determine the amount and recovery of: o net stranded generation plant costs and generation-related regulatory assets (stranded costs), o a true-up of actual market prices determined through legislatively-mandated capacity auctions to the power costs used in the PUCT's excess cost over market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up), o final approved deferred fuel balance, o unrefunded accumulated excess earnings, o excess of price-to-beat revenues over market prices subject to certain conditions and limitations (retail clawback) and o other restructuring true-up items. The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up proceedings scheduling TNC's filing in May 2004 and TCC's filing in September 2004 or 60 days after the completion of the sale of TCC's generation assets, if later. Stranded Costs and Generation-Related Regulatory Assets - ------------------------------------------------------- Restructuring legislation required utilities with stranded costs to use market-based methods to value certain generation assets for determining stranded costs. TCC is the only AEP subsidiary that has stranded costs under the Texas Legislation. We have elected to use the sale of assets method to determine the market value of TCC's generation assets for stranded cost purposes. When completed, the sale of TCC's generation assets will substantially complete the required separation of generation assets from transmission and distribution assets. For purposes of the 2004 true-up proceeding, the amount of stranded costs under this market valuation methodology will be the amount by which the book value of TCC's generation 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. In December 2002, TCC filed a plan of divestiture with the PUCT seeking approval of a sales process for all of its generation facilities. In March 2003, the PUCT dismissed TCC's divestiture filing, determining that it was more appropriate to address allowable valuation methods for the nuclear asset in a rulemaking proceeding. The PUCT approved a rule, in May 2003, which allows the market value obtained by selling nuclear assets to be used in determining stranded costs. Although the PUCT declined to review TCC's proposed sale of assets process, the PUCT hired a consultant to advise the PUCT and TCC during the sale of TCC's generation assets. TCC's sale of its generation assets will be subject to a review in the 2004 true-up proceeding. In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's generation capacity in Texas. In order to sell these assets, we anticipate retiring TCC's first mortgage bonds by making open market purchases or defeasing the bonds. Bids were received for all of TCC's generation plants. In January 2004, TCC agreed to sell its 7.8% ownership interest in the Oklaunion Power Station to an unaffiliated third party for approximately $43 million. In March 2004, TCC agreed to sell its 25.2% in STP for approximately $333 million and its other coal, gas and hydro plants for approximately $430 million to unaffiliated entities. Each sale is subject to specified price adjustments. TCC sent right of first refusal notices, expiring in May and June 2004, to the co-owners of Oklaunion and STP, respectively. TCC filed for FERC approval of the sales of the fossil and hydro plants. TCC will request approval of the STP sale from the FERC during the second quarter of 2004. We have received a notice from a co-owner of Oklaunion exercising their right of first refusal; therefore, SEC approval will be required. Approval of the sale of STP from the Nuclear Regulatory Commission is required. The completion of the sales is expected to occur in 2004, subject to the rights of first refusal and the necessary approvals required for each sale. TCC will file its 2004 true-up proceeding with the PUCT after the sale of the generation assets. After the 2004 true-up proceeding, TCC may recover stranded costs and other true-up amounts through transmission and distribution rates as a competition transition and may seek to issue securitization revenue bonds for its stranded costs. The cost of the securitization bonds is recovered through transmission and distribution rates as a separate transition charge. We recorded an impairment of generation assets of $938 million in December 2003 as a regulatory asset (see Note 7). The recovery of the regulatory asset will be subject to review and approval by the PUCT as a stranded cost in the 2004 true-up proceeding. Wholesale Capacity Auction True-up - ---------------------------------- Texas Legislation also requires that electric utilities and their affiliated power generation companies (PGC) offer for sale at auction, in 2002 and 2003 and after, 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. Actual market power prices received in the state mandated auctions will be used to calculate the wholesale capacity auction true-up adjustment for TCC for the 2004 true-up proceeding. TCC recorded a $480 million regulatory asset and related revenues which represent the quantifiable amount of the wholesale capacity auction true-up for the years 2002 and 2003. In the fourth quarter of 2003, the PUCT approved a true-up filing package containing calculation instructions similar to the methodology employed by TCC to calculate the amount recorded for recovery under its wholesale capacity auction true-up. The PUCT will review the $480 million wholesale capacity auction true-up regulatory asset for recovery as part of the 2004 true-up proceeding. Fuel Balance Recoveries - ----------------------- In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to establish its deferred unrecovered fuel balance applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. In January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation case. TNC received a written order on March 1, 2004 that established TNC's unrecovered fuel balance, including interest for the ERCOT service territory, at $4.6 million. This balance will be included in TNC's 2004 true-up proceeding. Various parties, including TNC, requested rehearing of the PUCT's order. In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its deferred over-recovery of fuel balance for inclusion in the 2004 true-up proceeding. In February 2004, an ALJ issued recommendations finding a $205 million over-recovery in this fuel proceeding. Management is unable to predict the amount of TCC's fuel over-recovery which will be included in its 2004 true-up proceeding. See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 3 "Rate Matters" for further discussion. Unrefunded Excess Earnings - -------------------------- The Texas Legislation provides for the calculation of excess earnings for each year from 1999 through 2001. The total excess earnings determined for the three year period were $3 million for SWEPCo, $47 million for TCC and $19 million for TNC. TCC, TNC and SWEPCo challenged the PUCT's treatment of fuel-related deferred income taxes and appealed the PUCT's final 2000 excess earnings to the Travis County District Court which upheld the PUCT ruling. The District Court's ruling was appealed to the Third Court of Appeals. In August 2003, the Third Court of Appeals reversed the PUCT order and the District Court's judgment. The PUCT's request for rehearing of the Appeals Court's decision was denied and the PUCT chose not to appeal the ruling any further. The District Court remanded to the PUCT an appeal of the same issue from the PUCT's 2001 order to be consistent with the Court of Appeals decision. Since an expense and regulatory liability had been accrued in prior years in compliance with the PUCT orders, the companies reversed a portion of their regulatory liability for the years 2000 and 2001 consistent with the Appeals Court's decision and credited amortization expense during the third quarter of 2003. In 2001, the PUCT issued an order requiring TCC to return estimated excess earnings by reducing distribution rates by approximately $55 million plus accrued interest over a five-year period beginning January 1, 2002. Since excess earnings amounts were expensed in 1999, 2000 and 2001, the order has no additional effect on reported net income but will reduce cash flows for the five-year refund period. The amount to be refunded is recorded as a regulatory liability. Management believes that TCC will have stranded costs and that it was inappropriate for the PUCT to order a refund prior to TCC's 2004 true-up proceeding. TCC appealed the PUCT's refund of excess earnings to the Travis County District Court. That court affirmed the PUCT's decision and further ordered that the refunds be provided to customers. TCC has appealed the decision to the Court of Appeals. Retail Clawback - --------------- The Texas Legislation provides for the affiliated price-to-beat (PTB) retail electric providers (REP) serving residential and small commercial customers to refund to its T&D utility the excess of the PTB revenues over market prices (subject to certain conditions and a limitation of $150 per customer). This is the retail clawback. If, prior to January 1, 2004, 40% of the load for the residential or small commercial classes is served by competitive REPs, the retail clawback is not applicable for that class of customer. During 2003, TCC and TNC filed to notify the PUCT that competitive REPs serve over 40% of the load in the small commercial class. The PUCT approved TCC's and TNC's filings in December 2003. In 2002, AEP had accrued a regulatory liability of approximately $9 million for the small commercial retail clawback on its REP's books. When the PUCT certified that the REP's in TCC and TNC service territories had reached the 40% threshold, the regulatory liability was no longer required for the small commercial class and was reversed in December 2003. At March 31, 2004, the remaining retail clawback regulatory liability was $57 million. Stranded Cost Recovery - ---------------------- When the 2004 true-up proceeding is completed, TCC intends to file to recover PUCT-approved stranded costs and other true-up amounts that are in excess of current securitized amounts, plus appropriate carrying charges and other true-up amounts, through a non-bypassable competition transition charge in the regulated T&D rates. TCC may also seek to securitize certain of the approved stranded plant costs and regulatory assets that were not previously recovered through the non-bypassable transition charge. The annual costs of securitization are recovered through a non-bypassable rate surcharge collected by the T&D utility over the term of the securitization bonds. In the event we are unable, after the 2004 true-up proceeding, to recover all or a portion of our stranded plant costs, generation-related regulatory assets, unrecovered fuel balances, wholesale capacity auction true-up regulatory assets, other restructuring true-up items and costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. VIRGINIA RESTRUCTURING - ---------------------- In April 2004, the Governor of Virginia signed legislation which extends the transition period for electricity restructuring including capped rates through December 31, 2010. The legislation provides specified cost recovery opportunities during the capped rate period, including two general rate changes and an opportunity for recovery of incremental environmental and reliability costs. 5. COMMITMENTS AND CONTINGENCIES ----------------------------- As discussed in the Commitments and Contingencies note within our 2003 Annual Report, we continue to be involved in various legal matters. The 2003 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since our disclosure in the 2003 Annual Report. The material matters discussed in the 2003 Annual Report without significant changes in status since year-end include, but are not limited to, (1) nuclear matters, (2) construction commitments, (3) merger litigation, (4) shareholder lawsuits, (5) California lawsuits, (6) Cornerstone lawsuit, (7) Texas Commercial Energy, LLP lawsuit, (8) Bank of Montreal Claim, and (9) FERC proposed Standard Market Design. See disclosure below for significant matters with changes in status subsequent to the disclosure made in our 2003 Annual Report. ENVIRONMENTAL - ------------- Federal EPA Complaint and Notice of Violation - --------------------------------------------- The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other unaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the Clean Air Act (CAA). The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications relate to costs that were incurred at our generating units over a 20-year period. Under the CAA, 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 CAA 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. On August 7, 2003, the District Court issued a decision following a liability trial in a case pending in the Southern District of Ohio against Ohio Edison Company, an unaffiliated 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 July 2004. Management believes that the Ohio Edison decision fails to properly evaluate and apply the applicable legal standards. The facts in our 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 August 26, 2003, the District Court for the Middle District of South Carolina issued a decision on cross-motions for summary judgment prior to a liability trial in a case pending against Duke Energy Corporation, an unaffiliated utility. The District Court denied all the pending motions, but set forth the legal standards that will be applied at the trial in that case. The District Court determined that the Federal EPA bears the burden of proof on the issue of whether a practice is "routine maintenance, repair, or replacement" and on whether or not a "significant net emissions increase" results from a physical change or change in the method of operation at a utility unit. However, the Federal EPA must consider whether a practice is "routine within the relevant source category" in determining if it is "routine." Further, the Federal EPA must calculate emissions by determining first whether a change in the maximum achievable hourly emission rate occurred as a result of the change, and then must calculate any change in annual emissions holding hours of operation constant before and after the change. The Federal EPA requested reconsideration of this decision, or in the alternative, certification of an interlocutory appeal to the Fourth Circuit Court of Appeals, and the District Court denied the Federal EPA's motion. On April 13, 2004, the parties filed a joint motion for entry of final judgment, based on stipulations of relevant facts that obviated the need for a trial, but preserving plaintiffs' right to seek an appeal of the federal prevention of significant deterioration (PSD) claims. On April 14, 2004, the Court entered final judgment for Duke Energy on all of the PSD claims made in the amended complaints, and dismissed all remaining claims with prejudice. On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued an order invalidating the administrative compliance order issued by the Federal EPA to the Tennessee Valley Authority for alleged CAA 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 CAA are unconstitutional. The United States filed a petition for certiorari with the United States Supreme Court and on May 3, 2004, that petition was denied. On June 26, 2003, the United States Court of Appeals for the District of Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG), of which our 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 our 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 Circuit Court denied that motion on September 30, 2003. The central issue in these petitions concerns the lawfulness of the emissions increase test, as currently interpreted and applied by the Federal EPA in its utility enforcement actions. A decision by the D. C. Circuit Court could significantly impact further proceedings in our case. On August 27, 2003, the Administrator of the Federal EPA signed a final rule that defines "routine maintenance repair and replacement" to include "functionally equivalent equipment replacement." Under the new final rule, replacement of a component within an integrated industrial operation (defined as a "process unit") with a new component that is identical or functionally equivalent will be deemed to be a "routine replacement" if the replacement does not change any of the fundamental design parameters of the process unit, does not result in emissions in excess of any authorized limit, and does not cost more than twenty percent of the replacement cost of the process unit. The new rule is intended to have a prospective effect, and was to become effective in certain states 60 days after October 27, 2003, the date of its publication in the Federal Register, and in other states upon completion of state processes to incorporate the new rule into state law. On October 27, 2003 twelve states, the District of Columbia and several cities filed an action in the United States Court of Appeals for the District of Columbia Circuit seeking judicial review of the new rule. The UARG has intervened in this case. On December 24, 2003, the Circuit Court granted a motion from the petitioners to stay the effective date of this rule, which had been December 26, 2003. We are unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the CAA proceedings. We are also 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. If 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. In December 2000, Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with the 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. OPERATIONAL - ----------- Power Generation Facility - ------------------------- We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, own and finance a non-regulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to us. The Facility is a "qualifying cogeneration facility" for purposes of PURPA. Commercial operation of the Facility as required by the agreements between Juniper, AEP and The Dow Chemical Company (Dow) was achieved on March 18, 2004. The initial term of the lease commenced on March 18, 2004, and we may extend the lease term for up to 30 years. The lease of the Facility is reported as an owned asset under a lease financing transaction. Therefore, the asset and related liability for the debt and equity of the facility are recorded on AEP's balance sheet. Juniper is an unaffiliated limited partnership, 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 arranged to finance the Facility with debt financing up to $494 million and equity up to $31 million from investors with no relationship to AEP or any of AEP's subsidiaries. At March 31, 2004, Juniper's acquisition costs for the Facility totaled $516 million, and we estimate total costs for the completed Facility to be approximately $525 million. For the 30-year extended lease term, the majority of base lease rental is a variable rate obligation indexed to three-month LIBOR (1.11% as of March 31, 2004). Consequently, as market interest rates increase, the base rental payments under the lease will also increase. Juniper is currently planning to refinance by June 30, 2004. The Facility is collateral for the debt obligation of Juniper. An additional rental prepayment (up to $396 million) may be due on June 30, 2004 unless Juniper has refinanced its present debt financing on a long-term basis. At March 31, 2004 and December 31, 2003, we reflected $396 million as long-term debt due within one year. Our maximum required cash payment as a result of our financing transaction with Juniper is $396 million as well as interest payments during the lease term. Due to the treatment of the Facility as a financing of an owned asset, the recorded liability of $516 million is greater than our maximum possible cash payment obligation to Juniper. Dow will use a portion of the energy produced by the Facility and sell the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as non-conforming. Commercial operation for purposes of the PPA began April 2, 2004. On September 5, 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We allege that TEM has breached the PPA, and we are seeking a determination of our rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of AEP breaches. If the PPA is deemed terminated or found to be unenforceable by the court, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover claimed termination value damages from TEM. The corporate parent of TEM has provided a limited guaranty. On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the "creation of protocols" was not subject to arbitration, but did not rule upon the merits of TEM's claim that the PPA is not enforceable. On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the "Commercial Operations Date." Despite OPCo's prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo's tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for them under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo (i) was suspending performance of its obligations under PPA, (ii) would be seeking a declaration from the New York federal court that the PPA has been terminated and (iii) would be pursuing against TEM and Tractebel SA under the guaranty damages and the full termination payment value of the PPA. Enron Bankruptcy - ---------------- In 2002, certain of our subsidiaries filed claims against Enron and its subsidiaries in the bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, certain of our subsidiaries 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 from Enron remained unsettled at the date of Enron's bankruptcy. Bammel storage facility and HPL indemnification matters - In connection with the 2001 acquisition of HPL, we entered into a prepaid arrangement under which we acquired exclusive rights to use and operate the underground Bammel gas storage facility and appurtenant pipelines pursuant to an agreement with BAM Lease Company. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years. In January 2004, we filed an amended lawsuit against Enron and its subsidiaries in the U.S. Bankruptcy Court claiming that Enron did not have the right to reject the Bammel storage facility agreement or the cushion gas use agreement, described below. In April 2004, AEP and Enron entered into a settlement agreement under which we will acquire title to the Bammel gas storage facility and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF) of natural gas currently used as cushion gas for $115 million. AEP and Enron will mutually release each other from all claims associated with the Bammel facility, including our indemnity claims. The proposed settlement is subject to Bankruptcy Court approval. The parties respective trading claims and Bank of America's (BOA) purported lien on approximately 55 BCF of natural gas in the Bammel storage reservoir (as described below) are not covered by the settlement agreement. Right to use of cushion gas agreements - In connection with the 2001 acquisition of HPL, we also entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 BCF of cushion gas (10.5 BCF and 55 BCF as described in the preceeding paragraph) required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. At the time of our acquisition, Enron and the BOA Syndicate also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement. After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. In July 2002, the BOA Syndicate filed a lawsuit against HPL in the state court of Texas seeking a declaratory judgment that they have a valid and enforceable security interest in gas purportedly in the Bammel storage reservoir. In December 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows and financial condition. In October 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron's financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In February 2004, Enron, in connection with BOA's dispute, filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements. We have objected to Enron's attempted rejection of these agreements. Management is unable to predict the outcome of these proceedings or the impact on results of operations, cash flows or financial condition. Commodity trading settlement disputes - In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP's offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas related trading transactions. AEP has asserted its right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. Enron bankruptcy summary - The amount expensed in prior years in connection with the Enron bankruptcy 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. As noted above, Enron has challenged our offsetting of receivables and payables and there is a dispute regarding the cushion gas agreement. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. Energy Market Investigation - --------------------------- 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 (CFTC), 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 and 2004. On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas in violation of the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and disgorgement of benefits. The case is in the initial pleading stage with our response to the complaint currently due on May 18, 2004. Although management is unable to predict the outcome of this case, it is not expected to have a material effect on results of operations due to a provision recorded in December 2003. In January 2004, the CFTC issued a request for documents and other information in connection with a CFTC investigation of activities affecting the price of natural gas in the fall of 2003. We are responding to that request. Management cannot predict what, if any further action, any of these governmental agencies may take with respect to these matters. FERC Market Power Mitigation - ---------------------------- A FERC order issued in November 2001 on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power system's status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. AEP and two unaffiliated utilities were required to submit generation market power analyses within sixty days of the FERC's order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. Management is unable to predict the outcome of these actions by the FERC or their affect on future results of operations and cash flows. 6. GUARANTEES ---------- There are certain immaterial liabilities recorded for guarantees entered into subsequent to December 31, 2002 in accordance with FIN 45. There is no collateral held in relation to any guarantees in excess of our ownership percentages and there is no recourse to third parties in the event any guarantees are drawn unless specified below. LETTERS OF CREDIT - ----------------- We have entered into standby letters of credit (LOC) with third parties. These LOCs cover gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these LOCs were issued by us in the ordinary course of business. At March 31, 2004, the maximum future payments for all the LOCs are approximately $322 million with maturities ranging from April 2004 to January 2011. As the parent of various 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. We have guaranteed 50% of the principal and interest payments as well as 100% of a Power Purchase Agreement (PPA) of Fort Lupton, an IPP of which we are a 50% owner. In the event Fort Lupton does not make the required debt payments, we have a maximum future payment exposure of approximately $7 million, which expires May 2008. In the event Fort Lupton is unable to perform under its PPA agreement, we have a maximum future payment exposure of approximately $15 million, which expires June 2019. We will be released from this guarantee upon the anticipated sale of this IPP. See Note 7 regarding the sale of IPPs, of which Fort Lupton is included. We have guaranteed 50% of a security deposit for gas transmission as well as 50% of a Power Purchase Agreement (PPA) of Orange Cogeneration (Orange), an IPP of which we are a 50% owner. In the event Orange fails to make payments in accordance with agreements for gas transmission, we have a maximum future payment exposure of approximately $1 million, which expires June 2023. In the event Orange is unable to perform under its PPA agreement, we have a maximum future payment exposure of approximately $1 million, which expires June 2016. We will be released from this guarantee upon the anticipated sale of this IPP. See Note 7 regarding the sale of IPPs, of which Orange Cogeneration is included. GUARANTEES OF THIRD-PARTY OBLIGATIONS - ------------------------------------- CSW Energy and CSW International - -------------------------------- CSW Energy and CSW International, AEP subsidiaries, 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 $4 million, which expires June 2020. AEP Utilities - ------------- AEP Utilities guaranteed 50% of the required debt service reserve for Polk Power Partners, an 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 $5 million, which expires July 2010. We will be released from this guarantee upon the anticipated sale of this IPP. See Note 7 regarding the sale of the IPPs, of which Polk is included. SWEPCo - ------ 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 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 $51 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 March 31, 2004, 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. As of July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46. INDEMNIFICATIONS AND OTHER GUARANTEES - ------------------------------------- Contracts - --------- 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 into prior to December 31, 2002 due to the uncertainty of future events. In 2003 and during the first quarter 2004, we entered into several sale agreements. These sale agreements include indemnifications with a maximum exposure of approximately $129 million. There are no material liabilities recorded for any indemnifications entered into during 2003 or the first quarter 2004. There are no liabilities recorded for any indemnifications entered prior to December 31, 2002. Master Operating Lease - ---------------------- 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 March 31, 2004, the maximum potential loss for these lease agreements was approximately $29 million assuming the fair market value of the equipment is zero at the end of the lease term. Railcar 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. Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines over the term from approximately 86% to 77% of the projected fair market value of the equipment. At March 31, 2004, 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 terms to an unaffiliated company under an operating lease. The sublessee has recently renewed for an additional year and may renew the lease for up to three more additional one-year terms. 7. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE -------------------------------------------------------------- DISPOSITIONS COMPLETED DURING FIRST QUARTER 2004 - ------------------------------------------------ Pushan Power Plant (Investments - Other segment) - ------------------------------------------------ In the fourth quarter of 2002, we began active negotiations to sell our interest in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest partner and a purchase and sale agreement was signed in the fourth quarter of 2003. The sale was completed on March 2, 2004 for $60.7 million. An estimated pre-tax loss on disposal of $20 million pre-tax ($13 million after-tax) was recorded in December 2002, based on an indicative price expression at that time, and was classified in Discontinued Operations. The effect of the sale on the first quarter 2004 results of operations was not significant. Results of operations of Pushan have been reclassified as Discontinued Operations. The assets and liabilities of Pushan were classified on our Consolidated Balance Sheets as held for sale until the sale was complete. Beginning with our first quarter 2004 financial statements, the assets and liabilities of Pushan are shown as Assets of Discontinued Operations and Liabilities of Discontinued Operations for all periods presented. DISPOSITIONS ANNOUNCED DURING FIRST QUARTER 2004 - ------------------------------------------------ During the first quarter of 2004 we announced the following dispositions expected to close later this year: Texas Plants (Utility Operations segment) - ----------------------------------------- In December 2002, TCC filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets, including the eight gas-fired generating plants that were either deactivated or designated as "reliability must run" status. During the fourth quarter of 2003, after receiving bids from interested buyers, we recorded a $938 million impairment loss and changed the classification of the plant assets from plant in service to Assets Held for Sale. In accordance with Texas legislation, the $938 million impairment was offset by the establishment of a regulatory asset, which is expected to be recovered through a wires charge, subject to the final outcome of the 2004 Texas true-up proceeding. During early 2004 we signed agreements to sell all of our TCC generating assets, at prices which approximate book value after considering the impairment charge described above. As a result, we do not expect these pending asset sales, described below, to have a significant effect on our future results of operations. Oklaunion Power Station ----------------------- In January 2004, we signed an agreement to sell TCC's 7.8 percent share of Oklaunion Power Station for approximately $43 million, subject to closing adjustments. The planned sale is expected to close in June 2004, subject to the co-owners' decisions on their rights of first refusal. We have received notice from a co-owner of their decision to exercise their right of first refusal. South Texas Project ------------------- In February 2004, we signed an agreement to sell TCC's 25.2 percent share of the South Texas Project (STP) nuclear plant for approximately $333 million, subject to closing adjustments. We expect the sale to close in the second half of 2004, subject to the co-owners' decisions on their rights of first refusal. We do not expect the sale of this asset to have a significant effect on our results of operations. TCC Generation Assets --------------------- In March 2004 we signed an agreement to sell our remaining generating assets within TCC, including eight natural gas plants, one coal-fired plant and one hydro plant to a non-related joint venture for approximately $430 million, subject to closing adjustments. We expect the sale to close in mid-2004, subject to various regulatory approvals and clearances. LIG Pipeline and its Subsidiaries (Investments - Gas Operations segment) - ------------------------------------------------------------------------ In February 2004, we signed an agreement to sell approximately 2,000 miles of natural gas gathering and transmission pipelines in Louisiana and five gas processing facilities that straddle the system. The sale of these LIG Pipeline Company assets for $76.2 million was completed in April 2004. The effect of the sale is not expected to have a significant effect on our results of operations during second quarter 2004. See Louisiana Intrastate Gas (LIG) under Discontinued Operations for additional information. Independent Power Producers (Investments - Other segment) - --------------------------------------------------------- During the third quarter of 2003, we initiated an effort to sell four domestic Independent Power Producer (IPP) investments accounted for under the equity method (two located in Colorado and two located in Florida). In accordance with accounting principles generally accepted in the United States of America, we were required to measure the impairment of each of these four investments individually. Based on indicative bids, it was determined that an other than temporary impairment existed on two of the equity method investments located in Colorado. The $70.0 million pre-tax ($45.5 million net of tax) impairment recorded in September 2003 was the result of the measurement of fair value that was triggered by our recent decision to sell the assets. This loss of investment value was included in Investment Value Losses on our Consolidated Statements of Operations. On March 10, 2004, we entered into an agreement to sell the four domestic IPP investments for a sales price of $156 million. We expect the transaction will result in a pre-tax gain of approximately $100 million when the sale is expected to close later in 2004. This gain will be generated primarily from the sale of the two Florida IPPs which were not impaired. AEP Coal (Investments - Other segment) - -------------------------------------- In 2003, as a result of management's decision to exit our non-core businesses, we retained an advisor to facilitate the sale of AEP Coal. In March 2004, an agreement was reached to sell assets, exclusive of certain reserves and related liabilities, of the mining operations of AEP Coal. AEP received approximately $8.8 million cash and the buyer assumed an additional $10.8 million in future reclamation liability. The sale closed in April 2004 and the effect of the sale on second quarter of 2004 results of operations should not be significant. The assets and liabilities of AEP Coal that are held for sale have been included in Assets and Liabilities Held for Sale in our Consolidated Balance Sheets at March 31, 2004 and December 31, 2003. DISCONTINUED OPERATIONS - ----------------------- Management periodically assesses the overall AEP business model and makes decisions regarding our continued support and funding of our various businesses and operations. When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify the operations of those businesses or operations as discontinued operations. The assets and liabilities of these discontinued operations are classified as Assets and Liabilities Held for Sale until the time that they are sold. At the time they are sold they are reclassified to Assets and Liabilities of Discontinued Operations on the Consolidated Balance Sheets for all periods presented. Assets and liabilities that are held for sale, but do not qualify as a discontinued operations are reflected as Assets and Liabilities Held for Sale both while they are held for sale and after they have been sold, for all periods presented. Certain of our operations were determined to be discontinued operations and have been classified as such in 2004 and 2003. Results of operations of these businesses have been reclassified for the three months ended March 31, 2004 and 2003, as shown in the following table:

Assets and liabilities of discontinued operations have been reclassified as follows: Pushan Power Plant ------------ (in millions) As of December 31, 2003 Current Assets $24 Property, Plant and Equipment, Net 142 ----- Total Assets of Discontinued Operations $166 ===== Current Liabilities $26 Long-term Debt 20 Deferred Credits and Other 57 ----- Total Liabilities of Discontinued Operations $103 ===== Pushan Power Plant (Investments - Other segment) - ------------------------------------------------ See Pushan Power Plant section under Dispositions Completed During First Quarter 2004 for information regarding the sale of Pushan Power Plant. Louisiana Intrastate Gas (LIG) (Investments - Gas Operations segment) - --------------------------------------------------------------------- After announcing during 2003 that we would be divesting our non-core assets we began actively marketing LIG with the help of an investment advisor. After receiving and analyzing initial bids during the fourth quarter of 2003 we recorded a $133.9 million pre-tax ($99 million after-tax) impairment loss; of this loss, $128.9 million pre-tax relates to the impairment of goodwill and $5 million pre-tax relates to other charges. In February 2004, we signed a definitive agreement to sell the pipeline portion of LIG. The sale was completed during early April of 2004 and the impact on results of operations in the second quarter of 2004 is not expected to be significant (see LIG Pipeline and its Subsidiaries in Dispositions Announced During First Quarter 2004 for additional information). Management continues its efforts to market the remaining gas storage assets. The assets and liabilities of LIG are classified as held for sale on our Consolidated Balance Sheets and the results of operations (including the above-mentioned impairments and other related charges) are classified in Discontinued Operations in our Consolidated Statements of Operations. U.K. Generation Plants (Investments - UK Operations segment) - ------------------------------------------------------------ In December 2001, we acquired two coal-fired generation plants (U.K. Generation) in the U.K. for a cash payment of $942.3 million and assumption of certain liabilities. Subsequently and continuing through 2002, wholesale U.K. electric power prices declined sharply as a result of domestic over-capacity and static demand. External industry forecasts and our own projections made during the fourth quarter of 2002 indicated that this situation may extend many years into the future. As a result, the U.K. Generation fixed asset carrying value at year-end 2002 was substantially impaired. A December 2002 probability-weighted discounted cash flow analysis of the fair value of our U.K. Generation indicated a 2002 pre-tax impairment loss of $548.7 million ($414 million after-tax). This impairment loss is included in 2002 Discontinued Operations on our Consolidated Statements of Operations. In the fourth quarter of 2003, the U.K. generation plants were determined to be non-core assets and management engaged an investment advisor to assist in determining the best methodology to exit the U.K. business. An information memorandum was distributed for the sale of our U.K. generation plants. Based on information received, we recorded a $577 million pre-tax charge ($375 after-tax), including asset impairments of $420.7 million during the fourth quarter of 2003 to write down the value of the assets to their estimated realizable value. Additional charges of $156.7 million pre-tax were also recorded in December 2003 including $122.2 million related to the net loss on certain cash flow hedges previously recorded in Accumulated Other Comprehensive Income that has been reclassified into earnings as a result of management's determination that the hedged event is no longer probable of occurring and $34.5 million related to a first quarter 2004 sale of certain power contracts. The assets and liabilities of U.K. Generation have been classified as held for sale on our Consolidated Balance Sheets and the results of operations are included in Discontinued Operations on our Consolidated Statements of Operations. We anticipate the sale of the U.K. Generation plants during 2004. ASSETS HELD FOR SALE - -------------------- The assets and liabilities of the entities held for sale at March 31, 2004 and December 31, 2003 are as follows:

8. BENEFIT PLANS ------------- Components of Net Periodic Benefit Costs - ---------------------------------------- The following table provides the components of our net periodic benefit cost (credit) for the following plans for the three months ended March 31, 2004 and 2003:

9. 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 Investments - Gas Operations* - ----------------------------- o Gas pipeline and storage services Investments - UK Operations** - ----------------------------- o International generation of electricity for sale to wholesale customers o Coal procurement and transportation to AEP plants and third parties Investments - Other - ------------------- o Coal mining, bulk commodity barging operations and other energy supply businesses * Operations of Louisiana Intrastate Gas were classified as discontinued during 2003. ** UK Operations were classified as discontinued during 2003. The tables below present segment income statement information for the three months ended March 31, 2004 and 2003 and balance sheet information as of March 31, 2004 and December 31, 2003. These amounts include certain estimates and allocations where necessary. Prior year amounts have been reclassified to conform to the current year's presentation.

10. FINANCING ACTIVITIES -------------------- Long-term debt and other securities issuances and retirements during the first three months of 2004 are shown in the table below. Amounts in total do not necessarily tie to our statements of cash flows due to rounding and due to retirements of debt of discontinued operations not included in the amount on our statements of cash flows.

AEP GENERATING COMPANY AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS -------------------------------------------------------- Results of Operations - --------------------- Operating revenues are derived from the sale of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC approved long-term unit power agreements. The unit power agreements provide for a FERC approved rate of return on common equity, a return on other capital (net of temporary cash investments) and recovery of costs including operation and maintenance, fuel and taxes. First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Net Income increased $31 thousand for the first quarter of 2004 compared with the first quarter of 2003. The fluctuations in Net Income are a result of terms in the unit power agreements which allow for the return on total capital of the Rockport Plant calculated and adjusted monthly. Operating Income - ---------------- Operating Income decreased $304 thousand for the first quarter of 2004 compared with the first quarter of 2003 primarily due to: o A $5 million decrease in Operating Revenue as a result of decreased recoverable expenses, primarily Fuel for Electric Generation, in accordance with the unit power agreements along with a decreased return on total capital. o A $4 million increase in Maintenance expense as a result of planned outages. In the first quarter of 2004, we incurred planned outages related to boiler inspections. The decrease in Operating Income was offset by: o A $9 million decrease in Fuel for Electric Generation expense. This decrease is primarily due to a 30% decrease in MWH generation as a result of the planned outages. Off-balance Sheet Arrangements - ------------------------------ We enter into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. Our off-balance sheet arrangement has not changed significantly from year-end 2003 and is comprised of a sale and leaseback transaction entered into by AEGCo and I&M with an unrelated unconsolidated trustee. Our current plans limit the use of off-balance sheet financing entities or structures, except for traditional operating lease arrangements and sales of customer accounts receivable that are entered into in the normal course of business. For complete information on this off-balance sheet arrangement see "Off-balance Sheet Arrangements" in "Management's Narrative Financial Discussion and Analysis" section of our 2003 Annual Report. Significant Factors - ------------------- See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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.

AEP GENERATING COMPANY INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to AEGCo's financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to AEGCo. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Commitments and Contingencies Note 5 Guarantees Note 6 Business Segments Note 9 Financing Activities Note 10 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS ---------------------------------------------- Results of Operations - --------------------- Net Income decreased $35 million for 2004 due mainly to the cessation of the recognition of non-cash earnings related to legislatively mandated capacity auction sales and regulatory assets established in Texas of $36 million, net of tax. First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Operating Income - ---------------- Operating Income decreased $37 million primarily due to: o Decreased Revenues associated with establishing regulatory assets in Texas of $56 million in 2003 (see "Texas Restructuring" in Note 4). These revenues did not continue after 2003. o Decreased off-system sales, including those to REPs, of $78 million due mainly to lower KWH sales of 31% and a small decrease in the overall average price per KWH. o Decreased revenues from ERCOT for various services, including balancing energy, which declined $14 million. o Decreased retail wires revenues of $2 million driven by a 6% decrease in degree-days, offset in part by a 5% increase in the average price per KWH. o Decreased Reliability Must Run revenues from ERCOT of $5 million which includes both fuel recovery and a fixed cost component decrease of $2 million. o Decreased fees of $6 million for services we provided to others as their Qualified Scheduling Entity (QSE) due mainly to certain REPs no longer using TCC as their QSE in 2004. o Increased Other Operation expenses of $8 million due mainly to $5 million of increased ERCOT related transmission expense and higher affiliated ancillary services, as well as an increase of $1 million for emission allowance expense. The decrease in Operating Income was partially offset by: o Increases resulting from risk management activities. o Net decreases in fuel and purchased electricity on a combined basis of $72 million. KWH purchased decreased 87% while the cost per KWH decreased 19%. Although the KWH generated increased 23%, fuel costs decreased 4% attributable mostly to larger amounts of fuel oil burned in 2003. o Decreased provisions for rate refunds of $14 million due to 2003 Texas fuel issues (see "TCC Fuel Reconciliation" in Note 3). o Increased transmission revenue of $10 million due to prior year adjustments for affiliated OATT and ancillary services resulting from revised data received from ERCOT for the years 2001-2003. o Decreased Depreciation and Amortization expense of $17 million due mainly to the cessation of depreciation on Texas generation plants classified as "Held For Sale." o Decreased Income Taxes of $22 million due primarily to a decrease in pre-tax operating book income. Other Impacts on Earnings - ------------------------- Nonoperating Income increased $2 million due mainly to risk management activities. Interest Charges increased $1 million due primarily to financing activities in 2003 that resulted in an increase in long-term debt outstanding. Financial Condition - ------------------- Credit Ratings The rating agencies currently have us 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- Cash Flow - --------- Cash flows for the three months ended March 31, 2004 and 2003 were as follows: 2004 2003 ---- ---- (in thousands) Cash and cash equivalents at beginning of period $65,882 $85,420 -------- -------- Cash flow from (used for): Operating activities 26,247 50,752 Investing activities (24,122) (21,851) Financing activities (29,182) (81,525) -------- -------- Net decrease in cash and cash equivalents (27,057) (52,624) -------- -------- Cash and cash equivalents at end of period $38,825 $32,796 ======== ======== Operating Activities - -------------------- Cash Flow From Operating Activities in 2004 was $26 million primarily due to Net Income, as explained above, and Taxes Accrued, offset in part by Deferred Property Tax, Accounts Payable and Interest Accrued. Investing Activities - -------------------- Investing expenditures in 2004 were $24 million due primarily to construction expenditures focused on improved service reliability projects for transmission and distribution systems. Financing Activities - -------------------- Cash Used For Financing Activities in 2004 reduced Long-term Debt, paid dividends and was partially offset by Advances to Affiliates. Financing Activity - ------------------ Long-term debt issuances and retirements during the first three months of 2004 were: Issuances --------- None Retirements ----------- Principal Interest Due Type of Debt Amount Rate Date ------------ --------- -------- ---- (in thousands) (%) First Mortgage Bonds $1,055 7.125 2005 Securitization Bonds 28,809 3.540 2005 Significant Factors - ------------------- We made progress on our planned divestiture of certain Texas generation assets by (1) announcing in January 2004 that we had signed an agreement to sell our 7.8% share of the Oklaunion Power Station for approximately $43 million, subject to closing adjustments, (2) announcing in February 2004 that we had signed an agreement to sell our 25.2% share of the South Texas Project nuclear plant for approximately $333 million, subject to closing adjustments, and (3) announcing in March 2004 that we had signed an agreement to sell our remaining generating assets, including eight natural gas plants, one coal-fired plant and one hydro plant for approximately $430 million, subject to closing adjustments. Subject to certain co-owners' rights of first refusal, we expect all of our announced sales to close before the end of 2004, after receiving appropriate regulatory approvals and clearances. We will file with the Public Utility Commission of Texas to recover net stranded costs associated with each of the sales pursuant to Texas restructuring legislation. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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 - ------------ Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Quantitative and Qualitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect. MTM Risk Management Contract Net Liabilities - -------------------------------------------- This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. MTM Risk Management Contract Net Liabilities Three Months Ended March 31, 2004 (in thousands) Total MTM Risk Management Contract Net Assets at December 31, 2003 $11,942 (Gain) Loss from Contracts Realized/Settled During the Period (a) (1,889) Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) 79 Change in Fair Value Due to Valuation Methodology Changes - Changes in Fair Value of Risk Management Contracts (d) (3,226) Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) - --------- Total MTM Risk Management Contract Net Assets 6,906 Net Cash Flow Hedge Contracts (f) (24,225) --------- Total MTM Risk Management Contract Net Liabilities at March 31, 2004 $(17,319) ========= (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized risk management contracts and related derivatives that settled during 2004 that were entered into prior to 2004. (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 2004. 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 2004. (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. (f)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss). 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" is in 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. (c)Amounts exclude Cash Flow Hedges. 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. Under SFAS 133 only contracts designated as cash flow hedges are recorded in AOCI, therefore, the table does not provide a full picture of our hedging activity. In accordance with GAAP, all amounts are presented net of related income taxes. Total Accumulated Other Comprehensive Income (Loss) Activity Three Months Ended March 31, 2004 Power ----- (in thousands) Beginning Balance December 31, 2003 $(1,828) Changes in Fair Value (a) (13,601) Reclassifications from AOCI to Net Income (b) (162) --------- Ending Balance March 31, 2004 $(15,591) ========= (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 AOCI 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 AOCI expected to be reclassified to earnings during the next twelve months is a $15,478 thousand loss. Credit Risk - ----------- Our counterparty credit quality and exposure is generally consistent with that of AEP. VaR Associated with Management Contracts The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated: Three Months Ended Twelve Months Ended March 31, 2004 December 31, 2003 ------------------------- ------------------------- (in thousands) (in thousands) End High Average Low End High Average Low --- ---- ------- --- --- ---- ------- --- $51 $160 $88 $45 $189 $733 $307 $73 VaR Associated with Debt Outstanding - ------------------------------------ The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $179 million and $206 million at March 31, 2004 and December 31, 2003, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS ------------------------------------------------- The notes to TCC's consolidated financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to TCC. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Rate Matters Note 3 Customer Choice and Industry Restructuring Note 4 Commitments and Contingencies Note 5 Guarantees Note 6 Assets Held for Sale Note 7 Benefit Plans Note 8 Business Segments Note 9 Financing Activities Note 10 AEP TEXAS NORTH COMPANY AEP TEXAS NORTH COMPANY MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS -------------------------------------------------------- Results of Operations - --------------------- Net Income increased $3 million for 2004 due mainly to reduced provisions for refunds of $8 million, net of tax, offset in part by the Cumulative Effect of Accounting Changes of $3 million recorded in 2003. First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Operating Income - ---------------- Operating Income increased by $7 million primarily due to: o Increased Reliability Must Run revenues from ERCOT of $6 million, which include both fuel recovery and a fixed cost component. o Decreased fuel and purchased electricity on a combined basis of $21 million. KWH generation decreased 3%, while the per-unit cost of fuel increased 10% due primarily to increases in the per-unit cost of natural gas. KWH purchased declined 53%, and the average cost per KWH purchased decreased 23%. o Decreased provision for rate refunds of $12 million due to fewer Texas fuel issues in 2003 (see "TNC Fuel Reconciliation" in Note 3). o Increased Transmission revenue of $7 million, due mainly to prior year adjustments for affiliated OATT and ancillary services resulting from revised data received from ERCOT for the years 2001-2003. o Reduced Taxes Other Than Income Taxes of $1 million resulting mainly from lower accrued property taxes. The increase in Operating Income was partially offset by: o Decreased off-system sales, including those to retail electric providers, of $27 million due mainly to lower KWH sales of 31% and a small decrease in the overall average price per KWH. o Revenues from ERCOT decreased $5 million for various services, including balancing energy, due mainly to prior years' adjustments made by ERCOT. o Reduced wholesale revenues of $1 million due to the loss of several large wholesale customers whose contracts expired and were not renewed. o Decreases from risk management activities. o Increased Income Taxes of $2 million due primarily to an increase in pre-tax operating book income. Other Impacts on Earnings - ------------------------- Interest Charges increased $2 million primarily as a result of refinancing in the first quarter of 2003, reflecting one month of interest charges as compared to three months of related interest for 2004. The Cumulative Effect of Accounting Changes is due to a one-time after-tax impact of adopting SFAS 143 in 2003. Financial Condition - ------------------- Credit Ratings - -------------- The rating agencies currently have us 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- Financing Activity - ------------------ Long-term debt issuances and retirements during the first three months of 2004 were: Issuances --------- None Retirements ----------- Principal Interest Due Type of Debt Amount Rate Date ------------ --------- -------- ---- (in thousands) (%) First Mortgage Bonds $24,036 6.125 2004 Significant Factors - ------------------- See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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 - ------------ Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Quantitative and Qualitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effects. MTM Risk Management Contract Net Liabilities - -------------------------------------------- This table provides detail on changes in our 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 risk management contracts and related derivatives that settled during 2004 that were entered into prior to 2004. (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 2004. 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 2004. (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. (f)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss). 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" is in 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. (c)Amounts exclude Cash Flow Hedges. 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. Under SFAS 133 only contracts designated as cash flow hedges are recorded in AOCI, therefore, the table does not provide a full picture of our hedging activity. In accordance with GAAP, all amounts are presented net of related income taxes. Total Accumulated Other Comprehensive Income (Loss) Activity Three Months Ended March 31, 2004 Power ----- (in thousands) Beginning Balance December 31, 2003 $(601) Changes in Fair Value (a) (4,555) Reclassifications from AOCI to Net Income (b) (55) -------- Ending Balance March 31, 2004 $(5,211) ======== (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 AOCI 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 AOCI expected to be reclassified to earnings during the next twelve months is a $5,166 thousand loss. Credit Risk - ----------- Our counterparty credit quality and exposure is generally consistent with that of AEP. VaR Associated with Risk Management Contracts - --------------------------------------------- The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated: Three Months Ended Twelve Months Ended March 31, 2004 December 31, 2003 ------------------------- ------------------------- (in thousands) (in thousands) End High Average Low End High Average Low --- ---- ------- --- --- ---- ------- --- $20 $64 $35 $18 $76 $294 $123 $29 VaR Associated with Debt Outstanding - ------------------------------------ The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $28 million and $33 million at March 31, 2004 and December 31, 2003, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or financial position.

AEP TEXAS NORTH COMPANY INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to TNC's financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to TNC. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Rate Matters Note 3 Customer Choice and Industry Restructuring Note 4 Commitments and Contingencies Note 5 Guarantees Note 6 Benefit Plans Note 8 Business Segments Note 9 Financing Activities Note 10 APPALACHIAN POWER COMPANY AND SUBSIDIARIES APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS ---------------------------------------------- Results of Operations - --------------------- Net Income for the first quarter of 2004 decreased $92 million from the prior year period primarily due to the Cumulative Effect of Accounting Changes of $77 million recorded in 2003 and an increase in Depreciation and Amortization expense of $12 million over the first quarter of 2003. First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Operating Income - ---------------- Operating Income for 2004 decreased by $26 million from 2003 primarily due to the following: o An $11 million decrease in revenues from risk management activities included in Operating Income. o A decrease of $3 million in Sales to AEP Affiliates due to decreased power available for sale caused by planned plant outages in the first quarter of 2004. o An increase in Depreciation and Amortization expense of $12 million primarily due to reduced expense in 2003 attributable to the adoption of SFAS 143 for regulated operations and to a lesser degree, due to a greater depreciable base in 2004 which included the addition of capitalized software costs. o An increase in Maintenance expense of $9 million primarily due to planned maintenance at Amos and Kanawha River Plants relating to scheduled outages in 2004. o An increase in Other Operation expense of $7 million primarily due to higher employee-related expenses in the first quarter of 2004. o A $9 million increase in purchased power essentially offset by decreased fuel expenses as purchased power was used to offset decreased generation resulting from the planned plant outages in 2004. The decrease in Operating Income for 2004 was partially offset by: o An increase in off-system sales and transmission revenues totaling $4 million. o A decrease in Income Taxes of $9 million due to the decrease in pre-tax book operating income in 2004. Other Impacts on Earnings - ------------------------- Nonoperating income increased $10 million in the first quarter of 2004 compared to 2003 primarily due to reduced losses from risk management activities resulting from AEP's plan to exit risk management activities in areas outside of its traditional market area. The increase in nonoperating income was partially offset by a $3 million increase in nonoperating income taxes resulting from an increase in pre-tax nonoperating book income. Interest charges decreased $4 million in the first quarter of 2004 from the prior year period due to lower debt levels and reduced interest rates and increased Allowance for Funds Used During Construction in 2004. Cumulative Effect of Accounting Changes - --------------------------------------- The Cumulative Effect of Accounting Changes of $77 million is due to the implementation of SFAS 143 and EITF 02-3 in 2003. 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+ Cash Flow - --------- Cash flows for the three months ended March 31, 2004 and 2003 were as follows: 2004 2003 ---- ---- (in thousands) Cash and cash equivalents at beginning of period $45,881 $4,285 --------- --------- Cash flow from (used for): Operating activities 182,058 220,018 Investing activities (91,039) (54,363) Financing activities (131,630) (159,491) --------- --------- Net increase (decrease) in cash and cash equivalents (40,611) 6,164 --------- --------- Cash and cash equivalents at end of period $5,270 $10,449 ========= ========= Operating Activities - -------------------- Cash Flows From Operating Activities in the first quarter of 2004 were $182 million primarily due to Net Income and changes in Accounts Receivable and accrued expenses. Investing Activities - -------------------- Construction expenditures in 2004 versus 2003 increased $34 million. The current year expenditures of $91 million were focused primarily on projects to improve service reliability for transmission and distribution, as well as environmental upgrades. Financing Activities - -------------------- In 2004, we retired $40 million of Installment Purchase Contracts, paid $25 million in dividends and repaid $66 million of Advances from Affiliates. Financing Activity - ------------------ Long-term debt issuances and retirements during the first quarter of 2004 were: Issuances --------- None. Retirements ----------- Principal Interest Due Type of Debt Amount Rate Date ------------ --------- -------- ---- (in thousands) (%) Installment Purchase Contracts $40,000 5.45 2019 Significant Factors - ------------------- See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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 - ------------ Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Quantitative and Qualitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect on this specific registrant. 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.

(a) "(Gain) Loss from Contracts Realized/Settled During the Period" includes realized risk management contracts and related derivatives that settled during 2004 that were entered into prior to 2004. (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 2004. 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 2004. (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. (f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss). (g) See Note 17 "Related Party Transactions" in the 2003 Annual Report. 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 AOCI 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 AOCI expected to be reclassified to earnings during the next twelve months is a $1,630 thousand loss. Credit Risk - ----------- Our counterparty credit quality and exposure is generally consistent with that of AEP. VaR Associated with Risk Management Contracts - --------------------------------------------- The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated: Three Months Ended Twelve Months Ended March 31, 2004 December 31, 2003 ------------------------- ------------------------- (in thousands) (in thousands) End High Average Low End High Average Low --- ---- ------- --- --- ---- ------- --- $672 $2,123 $1,162 $590 $596 $2,314 $969 $230 VaR Associated with Debt Outstanding - ------------------------------------ The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $86 million and $102 million at March 31, 2004 and December 31, 2003, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to APCo's consolidated financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to APCo. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Rate Matters Note 3 Customer Choice and Industry Restructuring Note 4 Commitments and Contingencies Note 5 Guarantees Note 6 Benefit Plans Note 8 Business Segments Note 9 Financing Activities Note 10 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS -------------------------------------------------------- Results of Operations - --------------------- First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- The decrease in Net Income of $21 million in 2004 compared to 2003 was primarily due to a $27 million net-of-tax Cumulative Effect of Accounting Changes in the first quarter of 2003, a $3 million increase in Depreciation and Amortization expense and a $6 million increase in Nonoperating Income Taxes, which was offset by a $3 million increase in total operating revenues and a $12 million increase in nonoperating income associated with risk management activities. Operating Income - ---------------- Operating Income decreased $1 million primarily due to: o A decrease of $3 million in wholesale sales to municipal customers as the result of the expiration of the final municipal contract at the end of 2003. o A decrease of $1 million in sales for resale to affiliated companies due to lower price realizations during 2004. o A decrease of $2 million in operating revenues relating to risk management activities as a result of lower volumes. o An increase of $2 million in Maintenance expense due primarily to boiler overhaul work from scheduled and forced outages. o An increase of $3 million in Depreciation and Amortization expense as a result of a greater depreciable base in 2004, including capital software costs and the increased amortization of regulatory assets due to a federal tax adjustment, which increased the regulatory asset amount, and a corresponding quarterly adjustment to the amortization amount. The decrease in Operating Income was partially offset by: o An increase of $9 million in retail electric revenues primarily due to growth in the residential and commercial customer base and increased KWH usage per customer in the first quarter of 2004. o A decrease of $1 million in Income Taxes due to a decrease in pre-tax operating book income. Other Impacts on Earnings - ------------------------- Nonoperating Income increased $12 million primarily due to favorable results from risk management activities in the first quarter of 2004 compared to losses that were recorded in the first quarter of 2003. Nonoperating Income Tax increased $6 million due to an increase 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. 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- Financing Activity - ------------------ There were no long-term debt issuances or retirements in the first three months of 2004. Significant Factors - ------------------- See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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 - ------------ Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Quantitative and Qualitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect on this specific registrant. 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.

(a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized risk management contracts and related derivatives that settled during 2004 that were entered into prior to 2004. (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 2004. 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 2004. (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. (f)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss). (g) See Note 17 "Related Party Transactions" in the 2003 Annual Report. 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. (c) Amounts exclude Cash Flow Hedges. 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. Under SFAS 133 only contracts designated as cash flow hedges are recorded in AOCI, therefore, the table does not provide a full picture of our hedging activity. In accordance with GAAP, all amounts are presented net of related income taxes. Total Accumulated Other Comprehensive Income (Loss) Activity Three Months Ended March 31, 2004 Power ----- (in thousands) Beginning Balance December 31, 2003 $202 Changes in Fair Value (a) (1,745) Reclassifications from AOCI to Net Income (b) (165) ---------- Ending Balance March 31, 2004 $(1,708) ======== (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 AOCI 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 AOCI expected to be reclassified to earnings during the next twelve months is a $790 thousand loss. Credit Risk - ----------- Our counterparty credit quality and exposure is generally consistent with that of AEP. VaR Associated with Energy and Gas Risk Management Contracts - ------------------------------------------------------------ The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated: Three Months Ended Twelve Months Ended March 31, 2004 December 31, 2003 ------------------------- ------------------------- (in thousands) (in thousands) End High Average Low End High Average Low --- ---- ------- --- --- ---- ------- --- $413 $1,305 $714 $363 $336 $1,303 $546 $130 VaR Associated with Debt Outstanding - ------------------------------------ The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $86 million and $98 million at March 31, 2004 and December 31, 2003, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to CSPCo's consolidated financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to CSPCo. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Rate Matters Note 3 Customer Choice and Industry Restructuring Note 4 Commitments and Contingencies Note 5 Guarantees Note 6 Benefit Plans Note 8 Business Segments Note 9 Financing Activities Note 10 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS ----------------------------------------------- Results of Operations - --------------------- During 2004, Net Income increased $15 million including an unfavorable $3 million Cumulative Effect of Accounting Change in 2003. During 2004, Net Income Before Cumulative Effect of Accounting Change increased $12 million due to reduced financing costs and an improvement in margins on nonoperating risk management activities. First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Operating Income - ---------------- Operating Income decreased $3 million primarily due to: o Decreased Sales to AEP Affiliates of $11 million due to declines in the price and volume of sales to the AEP Power Pool reflecting lower demand for electricity and lower capacity revenues. o Increased Maintenance expense of $7 million due primarily to the cost of a planned maintenance outage at one unit of Rockport Plant and increased cost of overhead lines and their right-of-way maintenance. o Increased Income Tax expense of $3 million reflecting an increase in pre-tax operating income. The decrease in Operating Income was partially offset by: o Increased retail revenues of $7 million due primarily to an improvement in industrial sales reflecting the recovery of the economy and the end of amortization for Cook outage settlements. o Decreased Fuel for Electric Generation expense of $9 million reflecting a change in fuel mix as nuclear generation increased 21% and coal-fired generation declined 22% due to generating unit availability. o Decreased Taxes Other Than Income Taxes of $2 million primarily due to decreased Federal Insurance Contributions Act taxes reflecting a reduction in employees from the sustained earnings improvement initiative and timing of payroll accrual. Other Impacts on Earnings - ------------------------- Nonoperating Income increased $14 million primarily due to improved risk management activities. Nonoperating Income Taxes increased $6 million reflecting the increase in pre-tax nonoperating income. Interest Charges decreased $6 million primarily due to a reduction in outstanding long-term debt of $255 million which was retired in May 2003 using lower rate short-term debt, maturity of $30 million first mortgage bonds in November 2003 and the refinancing of $65 million installment purchase contracts at lower interest rates. Cumulative Effect of Accounting Change - -------------------------------------- The Cumulative Effect of Accounting Change is due to the implementation of the requirements of EITF 02-3 related to mark-to-market accounting for risk management contracts that are not derivatives. 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 Cash Flow - ---------

Operating Activities - -------------------- Operating activities during 2004 provided $103 million more cash than during 2003 largely due to increased net income of $15 million and improved working capital requirements. Investing Activities - -------------------- Cash flows Used For Investing Activities during 2004 were $8 million higher than 2003 primarily due to increased construction expenditures. Construction expenditures for transmission and distribution assets were incurred to upgrade or replace equipment and improve reliability. Financing Activities - -------------------- Financing activities for 2004 used $99 million more cash from operations than during 2003 primarily to reduce short-term debt outstanding and pay common dividends. Financing Activity - ------------------ There were no long-term debt issuances or retirements during the first three months of 2004. Off-Balance Sheet Arrangements - ------------------------------ We enter into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. Our off-balance sheet arrangement has not changed significantly from year-end 2003 and is comprised of a sale and leaseback transaction entered into by AEGCo and I&M with an unrelated unconsolidated trustee. Our current plans limit the use of off-balance sheet financing entities or structures, except for traditional operating lease arrangements and sales of customer accounts receivable that are entered into in the normal course of business. For complete information on this off-balance sheet arrangement see "Off-balance Sheet Arrangements" in "Management's Financial Discussion and Analysis" section of our 2003 Annual Report. Significant Factors - ------------------- See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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 - ------------ Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Quantitative and Qualitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect on this specific registrant. 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.

(a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized risk management contracts and related derivatives that settled during 2004 that were entered into prior to 2004. (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 2004. 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 2004. (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. (f)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss). (g)See Note 17 "Related Party Transactions" in the 2003 Annual Report. 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" is in 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. (c) Amounts exclude Cash Flow Hedges. 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. Under SFAS 133 only contracts designated as cash flow hedges are recorded in AOCI, therefore, the table does not provide a full picture of our hedging activity. In accordance with GAAP, all amounts are presented net of related income taxes.

VaR Associated with Debt Outstanding - ------------------------------------ The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $61 million and $79 million at March 31, 2004 and December 31, 2003, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to I&M's consolidated financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to I&M. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Rate Matters Note 3 Customer Choice and Industry Restructuring Note 4 Commitments and Contingencies Note 5 Guarantees Note 6 Benefit Plans Note 8 Business Segments Note 9 Financing Activities Note 10 KENTUCKY POWER COMPANY KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS -------------------------------------------------------- Results of Operations - --------------------- First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Net Income for the first quarter of 2004 increased $2 million over the first quarter of 2003 primarily due to reduced losses on risk management activities, partially offset by the Cumulative Effect of Accounting Change recorded in 2003. Operating Income - ---------------- Operating Income for 2004 decreased $1 million primarily due to: o A decrease in Sales to AEP Affiliates of $2 million due to a decline in available power caused by a planned plant outage at Rockport Unit 2 in early February through March of 2004. Our share of Rockport's generation was down 30% in the first quarter of 2004 compared to 2003. o Fuel expense was up $3 million over 2003 due to increased generation based on increased plant availability at Big Sandy in 2004 resulting from unplanned outages at Big Sandy in 2003. o An increase in Depreciation and Amortization of $2 million in 2004 due to the implementation of emission control equipment at the Big Sandy plant in mid 2003. o A $1 million increase in Other Operation expense primarily due to increased employee-related expenses in 2004. o A $1 million decrease in gains from risk management activities included in Operating Income. The decreases in Operating Income were partially offset by: o An increase in retail revenues of $2 million over 2003 due to the rate increase in mid 2003 to recover the cost of emission control equipment. o An increase in off-system sales and transmission revenues of $1 million. o A decrease in Purchased Electricity from AEP Affiliates of $4 million due to increased purchases in 2003 driven by unplanned outages at the Big Sandy plant in 2003. In addition, energy purchases decreased from the Rockport Plant due to the planned outage at Rockport Unit 2 discussed above. Our energy purchases from Rockport are 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. Other Impacts on Earnings - ------------------------- Nonoperating Income (Loss) increased $3 million in the first quarter of 2004 compared to 2003 primarily due to favorable results from risk management activities for power sold outside AEP's traditional marketing area resulting from AEP's plan to exit risk management activities in areas outside of its traditional market area. Nonoperating Expenses increased $1 million due to a loss on the sale of land associated with the Ashland general office building in the first quarter of 2004. Interest Charges increased $1 million primarily due to reduced allowance for funds used during construction in 2004 resulting from the completion of the emission control equipment in mid 2003. Financial Condition - ------------------- Credit Ratings - -------------- The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch ------- --- ----- Senior Unsecured Debt Baa2 BBB BBB Financing Activity - ------------------ There were no long-term debt issuances or retirements during the first three months of 2004. Significant Factors - ------------------- See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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 - ------------ Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Quantitative and Qualitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect on this specific registrant. 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.

(a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized risk management contracts and related derivatives that settled during 2004 that were entered into prior to 2004. (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 2004. 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 2004. (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. (f)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss). (g)See Note 17 "Related Party Transactions" in the 2003 Annual Report. 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.

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. Under SFAS 133 only contracts designated as cash flow hedges are recorded in AOCI, therefore, the table does not provide a full picture of our hedging activity. In accordance with GAAP, all amounts are presented net of related income taxes.

Credit Risk - ----------- Our counterparty credit quality and exposure is generally consistent with that of AEP. VaR Associated with Risk Management Contracts - --------------------------------------------- The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

VaR Associated with Debt Outstanding - ------------------------------------ The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $23 million and $29 million at March 31, 2004 and December 31, 2003, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or financial position.

KENTUCKY POWER COMPANY INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to KPCo's financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to KPCo. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Rate Matters Note 3 Commitments and Contingencies Note 5 Guarantees Note 6 Benefit Plans Note 8 Business Segments Note 9 Financing Activities Note 10 OHIO POWER COMPANY CONSOLIDATED OHIO POWER COMPANY CONSOLIDATED MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS ---------------------------------------------- Results of Operations - --------------------- Effective July 1, 2003, we consolidated JMG Funding, LP (JMG) as a result of the implementation of FIN 46. OPCo now records the depreciation, interest and other operating expenses of JMG and eliminates JMG's revenues against OPCo's operating lease expenses. While there was no effect to net income as a result of consolidation, some individual income statement captions were affected. Net Income decreased $114 million primarily due to a $125 million Cumulative Effect of Accounting Changes in the first quarter of 2003. Income Before Cumulative Effect increased $11 million primarily due to an increase in risk management income. First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Operating Income - ---------------- Operating Income increased $9 million for the three months ended March 31, 2004 compared with the three months ended March 31, 2003 due to: o A $7 million increase in retail revenue primarily due to growth in the residential and commercial customer base. o A $7 million increase in Sales to AEP Affiliates. The increase is primarily the result of a 19.0% increase in MWH for affiliated system sales partially offset by lower price realizations for this year. In addition, the increase in Sales to AEP Affiliates is also the result of optimizing our generation capacity and selling our excess generated power to the AEP Power Pool. o A $7 million decrease in Purchased Electricity for Resale. This decrease was primarily due to cessation of the Buckeye Transmission agreement on June 30, 2003. Prior to this date, Ohio Edison interchange expenses were recorded in Purchased Electricity for Resale. An associated offsetting decrease in Ohio Edison revenue occurred in non-affiliated sales for resale; therefore, there was no effect to net income. In addition, the DOE Settlement Capacity Surcharge, which was included in rates for the first quarter of 2003, was no longer in effect for 2004. o A $19 million decrease in Income Taxes. This decrease was primarily due to a decrease in pre-tax operating book income and tax adjustments recorded in 2003. The increase in Operating Income was partially offset by: o A $7 million decrease in non-affiliated sales for resale primarily as a result of a 13.4% decrease in MWH sales. In addition, there were no Ohio Edison interchange revenues recorded during 2004 as a result of the cessation of the Buckeye Transmission agreement discussed above with no effect to net income as a result of the cessation. o A $13 million increase in Fuel for Electric Generation due to a 9.7% increase in the number of tons consumed during the first quarter of 2004. In addition, generation increased 11.1% from the first quarter of 2003 to the first quarter of 2004. o A $10 million increase in Depreciation and Amortization primarily associated with the OPCo consolidation of JMG. Depreciation expense related to the assets owned by JMG are now consolidated with OPCo (there was no change in overall net income due to the consolidation of JMG). In addition, the increase is a result of a greater depreciable base in 2004, including capitalized software costs and the increased amortization of regulatory assets due to a federal tax adjustment which increased the regulatory asset amount and a corresponding quarterly adjustment to the amortization amount. Other Impacts of Earnings - ------------------------- Nonoperating Income increased $20 million primarily due to favorable results from risk management activities in the first quarter of 2004 compared to losses that were incurred in the first quarter of 2003. Nonoperating Income Tax Expense (Credit) increased $10 million as a result of an increase in pre-tax nonoperating book income. Interest charges increased $11 million due primarily to the consolidation of JMG and its associated debt along with replacement of lower cost floating-rate short-term debt with higher cost fixed-rate long-term debt (there was no change in overall net income due to the consolidation of JMG). Cumulative Effect of Accounting Changes - --------------------------------------- The Cumulative Effect of Accounting Changes during 2003 was due to the one-time after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3. 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+ Cash Flow - --------- Cash flows for the three months ended March 31, 2004 and 2003 were as follows:

Operating Activities - -------------------- Cash Flows From Operating Activities for the first quarter of 2004 increased $90 million compared to the first quarter of 2003. This is primarily due to significant reductions in Accounts Payable balances during the first quarter of 2003 partially associated with a wind-down of risk management activities in that year. Investing Activities - -------------------- Cash Flows Used For Investing Activities were reduced by $6 million during the first quarter of 2004 compared with the first quarter of 2003 due primarily to a decrease in construction expenditures. Financing Activities - -------------------- Cash Flows For Financing Activities used $124 million in the first quarter of 2004 and provided $46 million in the first quarter of 2003. This is primarily due to a decrease in the change in Advances to/from Affiliates, Net, during the first quarter of 2004 as a result of becoming a net lender as opposed to a net borrower. Financing Activity - ------------------ Long-term debt issuances and retirements during the first three months of 2004 were: Issuances --------- None Retirements ----------- Principal Interest Due Type of Debt Amount Rate Date ------------ --------- -------- ---- (in thousands) (%) Installment Purchase Contracts $50,000 6.85 2004 Senior Unsecured Notes 140,000 7.375 2004 Notes Payable 1,500 6.27 2009 Notes Payable 1,463 6.81 2008 Other - ----- Power Generation Facility - ------------------------- AEP has agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, own and finance a non-regulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to AEP. The Facility is a "qualifying cogeneration facility" for purposes of PURPA. Commercial operation of the Facility as required by the agreements between Juniper, AEP and The Dow Chemical Company (Dow) was achieved on March 18, 2004. The initial term of the lease commenced on March 18, 2004, and AEP may extend the lease term for up to 30 years. The lease of the Facility is reported by AEP as an owned asset under a lease financing transaction. Therefore, the asset and related liability for the debt and equity of the facility are recorded on AEP's balance sheet. Juniper is an unaffiliated limited partnership, 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 arranged to finance the Facility with debt financing up to $494 million and equity up to $31 million from investors with no relationship to AEP or any of AEP's subsidiaries. At March 31, 2004, Juniper's acquisition costs for the Facility totaled $516 million, and AEP estimates total costs for the completed Facility to be approximately $525 million. For the 30-year extended lease term, the majority of base lease rental is a variable rate obligation indexed to three-month LIBOR (1.11% as of March 31, 2004). Consequently, as market interest rates increase, the base rental payments under the lease will also increase. An additional rental prepayment (up to $396 million) may be due on June 30, 2004 unless Juniper has refinanced its present debt financing on a long-term basis. Juniper is currently planning to refinance by June 30, 2004. The Facility is collateral for the debt obligation of Juniper. At March 31, 2004 and December 31, 2003, AEP reflected $396 million as long-term debt due within one year. AEP's maximum required cash payment as a result of their financing transaction with Juniper is $396 million as well as interest payments during the lease term. Due to the treatment of the Facility as a financing of an owned asset, the recorded liability of $516 million is greater than AEP's maximum possible cash payment obligation to Juniper. Dow will use a portion of the energy produced by the Facility and sell the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as non-conforming. Commercial operation for purposes of the PPA began April 2, 2004. OPCo has entered into an agreement with an affiliate that eliminates OPCo's market exposure related to the PPA. AEP has guaranteed this affiliate's performance under the agreement. On September 5, 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. AEP alleges that TEM has breached the PPA, and we are seeking a determination of our rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of AEP breaches. If the PPA is deemed terminated or found to be unenforceable by the court, AEP could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover claimed termination value damages from TEM. The corporate parent of TEM has provided a limited guaranty. On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the "creation of protocols" was not subject to arbitration, but did not rule upon the merits of TEM's claim that the PPA is not enforceable. On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the "Commercial Operations Date." Despite OPCo's prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo's tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for them under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo (i) was suspending performance of its obligations under PPA, (ii) would be seeking a declaration from the New York federal court that the PPA has been terminated and (iii) would be pursuing against TEM and Tractebel SA under the guaranty damages and the full termination payment value of the PPA. Significant Factors - ------------------- See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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 - ------------ Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Quantitative and Qualitative Disclosures About Risk Management Activities" section. The following tables provide information about our 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.

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.

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. Under SFAS 133 only contracts designated as cash flow hedges are recorded in AOCI, therefore, the table does not provide a full picture of our hedging activity. In accordance with GAAP, all amounts are presented net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,058 thousand loss. Credit Risk - ----------- Our counterparty credit quality and exposure is generally consistent with that of AEP. VaR Associated with Risk Management Contracts - --------------------------------------------- The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

VaR Associated with Debt Outstanding - ------------------------------------ The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $161 million and $214 million at March 31, 2004 and December 31, 2003, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.

OHIO POWER COMPANY CONSOLIDATED INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to OPCo's financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to OPCo. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Rate Matters Note 3 Customer Choice and Industry Restructuring Note 4 Commitments and Contingencies Note 5 Guarantees Note 6 Benefit Plans Note 8 Business Segments Note 9 Financing Activities Note 10 PUBLIC SERVICE COMPANY OF OKLAHOMA PUBLIC SERVICE COMPANY OF OKLAHOMA MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS -------------------------------------------------------- Results of Operations - --------------------- Net Income decreased $10 million for the quarter due mainly to increased Other Operation expenses. Fluctuations occurring in the retail portion of fuel and purchased power expense generally do not impact operating income, as they are offset in revenues due to the functioning of the fuel adjustment clause in Oklahoma. First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Operating Income - ---------------- Operating Income decreased $13 million primarily due to: o Decreased non-fuel related revenues of $3 million, due mainly to a $2 million decrease in wholesale margins from decreased off-system KWH sales. o Increased Other Operation expenses of $12 million due mainly to increased affiliated ancillary services and OATT resulting from an adjustment for prior years due to revised data from ERCOT for the years 2001-2003 of $5 million, other transmission related expenses, increased administrative expenses largely due to outside services and employee related expenses. o Increased Maintenance expense of $4 million due mainly to increased scheduled power plant maintenance of $3 million. . The decrease in Operating Income was partially offset by: o Decreased income taxes of $7 million is due primarily to a decrease in pre-tax operating book income. Other Impacts on Earnings - ------------------------- Interest Charges decreased $3 million as a result of the replacement of higher interest rate first mortgage bonds in 2003 with lower fixed-rate senior 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- Financing Activity - ------------------ There were no long-term debt issuances or retirements during the first three months of 2004. Significant Factors - ------------------- See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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 - ------------ Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Quantitative and Qualitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect. 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.

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. Under SFAS 133 only contracts designated as cash flow hedges are recorded in AOCI, therefore, the table does not provide a full picture of our hedging activity. In accordance with GAAP, all amounts are presented net of related income taxes. Total Accumulated Other Comprehensive Income (Loss) Activity Three Months Ended March 31, 2004 (in thousands) Beginning Balance December 31, 2003 $156 Changes in Fair Value (a) (416) Reclassifications from AOCI to Net Income (b) (28) ------ Ending Balance March 31, 2004 $(288) ====== (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 AOCI 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 AOCI expected to be reclassified to earnings during the next twelve months is a $133 thousand loss. Credit Risk - ----------- Our counterparty credit quality and exposure is generally consistent with that of AEP. VaR Associated with Risk Management Contracts - --------------------------------------------- The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

VaR Associated with Debt Outstanding - ------------------------------------ The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $56 million and $66 million at March 31, 2004 and December 31, 2003, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or financial position.

PUBLIC SERVICE COMPANY OF OKLAHOMA INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to PSO's financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to PSO. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Rate Matters Note 3 Commitments and Contingencies Note 5 Guarantees Note 6 Benefit Plans Note 8 Business Segments Note 9 Financing Activities Note 10 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS ------------------------------------------------- Results of Operations - --------------------- Net Income decreased $14 million for 2004 due largely to the $9 million (net of tax) Cumulative Effect of Accounting Changes recorded in 2003. Fluctuations occurring in the retail portion of fuel and purchased power expense generally do not impact operating income, as they are offset in revenues and/or operations expense due to the functioning of the fuel adjustment clauses in the states in which we serve. First Quarter 2004 Compared to First Quarter 2003 - ------------------------------------------------- Operating Income - ---------------- Operating Income decreased by $6 million primarily due to: o A decrease in risk management activities of $4 million. o Increased Other Operations expense of $12 million primarily due to an increase related to transmission expense resulting from a prior year true-up for OATT transactions recorded in 2004 resulting from revised data from ERCOT for the years 2001-2003 of $6 million and a $5 million increase related to deferred fuel for the Louisiana jurisdiction. o Increased Maintenance expense of $3 million primarily related to scheduled power plant maintenance offset in part by lower overhead line expense. o Increased Depreciation and Amortization expense of $3 million due primarily to the restoration in 2003 of a regulatory asset related to the recovery of fuel related costs in Arkansas. The decrease in Operating Income was partially offset by: o An increase in retail base revenues of $4 million due to an increased number of customers and their average usage, offset in part by milder weather resulting from a 3% decrease in degree-days. o A $2 million increase in transmission revenues due mainly to a prior year true-up for OATT transactions recorded in 2004 resulting from revised data from ERCOT for the years 2001-2003. o Decreased Income Taxes of $5 million is due primarily to a decrease in pre-tax operating book income. Other Impacts on Earnings - ------------------------- Minority Interest Expense of $1 million is a result of consolidating Sabine Mining Company during the third quarter of 2003, due to implementation of FIN 46. The Cumulative Effect of Accounting Changes is due to a one-time after-tax impact of adopting SFAS 143 and EITF 02-3 in 2003. 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- Cash Flow - --------- Cash flows for the Three Months ended March 31, 2004 and 2003 were as follows:

Operating Activities - -------------------- Cash Flows From Operating Activities were $17 million primarily due to Net Income, Accounts Receivables, Fuel Recovery and Taxes Accrued. Investing Activities - -------------------- Cash Used for Investing Activities was primarily related to construction projects for improved transmission and distribution service reliability. Financing Activities - -------------------- Cash Flows From Financing Activities through long-term debt issuances and advances from affiliates were used to replace higher interest rate long-term debt with lower interest rate long-term debt. Financing Activity - ------------------ Long-term debt issuances and retirements during the first three months of 2004 were:

Significant Factors - ------------------- See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us. Critical Accounting Policies - ---------------------------- See "Critical Accounting Policies" in "Registrants' Combined Management's Discussion and Analysis" in the 2003 Annual Report 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 - ------------ Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Quantitative and Qualitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect. 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.

(a) "(Gain) Loss from Contracts Realized/Settled During the Period" includes realized risk management contracts and related derivatives that settled during 2004 that were entered into prior to 2004. (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 2004. 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 2004. (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. (f) "Net Cash Flow Hedge Contracts (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss). 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" is in 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. (c)Amounts exclude Cash Flow Hedges. 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. Under SFAS 133 only contracts designated as cash flow hedges are recorded in AOCI, therefore, the table does not provide a full picture of our hedging activity. In accordance with GAAP, all amounts are presented net of related income taxes. Total Accumulated Other Comprehensive Income (Loss) Activity Three Months Ended March 31, 2004 (in thousands) Beginning Balance December 31, 2003 $184 Changes in Fair Value (a) (490) Reclassifications from AOCI to Net Income (b) (32) ------ Ending Balance March 31, 2004 $(338) ====== (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 AOCI 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 AOCI expected to be reclassified to earnings during the next twelve months is an $156 thousand loss. Credit Risk - ----------- Our counterparty credit quality and exposure is generally consistent with that of AEP. VaR Associated with Risk Management Contracts - --------------------------------------------- The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

VaR Associated with Debt Outstanding - ------------------------------------ The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $37 million and $57 million at March 31, 2004 and December 31, 2003, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to SWEPCo's consolidated financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to SWEPCo. The footnotes begin on page L-1. Footnote Reference --------- Significant Accounting Matters Note 1 New Accounting Pronouncements Note 2 Rate Matters Note 3 Customer Choice and Industry Restructuring Note 4 Commitments and Contingencies Note 5 Guarantees Note 6 Benefit Plans Note 8 Business Segments Note 9 Financing Activities Note 10

1. SIGNIFICANT ACCOUNTING MATTERS ------------------------------ General - ------- The accompanying unaudited interim financial statements should be read in conjunction with the 2003 Annual Report as incorporated in and filed with our 2003 Form 10-K. In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. Components of Accumulated Other Comprehensive Income (Loss) - ----------------------------------------------------------- Accumulated Other Comprehensive Income (Loss) is included on the balance sheet in the equity section. The components of Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries is shown in the following table. March 31, December 31, Components 2004 2003 ----------- ---- ---- (in thousands) Cash Flow Hedges: APCo $(4,619) $(1,569) CSPCo (1,707) 202 I&M (1,871) 222 KPCo (335) 420 OPCo (2,625) (103) PSO (287) 156 SWEPCo (338) 184 TCC (15,590) (1,828) TNC (5,211) (601) Minimum Pension Liability: APCo $(50,519) $(50,519) CSPCo (46,529) (46,529) I&M (25,328) (25,328) KPCo (6,633) (6,633) OPCo (52,646) (48,704) PSO (43,998) (43,998) SWEPCo (21,027) (44,094) TCC (62,511) (60,044) TNC (26,117) (26,117) During the first quarter of 2004, SWEPCo reclassified $23 million from Accumulated Other Comprehensive Income (Loss) related to minimum pension liability to Regulatory Assets ($35 million) and Deferred Income Taxes ($12 million) as a result of authoritative letters issued by the FERC and the Arkansas and Louisiana commissions. 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. 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: Balance At Balance at January 1, March 31, 2004 Accretion 2004 ---------- --------- ---------- (in millions) AEGCo (a) $1.1 $- $1.1 APCo (a) 21.7 0.5 22.2 CSPCo (a) 8.7 0.2 8.9 I&M (b) 553.2 9.7 562.9 OPCo (a) 42.7 0.8 43.5 SWEPCo (d) 8.4 0.2 8.6 TCC (c) 218.8 4.0 222.8 (a) Consists of asset retirement obligations related to ash ponds. (b) Consists of asset retirement obligations related to ash ponds ($1.1 million at March 31, 2004) and nuclear decommissioning costs for the Cook Plant ($561.8 million at March 31, 2004). (c) Consists of asset retirement obligations related to nuclear decommissioning costs for STP included in Liabilities Held for Sale - Texas Generation Plants on TCC's Consolidated Balance Sheets. (d) Consists of asset retirement obligations related to Sabine Mining. Accretion expense is included in Other Operation expense in the respective income statements of the individual subsidiary registrants. As of March 31, 2004 and December 31 2003, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $897 million ($767 million for I&M and $130 million for TCC) and $845 million ($720 million for I&M and $125 million for TCC), respectively, recorded in Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds on I&M's Consolidated Balance Sheets and in Assets Held for Sale-Texas Generation Plants on TCC's Consolidated Balance Sheets. Reclassification - ---------------- Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income. 2. NEW ACCOUNTING PRONOUNCEMENTS ----------------------------- FIN 46 (revised December 2003)"Consolidation of Variable Interest Entities" FIN 46R - --------------------------------------------------------------------------- We implemented FIN 46R, "Consolidation of Variable Interest Entities," effective March 31, 2004 with no material impact to our financial statements. FIN 46R is a revision to FIN 46 which interprets the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FASB Staff Position No. 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003 - ----------------------------------------------------------------------------- In accordance with FASB Staff Position No. 106-1, in December 2003, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC elected to defer accounting for any effects of the prescription drug subsidy under the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act) until the FASB issues authoritative guidance on the accounting for the federal subsidy. The measurements of the accumulated postretirement benefit obligation and periodic postretirement benefit cost included in the financial statements do not reflect any potential effects of the Act. APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC cannot determine what impact, if any, new authoritative guidance on the accounting for the federal subsidy may have on their results of operations or financial condition. Future Accounting Changes The Financial Accounting Standards Board's (FASB's) standard-setting process is ongoing and 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. The FASB is currently working on projects related to accounting for stock compensation, pension plans, property, plant and equipment, earnings per share calculations and related tax impacts. We also expect to see more projects as a result of the FASB's desire to converge International Accounting Standards with those generally accepted in the United States of America. The ultimate pronouncements resulting from these and future projects could have an impact on our future results of operations and financial position. 3. RATE MATTERS ------------ As discussed in the 2003 Annual Report, rate proceedings in the FERC and several state jurisdictions are ongoing. The Rate Matters note within the 2003 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material rate matters still pending, without significant changes since year-end. The following sections discuss current activities. TNC Fuel Reconciliation - Affecting TNC - ---------------------------------------- In 2002, TNC filed with the PUCT to reconcile fuel costs, requesting 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 deferred 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 for under-recovered fuel costs as of the end of the reconciliation period. The under-recovery balance at December 31, 2001 for TNC's service within SPP was $0.7 million including interest. In March 2003, the ALJ in this proceeding filed a Proposal for Decision (PFD) with a recommendation that TNC's under-recovered retail fuel balance be reduced. In March 2003, TNC established a reserve of $13 million based on the recommendations in the PFD. In May 2003, the PUCT reversed the ALJ on certain matters and remanded TNC's final fuel reconciliation to the ALJ to consider two issues. The remand issues are the sharing of off-system sales margins from AEP's trading activities with customers 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. The PUCT proposed that the sharing of off-system sales margins for periods beyond the termination of the fuel factor should be recognized in the final fuel reconciliation proceeding. 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. While 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, an additional provision of $10 million was recorded in December 2003. On December 3, 2003, the ALJ issued a PFD in the remand phase of the TNC fuel reconciliation recommending additional disallowances for the two remand issues. TNC filed responses to the PFD and the PUCT announced a final ruling in the fuel reconciliation proceeding on January 15, 2004 accepting the PFD. TNC received a written order in March 2004 and increased the reserve by $1.5 million. In March 2004, various parties, including TNC, requested a rehearing of the PUCT's ruling. In February 2002, TNC received a final order from the PUCT in a previous fuel reconciliation covering the period July 1997 to June 2000 and reflected the order in its financial statements. This final order was appealed to the Travis County District Court. In May 2003, the District Court upheld the PUCT's final order. That order was appealed to the Third Court of Appeals. In March 2004, the Third Court of Appeals heard oral arguments. A decision is pending. TCC Fuel Reconciliation - Affecting TCC - ----------------------------------------- In 2002, TCC filed its final fuel reconciliation with the PUCT to reconcile fuel costs to be included in its deferred over-recovery balance in the 2004 true-up proceeding. This reconciliation covers the period of July 1998 through December 2001. 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. Based on the PUCT ruling in the TNC proceeding relating to similar issues, TCC established a reserve for potential adverse rulings of $81 million during 2003. On February 3, 2004, the ALJ issued a PFD recommending that the PUCT disallow $140 million in eligible fuel costs including some new items not considered in the TNC case, and other items considered but not disallowed in the TNC ruling. Based on an analysis of the ALJ's recommendations, TCC established an additional reserve of $13 million during the first quarter of 2004. The over-recovery balance and the provisions total $163 million including interest at March 31, 2004. At this time, management is unable to predict the outcome of this proceeding. An adverse ruling from the PUCT, disallowing amounts in excess of the established reserve 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 4 "Customer Choice and Industry Restructuring." SWEPCo Texas Fuel Reconciliation - Affecting SWEPCo - --------------------------------------------------- In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in SPP. This reconciliation covers the period of January 2000 through December 2002. During the reconciliation period, SWEPCo incurred $435 million of Texas retail eligible fuel expense. In November 2003, intervenors and the PUCT Staff recommended fuel cost disallowances of more than $30 million. In December 2003, SWEPCo agreed to a settlement in principle with all parties in the fuel reconciliation. The settlement provides for a disallowance in fuel costs of $8 million which was recorded in December 2003. In addition, the settlement provides for the deferral as a regulatory asset of costs of a new lignite mining agreement in excess of a specified benchmark for lignite at SWEPCo's Dolet Hills Plant. The settlement provides for recovery of the deferred costs over a period ending in April 2011 as cost savings are realized under the new mining agreement. The settlement also will allow future recovery of litigation costs associated with the termination of a previous lignite mining agreement if we achieve future cost savings. In April 2004, the PUCT approved the settlement. TCC Rate Case - Affecting TCC - ----------------------------- On June 26, 2003, the City of McAllen, Texas requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC passed similar rate review resolutions. In Texas, municipalities have original jurisdiction over rates of electric utilities within their municipal limits. Under Texas law, TCC must provide support for its rates to the municipalities. TCC filed the requested support for its rates based on a test year ending June 30, 2003 with all of its municipalities and the PUCT on November 3, 2003. TCC's proposal would decrease its wholesale transmission rates by $2 million or 2.5% and increase its retail energy delivery rates by $69 million or 19.2%. On February 9, 2004, eight intervening parties filed testimony recommending reductions to TCC's requested $67 million rate increase. The recommendations range from a decrease in existing rates of approximately $100 million to an increase in TCC's current rates of approximately $27 million. The PUCT Staff filed testimony, on February 17, 2004, recommending reductions to TCC's request of approximately $51 million. TCC's rebuttal testimony was filed on February 26, 2004. The PUCT held hearings in March 2004 and is expected to issue a decision in June 2004. Management is unable to predict the ultimate effect of this proceeding on TCC's rates or its impact on TCC's results of operations, cash flows and financial condition. Louisiana Compliance Filing - Affecting SWEPCo - ----------------------------------------------- In October 2002, SWEPCo filed with the Louisiana Public Service Commission (LPSC) detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of their order approving the merger between AEP and CSW. The LPSC's merger order also provides that SWEPCo's base rates are capped at the present level through mid 2005. In April 2004, SWEPCo filed updated financial information with a test year ending December 31, 2003 as required by the LPSC. Both filings indicate that SWEPCo's current rates should not be reduced. If, after review of the updated information, the LPSC disagrees with our conclusion, they could order SWEPCo to file all documents for a full cost of service revenue requirement review in order to determine whether SWEPCo's capped rates should be reduced which would adversely impact results of operations and cash flows. PSO Fuel and Purchased Power - Affecting PSO - -------------------------------------------- PSO had a $44 million under-recovery of fuel costs resulting from a 2002 reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO filed with the Corporation Commission of the State of Oklahoma (OCC) seeking recovery of the $44 million over an 18-month period. In August 2003, the OCC Staff filed testimony recommending PSO be granted recovery of $42.4 million over three years. In September 2003, the OCC expanded the case to include a full review of PSO's 2001 fuel and purchased power practices. PSO filed its testimony in February 2004. An intervenor and the OCC Staff filed testimony in April 2004. The intervenor suggested $8.8 million related to the 2002 reallocation not be recovered from customers. The Attorney General of Oklahoma also filed a statement of position, indicating allocated trading margins were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and could more than offset the $44 million 2002 allocation. The intervenor and the OCC Staff also believed trading margins were allocated incorrectly. Under the intervenor's recalculation of margin allocation, PSO's amount of recoverable fuel would be decreased approximately $6.8 million for 2000 and $10.7 million for 2001. OCC Staff calculates the 2001 amount at $8.8 million. They also recommend recalculation of fuel for years subsequent to 2001 using the same methods. Hearings are scheduled to occur in June 2004. Management believes that fuel costs have been prudently incurred consistent with OCC rules, and that the allocation of trading margins pursuant to the agreements is correct. If the OCC determines, as a result of the review that a portion of PSO's fuel and purchased power costs should not be recovered, there will be an adverse effect on PSO's results of operations, cash flows and possibly financial condition. 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). In July 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 $31 million of RTO formation and integration costs and related carrying charges through March 31, 2004. Amounts per company are as follows: Company (in millions) ------- ------------- APCo $8.5 CSPCo 3.6 I&M 6.6 KPCo 2.0 OPCo 9.4 As a result of the subsequent delay in the integration of AEP's East transmission system into PJM, FERC declined to rule, in its July 2003 order, 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 plan to apply for permission to transfer the deferred formation/integration costs to a regulatory asset prior to integration with PJM. In August 2003, the Virginia SCC filed a request for rehearing of the July 2003 order, arguing that FERC's action was an infringement on state jurisdiction, and that FERC should not have treated Alliance RTO startup costs in the same manner as PJM integration costs. On October 22, 2003, FERC denied the rehearing request. In its July 2003 order, FERC indicated that it would review the deferred costs 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 East companies' portion of the OATT at the time they join PJM. Presently, retail base rates are frozen or capped and cannot be increased for retail customers of CSPCo, I&M and OPCo. We intend to file an application 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. The AEP East companies are scheduled to join PJM in October 2004, although there are pending proceedings at the FERC and in Virginia and Kentucky concerning our integration into PJM. Therefore, 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. If the AEP East companies do not obtain regulatory approval to join PJM, we are committed to reimburse PJM for certain project implementation costs (presently estimated at $24 million for AEP's share of the entire PJM integration project). If incurred, PJM project implementation costs will be allocated among the AEP East companies. Management intends to seek recovery of the deferred RTO formation/integration costs and project implementation cost reimbursements, if incurred. 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. In the first quarter of 2003, the state of Virginia enacted legislation preventing APCo from joining an RTO prior to July 1, 2004 and thereafter only with the approval of the Virginia SCC, but required such transfers by January 1, 2005. In January 2004, APCo filed with the Virginia SCC a cost/benefit study covering the time period through 2014 as required by the Virginia SCC. The study results show a net benefit of approximately $98 million for APCo over the 11-year study period from AEP's participation in PJM. A hearing for this proceeding is scheduled in July 2004. In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack of evidence that it would benefit Kentucky retail customers. In August 2003, KPCo sought and was granted a rehearing to submit additional evidence. In December 2003, AEP filed with the KPSC a cost/benefit study showing a net benefit of approximately $13 million for KPCo over the five-year study period from AEP's participation in PJM. In April 2004, we reached an agreement with interveners to settle the RTO issues in Kentucky. The KPSC is expected to consider the agreement in May. In September 2003, the IURC issued an order approving I&M's transfer of functional control over its transmission facilities to PJM, subject to certain conditions included in the order. The IURC's order stated that AEP shall request and the IURC shall complete a review of Alliance formation costs before any deferral of the costs for future recovery. In November 2003, the FERC issued an order preliminarily finding that AEP must fulfill its CSW merger condition to join an RTO by integrating into PJM (transmission and markets) by October 1, 2004. The order was based on PURPA 205(a), which allows FERC to exempt electric utilities from state law or regulation in certain circumstances. The FERC set several issues for public hearing before an ALJ. Those issues include whether the laws, rules, or regulations of Virginia and Kentucky are preventing AEP from joining an RTO and whether the exceptions under PURPA 205(a) apply. The FERC ALJ affirmed the FERC's preliminary finding in March 2004. The FERC has not issued a final order in this matter. FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo, I&M, KPCo and OPCo - -------------------------------------------------------------------------- In July 2003, the FERC issued an order directing PJM and the Midwest Independent System Operator (ISO) to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed Midwest ISO and PJM expanded regions (RTO Footprint). The elimination of the T&O rates 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 T&O rates. The FERC also found that the T&O 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 RTO Footprint. FERC initiated an investigation and hearing in regard to these rates. In November 2003, the FERC adopted a new regional rate design and directed each transmission provider to file compliance rates to eliminate T&O rates prospectively within the region and simultaneously implement new seams elimination cost allocation (SECA) rates to mitigate the lost revenues for a two-year transition period beginning April 1, 2004. The FERC was expected to implement a new rate design after the two-year period. As required by the FERC, AEP filed compliance tariff changes in January 2004 to eliminate the T&O charges within the RTO Footprint. Various parties raised issues with the SECA rate orders and the FERC implemented settlement procedures before an ALJ. In March 2004, the FERC approved a settlement that delays elimination of T&O rates until December 1, 2004 and provides principles and procedures for a new rate design for the RTO Footprint, to be effective on December 1, 2004. The settlement also provides that if the process does not result in the implementation of a new rate design on December 1, then the SECA rates will be implemented and will remain in effect until a new rate is implemented by the FERC. If implemented, the SECA rate would not be effective beyond March 31, 2006. The AEP East companies received approximately $157 million of T&O rate revenues from transactions delivering energy to customers in the RTO Footprint for the twelve months ended December 31, 2003. At this time, management is unable to predict whether the new rate design will fully compensate the AEP East companies for their lost T&O rate revenues and, consequently, their impact on future results of operations, cash flows and financial condition. Indiana Fuel Order - Affecting I&M - ---------------------------------- On July 17, 2003, I&M filed a fuel adjustment clause application requesting authorization to implement the fixed fuel adjustment charge (fixed pursuant to a prior settlement of the Cook Nuclear Plant Outage) for electric service for the billing months of October 2003 through February 2004, and for approval of a new fuel cost adjustment credit for electric service to be applicable during the March 2004 billing month. The Cook settlement agreement provided for the fixed rate to end in February 2004. In another agreement in connection with a planned corporate separation I&M agreed, contingent on implementing the corporate separation, to a new freeze conditionally beginning March 2004 and continuing through December 2007. On August 27, 2003, the IURC issued an order approving the requested fixed fuel adjustment charge for October 2003 through February 2004. The order further stated that certain parties must negotiate the appropriate action on fuel after March 1, 2004. Negotiations with the parties to determine a resolution of this issue are ongoing. The IURC ordered the fixed fuel adjustment charge remain in place, on an interim basis, for March and April 2004. In April 2004, the IURC issued an order that extended the interim fuel factor for May through September 2004, subject to true-up following the resolution of issues in the corporate separation agreement. The IURC also issued an order that reopens the corporate separation docket to investigate issues related to the corporate separation agreement. Michigan 2004 Fuel Recovery Plan - Affecting I&M - ------------------------------------------------ A Michigan Public Service Commission's (MPSC) December 16, 1999 order approved a Settlement Agreement regarding the extended outage of the Cook Plant and fixed I&M Power Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers rate areas through December 2003. In accordance with the settlement, PSCR Plan cases were not required to be filed through the 2003 plan year. As required, I&M filed its 2004 PSCR Plan with the MPSC on September 30, 2003 seeking new fuel and power supply recovery factors to be effective in 2004. A public hearing of this case occurred on March 10, 2004 and a MPSC order is expected during the second half of 2004. As allowed by Michigan law, the proposed factors were effective on January 1, 2004, subject to review and possible adjustment based on the results of the MPSC order. 4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING ------------------------------------------ As discussed in the 2003 Annual Report, certain AEP subsidiaries are affected by customer choice initiatives and industry restructuring. The Customer Choice and Industry Restructuring note in the 2003 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant current events related to customer choice and industry restructuring. OHIO RESTRUCTURING - Affecting CSPCo and OPCo - --------------------------------------------- The Ohio Electric Restructuring Act of 1999 (Ohio Act) provides for a Market Development Period (MDP) during which retail customers can choose their electric power suppliers or receive Default Service at frozen generation rates from the incumbent utility. The MDP began on January 1, 2001 and is scheduled to terminate no later than December 31, 2005. The Public Utilities Commission of Ohio (PUCO) may terminate the MDP 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 MDP, 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 receive Default Service, which must be offered by the incumbent utility at market rates. On December 17, 2003, the PUCO adopted a set of rules concerning the method by which it will determine market rates for Default Service following the MDP. The rule provides for a Market Based Standard Service Offer which would be a variable rate based on a transparent forward market, daily market, and/or hourly market prices. The rule also requires a fixed-rate Competitive Bidding Process for residential and small nonresidential customers and permits a fixed-rate Competitive Bidding Process for large general service customers and other customer classes. Customers who do not switch to a competitive generation provider can choose between the Market Based Standard Service Offer or the Competitive Bidding Process. Customers who make no choice will be served pursuant to the Competitive Bidding Process. On February 9, 2004, CSPCo and OPCo filed their rate stabilization plan with the PUCO addressing rates following the end of the MDP, which ends December 31, 2005. If approved by the PUCO, rates would be established pursuant to the plan for the period from January 1, 2006 through December 31, 2008 instead of the rates discussed in the previous paragraph. The plan is intended to provide rate stability and certainty for customers, facilitate the development of a competitive retail market in Ohio, provide recovery of environmental and other costs during the plan period and improve the environmental performance of AEP's generation resources that serve Ohio customers. The plan includes annual, fixed increases in the generation component of all customers' bills (3% annually for CSPCo and 7% annually for OPCo), and the opportunity for additional generation-related increases upon PUCO review and approval. For residential customers, however, if the temporary 5% generation rate discount provided by the Ohio Act was eliminated on June 30, 2004, the fixed increases would be 1.6% for CSPCo and 5.7% for OPCo. The generation-related increases under the plan would be subject to caps. The plan would maintain distribution rates through the end of 2008 for CSPCo and OPCo at the level effective on December 31, 2005. Such rates could be adjusted for specified reasons. Transmission charges can be adjusted to reflect applicable charges approved by the FERC related to open access transmission, net congestion, and ancillary services. The plan also provides for continued recovery of transition regulatory assets and deferral of regulatory assets in 2004 and 2005 for RTO costs and carrying charges on required expenditures. Management cannot predict whether the plan will be approved as submitted or its impact on results of operations and cash flows. As provided in stipulation agreements approved by the PUCO in 2000, CSPCo and OPCo are deferring customer choice implementation costs and related carrying costs that are 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. The February 2004 filing provides for the continued deferrals of customer choice implementation costs during the rate stabilization plan period. At March 31, 2004, CSPCo has incurred $33 million and deferred $13 million and OPCo has incurred $36 million and deferred $16 million of such costs. Recovery of these regulatory assets will be subject to PUCO review in each company's future Ohio filings for new distribution rates. If the rate stabilization plan is approved, it would defer recovery of these amounts until after the end of the rate stabilization period. Management believes that the customer choice implementation costs were prudently incurred and the deferred amounts 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 - --------------------------------------------------- Texas Legislation enacted in 1999 provided the framework and timetable to allow retail electricity competition for all customers. On January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in the SPP area of Texas until at least January 1, 2007. The Texas Legislation, among other things: o provides for the recovery of regulatory assets and other stranded costs through securitization and non-bypassable wires charges; o requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility; o provides for an earnings test for each of the years 1999 through 2001 and; o provides for a 2004 true-up proceeding. See 2004 true-up proceeding discussion below. The Texas Legislation required vertically integrated utilities to legally separate their generation and retail-related assets from their transmission and distribution-related assets. Prior to 2002, TCC and TNC functionally separated their operations to comply with the Texas Legislation requirements. AEP formed new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1, 2002 (the start date of retail competition). In December 2002, AEP sold the affiliated REPs to an unaffiliated company. TEXAS 2004 TRUE-UP PROCEEDING - ----------------------------- A 2004 true-up proceeding will determine the amount and recovery of: o net stranded generation plant costs and generation-related regulatory assets (stranded costs), o a true-up of actual market prices determined through legislatively-mandated capacity auctions to the power costs used in the PUCT's excess cost over market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up), o final approved deferred fuel balance, o unrefunded accumulated excess earnings, o excess of price-to-beat revenues over market prices subject to certain conditions and limitations (retail clawback) and o other restructuring true-up items. The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up proceedings, scheduling TNC's filing in May 2004 and TCC's filing in September 2004 or 60 days after the completion of the sale of TCC's generation assets, if later. Stranded Costs and Generation-Related Regulatory Assets - ------------------------------------------------------- Restructuring legislation required utilities with stranded costs to use market-based methods to value certain generation assets for determining stranded costs. TCC is the only AEP subsidiary that has stranded costs under the Texas Legislation. We have elected to use the sale of assets method to determine the market value of TCC's generation assets for stranded cost purposes. When completed, the sale of TCC's generation assets will substantially complete the required separation of generation assets from transmission and distribution assets. For purposes of the 2004 true-up proceeding, the amount of stranded costs under this market valuation methodology will be the amount by which the book value of TCC's generation 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. In December 2002, TCC filed a plan of divestiture with the PUCT seeking approval of a sales process for all of its generation facilities. In March 2003, the PUCT dismissed TCC's divestiture filing, determining that it was more appropriate to address allowable valuation methods for the nuclear asset in a rulemaking proceeding. The PUCT approved a rule, in May 2003, which allows the market value obtained by selling nuclear assets to be used in determining stranded costs. Although the PUCT declined to review TCC's proposed sale of assets process, the PUCT hired a consultant to advise the PUCT and TCC during the sale of the generation assets. TCC's sale of its generation assets will be subject to a review in the 2004 true-up proceeding. In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's generating capacity in Texas. In order to sell these assets, TCC anticipates retiring first mortgage bonds by making open market purchases or defeasing the bonds. Bids were received for all of TCC's generation plants. In January 2004, TCC agreed to sell its 7.8% ownership interest in the Oklaunion Power Station to an unaffiliated third party for approximately $43 million. In March 2004, TCC agreed to sell its 25.2% in STP for approximately $333 million and its other coal, gas and hydro plants for approximately $430 million to unaffiliated entities. Each sale is subject to specified price adjustments. TCC sent right of first refusal notices, expiring in May and June 2004, to the co-owners of Oklaunion and STP, respectively. TCC filed for FERC approval of the sales of the fossil and hydro plants. TCC will request approval of the STP sale from the FERC during the second quarter of 2004. TCC received a notice from a co-owner of Oklaunion exercising their right of first refusal; therefore, SEC approval will be required. Approval of the sale of STP from the Nuclear Regulatory Commission is required. The completion of the sales is expected to occur in 2004, subject to rights of first refusal and the necessary approvals required for each sale. TCC will file its 2004 true-up proceeding with the PUCT after the sale of the generation assets. After the 2004 true-up proceeding, TCC may recover stranded costs and other true-up amounts through transmission and distribution rates as a competition transition and may seek to issue securitization revenue bonds for its stranded costs. The cost of the securitization bonds is recovered through transmission and distribution rates as a separate transition charge. TCC recorded an impairment of generation assets of $938 million in December 2003 as a regulatory asset (see Note 7). The recovery of the regulatory asset will be subject to review and approval by the PUCT as a stranded cost in the 2004 true-up proceeding. Wholesale Capacity Auction True-up - ---------------------------------- Texas Legislation also requires that electric utilities and their affiliated power generation companies (PGC) offer for sale at auction, in 2002 and 2003 and after, 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. Actual market power prices received in the state mandated auctions will be used to calculate the wholesale capacity auction true-up adjustment for TCC for the 2004 true-up proceeding. TCC recorded a $480 million regulatory asset and related revenues which represent the quantifiable amount of the wholesale capacity auction true-up for the years 2002 and 2003. In the fourth quarter of 2003, the PUCT approved a true-up filing package containing calculation instructions similar to the methodology employed by TCC to calculate the amount recorded for recovery under its wholesale capacity auction true-up. The PUCT will review the $480 million wholesale capacity auction true-up regulatory asset for recovery as part of the 2004 true-up proceeding. Fuel Balance Recoveries - ----------------------- In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to establish its deferred unrecovered fuel balance applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. In January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation case. TNC received a written order on March 1, 2004 that established TNC's unrecovered fuel balance, including interest for the ERCOT service territory, at $4.6 million. This balance will be included in TNC's 2004 true-up proceeding. Various parties, including TNC, requested rehearing of the PUCT's order. In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its deferred over-recovery of fuel balance for inclusion in the 2004 true-up proceeding. In February 2004, an ALJ issued recommendations finding a $205 million over-recovery in this fuel proceeding. Management is unable to predict the amount of TCC's fuel over-recovery which will be included in its 2004 true-up proceeding. See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 3 "Rate Matters" for further discussion. Unrefunded Excess Earnings - -------------------------- The Texas Legislation provides for the calculation of excess earnings for each year from 1999 through 2001. The total excess earnings determined for the three year period were $3 million for SWEPCo, $47 million for TCC and $19 million for TNC. TCC, TNC and SWEPCo challenged the PUCT's treatment of fuel-related deferred income taxes and appealed the PUCT's final 2000 excess earnings to the Travis County District Court which upheld the PUCT ruling. The District Court's ruling was appealed to the Third Court of Appeals. In August 2003, the Third Court of Appeals reversed the PUCT order and the District Court judgment. The PUCT's request for rehearing of the Appeals Court's decision was denied and the PUCT chose not to appeal the ruling any further. The District Court remanded to the PUCT an appeal of the same issue from the PUCT's 2001 order to be consistent with the Court of Appeals decision. Since an expense and regulatory liability had been accrued in prior years in compliance with the PUCT orders, the companies reversed a portion of their regulatory liability for the years 2000 and 2001 consistent with the Appeals Court's decision and credited amortization expense during the third quarter of 2003. In 2001, the PUCT issued an order requiring TCC to return estimated excess earnings by reducing distribution rates by approximately $55 million plus accrued interest over a five-year period beginning January 1, 2002. Since excess earnings amounts were expensed in 1999, 2000 and 2001, the order has no additional effect on reported net income but will reduce cash flows for the five-year refund period. The amount to be refunded is recorded as a regulatory liability. Management believes that TCC will have stranded costs and that it was inappropriate for the PUCT to order a refund prior to TCC's 2004 true-up proceeding. TCC appealed the PUCT's refund of excess earnings to the Travis County District Court. That court affirmed the PUCT's decision and further ordered that the refunds be provided to customers. TCC has appealed the decision to the Court of Appeals. Retail Clawback - --------------- The Texas Legislation provides for the affiliated price-to-beat (PTB) retail electric providers (REP) serving residential and small commercial customers to refund to its T&D utility the excess of the PTB revenues over market prices (subject to certain conditions and a limitation of $150 per customer). This is the retail clawback. If, prior to January 1, 2004, 40% of the load for the residential or small commercial classes is served by competitive REPs, the retail clawback is not applicable for that class of customer. During 2003, TCC and TNC filed to notify the PUCT that competitive REPs serve over 40% of the load in the small commercial class. The PUCT approved TCC's and TNC's filings in December 2003. In 2002, AEP had accrued a regulatory liability of approximately $9 million for the small commercial retail clawback on its REP's books. When the PUCT certified that the REP's in TCC and TNC service territories had reached the 40% threshold, the regulatory liability was no longer required for the small commercial class and was reversed in December 2003. At March 31, 2004, the remaining retail clawback liability was $45.5 million for TCC and $11.8 million for TNC. Stranded Cost Recovery - ---------------------- When the 2004 true-up proceeding is completed, TCC intends to file to recover PUCT-approved stranded costs and other true-up amounts that are in excess of current securitized amounts, plus appropriate carrying charges and other true-up amounts, through non-bypassable competition transition charge in the regulated T&D rates. TCC may also seek to securitize certain of the approved stranded plant costs and regulatory assets that were not previously recovered through the non-bypassable transition charge. The annual costs of securitization are recovered through a non-bypassable rate surcharge collected by the T&D utility over the term of the securitization bonds. In the event we are unable, after the 2004 true-up proceeding, to recover all or a portion of our stranded plant costs, generation-related regulatory assets, unrecovered fuel balances, wholesale capacity auction true-up regulatory assets, other restructuring true-up items and costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. VIRGINIA RESTRUCTURING - ---------------------- In April 2004, the Governor of Virginia signed legislation which extends the transition period for electricity restructuring including capped rates through December 31, 2010. The legislation provides specific cost recovery opportunities during the capped rate period, including two general rate changes and an opportunity for recovery of incremental environmental and reliability costs. 5. COMMITMENTS AND CONTINGENCIES ----------------------------- As discussed in the Commitments and Contingencies note within the 2003 Annual Report, certain AEP subsidiaries continue to be involved in various legal matters. The 2003 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since their disclosure in the 2003 Annual Report. The material matters discussed in the 2003 Annual Report without significant changes in status since year-end include, but are not limited to, (1) nuclear matters, (2) construction commitments, (3) merger litigation, (4) Texas Commercial Energy, LLP lawsuit, and (5) FERC proposed Standard Market Design. See disclosure below for significant matters with changes in status subsequent to the disclosure made in the 2003 Annual Report. ENVIRONMENTAL - ------------- Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo - --------------------------------------------------------------------------- The Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and other unaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the Clean Air Act (CAA). The Federal EPA filed its complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications relate to costs that were incurred at the generating units over a 20-year period. Under the CAA, 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 CAA 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. On August 7, 2003, the District Court issued a decision following a liability trial in a case pending in the Southern District of Ohio against Ohio Edison Company, an unaffiliated 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 July 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 August 26, 2003, the District Court for the Middle District of South Carolina issued a decision on cross-motions for summary judgment prior to a liability trial in a case pending against Duke Energy Corporation, an unaffiliated utility. The District Court denied all the pending motions, but set forth the legal standards that will be applied at the trial in that case. The District Court determined that the Federal EPA bears the burden of proof on the issue of whether a practice is "routine maintenance, repair, or replacement" and on whether or not a "significant net emissions increase" results from a physical change or change in the method of operation at a utility unit. However, the Federal EPA must consider whether a practice is "routine within the relevant source category" in determining if it is "routine." Further, the Federal EPA must calculate emissions by determining first whether a change in the maximum achievable hourly emission rate occurred as a result of the change, and then must calculate any change in annual emissions holding hours of operation constant before and after the change. The Federal EPA requested reconsideration of this decision, or in the alternative, certification of an interlocutory appeal to the Fourth Circuit Court of Appeals, and the District Court denied the Federal EPA's motion. On April 13, 2004, the parties filed a joint motion for entry of final judgment, based on stipulations of relevant facts that obviated the need for a trial, but preserving plaintiffs' right to seek an appeal of the federal prevention of significant deterioration (PSD) claims. On April 14, 2004, the Court entered final judgment for Duke Energy on all of the PSD claims made in the amended complaints, and dismissed all remaining claims with prejudice. On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued an order invalidating the administrative compliance order issued by the Federal EPA to the Tennessee Valley Authority for alleged CAA 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 CAA are unconstitutional. The United States filed a petition for certiorari with the United States Supreme Court, and on May 3, 2004, that petition was denied. On June 26, 2003, the United States 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 Circuit Court denied that motion on September 30, 2003. The central issue in these petitions concerns the lawfulness of the emissions increase test, as currently interpreted and applied by the Federal EPA in its utility enforcement actions. A decision by the D. C. Circuit Court could significantly impact further proceedings in the AEP case. On August 27, 2003, the Administrator of the Federal EPA signed a final rule that defines "routine maintenance repair and replacement" to include "functionally equivalent equipment replacement." Under the new final rule, replacement of a component within an integrated industrial operation (defined as a "process unit") with a new component that is identical or functionally equivalent will be deemed to be a "routine replacement" if the replacement does not change any of the fundamental design parameters of the process unit, does not result in emissions in excess of any authorized limit, and does not cost more than twenty percent of the replacement cost of the process unit. The new rule is intended to have a prospective effect, and was to become effective in certain states 60 days after October 27, 2003, the date of its publication in the Federal Register, and in other states upon completion of state processes to incorporate the new rule into state law. On October 27, 2003 twelve states, the District of Columbia and several cities filed an action in the United States Court of Appeals for the District of Columbia Circuit seeking judicial review of the new rule. The UARG has intervened in this case. On December 24, 2003, the Circuit Court granted a motion from the petitioners to stay the effective date of this rule, which had been December 26, 2003. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the CAA proceedings. Management is also 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. If 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 the 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. OPERATIONAL - ----------- Power Generation Facility - Affecting OPCo - ------------------------------------------ AEP has agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, own and finance a non-regulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to AEP. The Facility is a "qualifying cogeneration facility" for purposes of PURPA. Commercial operation of the Facility as required by the agreements between Juniper, AEP and The Dow Chemical Company (Dow) was achieved on March 18, 2004. Dow will use a portion of the energy produced by the Facility and sell the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price which is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA which TEM rejected as non-conforming. Commercial operation for purposes of the PPA began April 2, 2004. OPCo has entered an agreement with an affiliate that eliminates OPCo's market exposure related to the PPA. AEP has guaranteed this affiliate's performance under the agreement. On September 5, 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. AEP alleges that TEM has breached the PPA, and is seeking a determination of OPCo's rights under the PPA. TEM alleges that the PPA never became enforceable or alternatively, that the PPA has already been terminated as the result of AEP breaches. If the PPA is deemed terminated or found to be unenforceable by the court, AEP could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover claimed termination value damages from TEM. The corporate parent of TEM has provided a limited guaranty. On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the "creation of protocols" was not subject to arbitration, but did not rule upon the merits of TEM's claim that the PPA is not enforceable. On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the "Commercial Operations Date." Despite OPCo's prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo's tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for them under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo (i) was suspending performance of its obligations under PPA, (ii) would be seeking a declaration from the New York federal court that the PPA has been terminated and (iii) would be pursing against TEM and Tractebel SA under the guaranty damages and the full termination payment value of the PPA. Enron Bankruptcy - Affecting APCo, CSPCo, I&M, KPCo and OPCo - ----------------------------------------------------------- In 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the bankruptcy proceeding 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, AEP purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities from Enron remained unsettled at the date of Enron's bankruptcy. Commodity trading settlement disputes - In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP's offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas related trading transactions. The AEP subsidiaries asserted their right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows or financial condition. In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows or financial condition. Enron bankruptcy summary - The amount expensed in prior years in connection with the Enron bankruptcy 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. As noted above, Enron has challenged the offsetting of receivables and payables. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows and financial condition. Energy Market Investigation - Affecting AEP System - -------------------------------------------------- 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 (CFTC), 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 and 2004. On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas in violation of the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and disgorgement of benefits. The case is in the initial pleading stage with our response to the complaint currently due on May 18, 2004. Although management is unable to predict the outcome of this case, it is not expected to have a material effect on results of operations due to a provision recorded in December 2003. In January 2004, the CFTC issued a request for documents and other information in connection with a CFTC investigation of activities affecting the price of natural gas in the fall of 2003. We are responding to that request. Management cannot predict what, if any further action, any of these governmental agencies may take with respect to these matters. FERC Market Power Mitigation - Affecting AEP System - --------------------------------------------------- A FERC order issued in November 2001 on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power system's status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. AEP and two unaffiliated utilities were required to submit generation market power analyses within sixty days of the FERC's order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. Management is unable to predict the outcome of these actions by the FERC or their affect on future results of operations and cash flows. 6. GUARANTEES ---------- There are no liabilities recorded for guarantees entered into prior to December 31, 2002 by registrant subsidiaries in accordance with FIN 45. There are certain immaterial liabilities recorded for guarantees entered into subsequent to December 31, 2002. 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. Letter of Credit - ---------------- TCC has entered into a standby letter of credit (LOC) with third parties. This LOC covers credit enhancements for issued bonds. This LOC was issued in TCC's ordinary course of business. At March 31, 2004, the maximum future payments of the LOC are $43 million which matures November 2005. AEP holds all assets of the subsidiary as collateral. There is no recourse to third parties in the event this letter of credit is drawn. SWEPCo - ------ 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 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 $51 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 March 31, 2004, 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. On July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46. Upon consolidation, SWEPCo recorded the assets and liabilities of Sabine ($78 million). Also, after consolidation, SWEPCo currently records all expenses (depreciation, interest and other operation expense) of Sabine and eliminates Sabine's revenues against SWEPCo's fuel expenses. There is no cumulative effect of an accounting change recorded as a result of the requirement to consolidate, and there is no change in net income due to the consolidation of Sabine. Indemnifications and Other Guarantees - ------------------------------------- All of the registrant subsidiaries enter into certain 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, exposure generally does not exceed the sale price. Registrant subsidiaries cannot estimate the maximum potential exposure for any of these indemnifications entered into prior to December 31, 2002 due to the uncertainty of future events. In 2003 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 into during 2003. There are no liabilities recorded for any indemnifications entered prior to December 31, 2002. Certain registrant 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 March 31, 2004, the maximum potential loss by subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows: Maximum Potential Loss Subsidiary (in millions) ---------- ------------- APCo $1 CSPCo 1 I&M 2 KPCo 1 OPCo 4 PSO 4 SWEPCo 4 TCC 6 TNC 2 7. ASSETS HELD FOR SALE -------------------- DISPOSITIONS ANNOUNCED DURING FIRST QUARTER 2004 - ------------------------------------------------ During the first quarter of 2004 we announced the following dispositions expected to close later this year: Texas Plants - ------------ In December 2002, TCC filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets, including the eight gas-fired generating plants that were either deactivated or designated as "reliability must run" status. During the fourth quarter of 2003, after receiving bids from interested buyers, TCC recorded a $938 million impairment loss and changed the classification of the plant assets from plant in service to Assets Held for Sale. In accordance with Texas legislation, the $938 million impairment was offset by the establishment of a regulatory asset, which is expected to be recovered through a wires charge, subject to the final outcome of the 2004 Texas true-up proceeding. During early 2004 TCC signed agreements to sell all of its generating assets at prices which approximate book value after considering the impairment charge described above. As a result, TCC does not expect these pending asset sales, described below, to have a significant effect on its future results of operations. Oklaunion Power Station ----------------------- In January 2004, TCC signed an agreement to sell its 7.8 percent share of Oklaunion Power Station for approximately $43 million, subject to closing adjustments. The planned sale is expected to close in June 2004, subject to the co-owners' decisions on their rights of first refusal. TCC has received notice from a co-owner of their decision to exercise their right of first refusal. South Texas Project ------------------- In February 2004, TCC signed an agreement to sell its 25.2 percent share of the South Texas Project (STP) nuclear plant for approximately $333 million, subject to closing adjustments. TCC expects the sale to close in the second half of 2004, subject to the co-owners' decisions on their rights of first refusal. TCC does not expect the sale of this asset to have a significant effect on its results of operations. TCC Generation Assets --------------------- In March 2004, TCC signed an agreement to sell its remaining generating assets, including eight natural gas plants, one coal-fired plant and one hydro plant to a non-related joint venture for approximately $430 million, subject to closing adjustments. TCC expects the sale to close in mid-2004, subject to various regulatory approvals and clearances. ASSETS HELD FOR SALE - -------------------- The assets and liabilities of the TCC plants held for sale at March 31, 2004 and December 31, 2003 are as follows: March 31, 2004 December 31, 2003 -------------- ----------------- Assets: (in millions) Current Assets $56 $57 Property, Plant and Equipment, Net 799 797 Regulatory Assets 48 49 Decommissioning Trusts 130 125 ------- ------- Total Assets Held for Sale $1,033 $1,028 ======= ======= Liabilities: Regulatory Liabilities $9 $9 Asset Retirement Obligations 223 219 ------- ------- Total Liabilities Held for Sale $232 $228 ======= ======= 8. BENEFIT PLANS ------------- APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP sponsored U.S. qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWPECo, TCC and TNC participate in other postretirement benefit plans sponsored by AEP to provide medical and death benefits for retired employees in the U.S. The following table provides the components of AEP's net periodic benefit cost (credit) for the plans for the three months ended March 31, 2004 and 2003:

The following table provides the net periodic benefit cost (credit) for the plans by the following AEP registrant subsidiaries for the three months ended March 31, 2004 and 2003:

9. 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. 10. FINANCING ACTIVITIES -------------------- Long-term debt and other securities issuances and retirements during the first three months of 2004 were:

Retirements: ------------ None Lines of Credit - AEP System - ---------------------------- The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries. The corporate borrowing program includes a utility money pool, which funds the utility subsidiaries and a non-utility money pool, which funds the majority of the non-utility subsidiaries. In addition, the AEP System also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in the non-utility money pool for regulatory or operational reasons. The AEP System Corporate Borrowing Program operates in accordance with the terms and conditions outlined by the SEC. AEP has authority from the SEC through March 31, 2006 for short-term borrowings sufficient to fund the utility money pool and the non-utility money pool as well as its own requirements in an amount not to exceed $7.2 billion. Utility money pool participants include AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC (domestic utility companies). The following are the SEC authorized limits for short-term borrowings for the domestic utility companies as of March 31, 2004: Authorized ---------- (in millions) AEP Generating Company $125 AEP Texas Central Company (a) 438 AEP Texas North Company (a) 275 Appalachian Power Company 600 Columbus Southern Power Company (a) 150 Indiana Michigan Power Company 500 Kentucky Power Company 200 Ohio Power Company (a) - Public Service Company of Oklahoma 300 Southwestern Electric Power Company 350 (a) Short-term borrowing limits for these domestic utility companies are reduced by long-term debt issued commencing with the SEC order dated December 18, 2002, which authorized financing transactions through March 31, 2006. REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS ---------------------------------------------------------- The following is a combined presentation of certain components of the registrants' management's discussion and analysis. The information in this section completes the information necessary for management's discussion and analysis of financial condition and results of operations and is meant to be read with (i) Management's Financial Discussion and Analysis, (ii) financial statements, and (iii) footnotes of each individual registrant. The Registrants' Combined Management's Discussion and Analysis section of the 2003 Annual Report should be read in conjunction with this report. Significant Factors - ------------------- RTO Formation - ------------- 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 our subsidiaries' transmission systems to RTOs. In addition, legislation in some of our states requires RTO participation. The status of the transfer of functional control of our subsidiaries' transmission systems to RTOs or the status of our participation in RTOs has not changed significantly from our disclosure as described in "RTO Formation" within the "Registrants' Combined Management's Discussion and Analysis" section of the 2003 Annual Report. In November 2003, the FERC preliminarily found that certain AEP subsidiaries must fulfill their CSW merger condition to join an RTO by integrating into PJM (transmission and markets) by October 1, 2004. FERC based their order on PURPA 205(a), which allows FERC to exempt electric utilities from state law or regulation in certain circumstances. An ALJ held hearings on issues including whether the laws, rules, or regulations of Virginia and Kentucky prevent AEP subsidiaries from joining an RTO and whether the exceptions under PURPA 205(a) apply. The FERC ALJ affirmed the FERC's preliminary findings in March 2004. The FERC has not issued a final order in this matter. In April 2004, KPCo reached an agreement with interveners to settle the RTO issues in Kentucky. The KPSC is expected to consider the settlement agreement in May 2004. Litigation - ---------- AEP subsidiaries continue to be involved in various litigation matters as described in the "Significant Factors - Litigation" section of Registrants' Combined Management's Discussion and Analysis in the 2003 Annual Report. The 2003 Annual Report should be read in conjunction with this report in order to understand other litigation matters that did not have significant changes in status since the issuance of the 2003 Annual Report, but may have a material impact on future results of operations, cash flows and financial condition. Other matters described in the 2003 Annual Report that did not have significant changes during the first quarter of 2004, that should be read in order to gain a full understanding of the current litigation include disclosure related to the Texas Commercial Energy, LLP Lawsuit. Federal EPA Complaint and Notice of Violation - --------------------------------------------- See discussion of New Source Review Litigation under "Environmental Matters". Enron Bankruptcy - ---------------- In 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the bankruptcy proceeding 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, AEP purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities from Enron remained unsettled at the date of Enron's bankruptcy. Commodity trading settlement disputes - In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP's offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas related trading transactions. AEP has asserted its right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows or financial condition. In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows or financial condition. Enron bankruptcy summary - The amounts expensed in prior years in connection with the Enron bankruptcy were 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. As noted above, Enron has challenged the offsetting of receivables and payables. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows and financial condition could be material. Energy Market Investigations - ---------------------------- 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 (CFTC), 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 and 2004. On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas in violation of the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and disgorgement of benefits. The case is in the initial pleading stage with our response to the complaint currently due on May 18, 2004. Although management is unable to predict the outcome of this case, AEP recorded a provision in 2003 and the action is not expected to have a material effect on results of operations. In January 2004, the CFTC issued a request for documents and other information in connection with a CFTC investigation of activities affecting the price of natural gas in the fall of 2003. AEP is responding to that request. Management cannot predict whether these governmental agencies will take further action with respect to these matters. Environmental Matters - --------------------- As discussed in the 2003 Annual Report, there are new environmental control requirements that management expects will result in substantial capital investments and operational costs. The sources of these future requirements include: o Legislative and regulatory proposals to adopt stringent controls on sulfur dioxide (SO2), nitrogen oxide (NOx) and mercury emissions from coal-fired power plants, o New Clean Water Act rules to reduce the impacts of water intake structures on aquatic species at certain of our power plants, and o Possible future requirements to reduce carbon dioxide emissions to address concerns about global climatic change. This discussion updates certain events occurring in 2004 and adds estimates of future capital expenditures for the Clean Water Act rule. You should also read the "Significant Factors - Environmental Matters" section within Registrants' Combined Management's Discussion and Analysis in the 2003 Annual Report for a complete description of all material environmental matters affecting us, including, but not limited to, (1) the current air quality regulatory framework, (2) estimated air quality environmental investments, (3) superfund and state remediation, (4) global climate change, and (5) costs for spent nuclear fuel and decommissioning. Future Reduction Requirements for SO2, NOx, and Mercury - ------------------------------------------------------- In 1997, the Federal EPA adopted new, more stringent NAAQS for fine particulate matter and ground-level ozone. The Federal EPA is in the process of developing final designations for fine particulate matter and ground-level ozone non-attainment areas. The Federal EPA finalized designations for ozone non-attainment areas on April 15, 2004. On the same day, the Administrator of the Federal EPA signed a final rule establishing the elements that must be included in state implementation plans (SIPs) to achieve the new standards, and setting deadlines ranging from 2008 to 2015 for achieving compliance with the final standard, based on the severity of non-attainment. All or parts of 474 counties are affected by this new rule, including many urban areas in the Eastern United States. The Federal EPA identified SO2 and NOx emissions as precursors to the formation of fine particulate matter. NOx emissions are also identified as a precursor to the formation of ground-level ozone. As a result, requirements for future reductions in emissions of NOx and SO2 from the AEP System's generating units are highly probable. In addition, the Federal EPA proposed a set of options for future mercury controls at coal-fired power plants. Regulatory Emissions Reductions - ------------------------------- On January 30, 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% each in emissions of SO2, NOx and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components: o The Federal EPA proposed an interstate air quality rule for reducing SO2 and NOx emissions across the eastern half of the United States (29 states and the District of Columbia) to address attainment of the fine particulate matter and ground-level ozone NAAQS. These reductions could also satisfy these states' obligations to make reasonable progress towards the national visibility goal under the regional haze program. o The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units. The interstate air quality rule would require affected states to include, in their SIPs, a program to reduce NOx and SO2 emissions from coal-fired electric utility units. SO2 and NOx emissions would be reduced in two phases, which would be implemented through a cap-and-trade program. Regional SO2 emissions would be reduced to 3.9 million tons by 2010 and to 2.7 million tons by 2015. Regional NOx emissions would be reduced to 1.6 million tons by 2010 and to 1.3 million tons by 2015. Rules to implement the SO2 and NOx trading programs have not yet been proposed. On April 15, 2004, the Federal EPA Administrator signed a proposed rule detailing how states should analyze and include "Best Available Retrofit" requirements for individual facilities in their SIPs to address regional haze. The guidance applies to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain regulated pollutants in specific industrial categories, including utility boilers. The Federal EPA included an alternative "Best Available Retrofit" program based on emissions budgeting and trading programs. For utility units that are affected by the January 24, 2004 Interstate Air Quality Rule (IAQR), described above, the Federal EPA proposed that participation in the trading program under the IAQR would satisfy any applicable "Best Available Retrofit" requirements. To control and reduce mercury emissions, the Federal EPA published two alternative proposals. The first option requires the installation of maximum achievable control technology (MACT) on a site-specific basis. Mercury emissions would be reduced from 48 tons to approximately 34 tons by 2008. The Federal EPA believes, and the industry concurs, that there are no commercially available mercury control technologies in the marketplace today that can achieve the MACT standards for bituminous coals, but certain units have achieved comparable levels of mercury reduction by installing conventional SO2 (scrubbers) and NOx (SCR) emission reduction technologies. The proposed rule imposes significantly less stringent standards on generating plants that burn sub-bituminous coal or lignite, which standards potentially could be met without installation of mercury control technologies. The Federal EPA recommends, and AEP supports, a second mercury emission reduction option. The second option would permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. This approach would coordinate the reduction requirements for mercury with the SO2 and NOx reduction requirements imposed on the same sources under the proposed interstate air quality rule. Coordination is significantly more cost-effective because technologies like scrubbers and SCRs, which can be used to comply with the more stringent SO2 and NOx requirements, have also proven highly effective in reducing mercury emissions on certain coal-fired units that burn bituminous coal. The second option contemplates reducing mercury emissions from 48 million tons to 34 million tons by 2010 and to 15 million tons by 2018. A supplemental proposal including unit-specific allocations and a framework for the emissions budgeting and trading program preferred by the Federal EPA was published in the Federal Register on March 16, 2004. Comments on both the initial proposal and the supplemental notice are due on or before June 29, 2004. The Federal EPA's proposals are the beginning of a lengthy rulemaking process, which will involve supplemental proposals on many details of the new regulatory programs, written comments and public hearings, issuance of final rules, and potential litigation. In addition, states have substantial discretion in developing their rules to implement cap-and-trade programs, and will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. As a result, the ultimate requirements may not be known for several years and may depart significantly from the original proposed rules described here. While uncertainty remains as to whether future emission reduction requirements will result from new legislation or regulation, it is certain under either outcome that AEP subsidiaries will invest in additional conventional pollution control technology on a major portion of their coal-fired power plants. Finalization of new requirements for further SO2, NOx and/or mercury emission reductions will result in the installation of additional scrubbers, SCR systems and/or the installation of emerging technologies for mercury control. New Source Review Litigation - ---------------------------- Under the Clean Air Act (CAA), 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 Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and other unaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the CAA. The Federal EPA filed its complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications relate to costs that were incurred at the generating units 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 CAA proceedings. Management is also 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. If 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. Clean Water Act Regulation - -------------------------- On February 16, 2004, the Federal EPA signed a rule pursuant to the Clean Water Act that will require all large existing, once-through cooled power plants to meet certain performance standards to reduce the mortality of juvenile and adult fish or other larger organisms pinned against a plant's cooling water intake screens. All plants must reduce fish mortality by 80% to 95%. A subset of these plants that are located on sensitive water bodies will be required to meet additional performance standards for reducing the number of smaller organisms passing through the water screens and the cooling system. These plants must reduce the rate of smaller organisms passing through the plant by 60% to 90%. Sensitive water bodies are defined as oceans, estuaries, the Great Lakes, and small rivers with large plants. These rules will result in additional capital and operation and maintenance expenses to ensure compliance. The capital cost of compliance for the AEP System's facilities, based on the Federal EPA's estimates in the rule, is $193 million. Any capital costs associated with compliance activities to meet the new performance standards would likely be incurred during the years 2008 through 2010. Management has not independently confirmed the accuracy of the Federal EPA's estimate. The rule has provisions to limit compliance costs. Management may propose less costly site-specific performance criteria if compliance cost estimates are significantly greater than the Federal EPA's estimates or greater than the environmental benefits. The rule also allows for mitigation (also called restoration measures) if it is less costly and has equivalent or superior environmental benefits than meeting the criteria in whole or in part. The following table shows the investment amount per subsidiary. Estimated Compliance Investments ----------- (in millions) APCo $21 CSPCo 19 I&M 118 OPCo 31 Other Matters - ------------- As discussed in the 2003 Annual Report, there are several "Other Matters" affecting AEP subsidiaries, including FERC's proposed standard market design and FERC's market power mitigation efforts. These were no significant changes to the status of FERC's proposed standard market design. The current status of FERC's market power mitigation efforts is described below. FERC Market Power Mitigation - ---------------------------- A FERC order issued in November 2001 on AEP's triennial market-based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power system's status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. AEP and two unaffiliated utilities were required to submit generation market power analyses within sixty days of the FERC's order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. Management is unable to predict the outcome of these actions by the FERC or their affect on future results of operations and cash flows. CONTROLS AND PROCEDURES During the first quarter of 2004, AEP's management, including the principal executive officer and principal financial officer, evaluated AEP's disclosure controls and procedures relating 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 March 31, 2004, these officers concluded that the disclosure controls and procedures in place provide reasonable assurance that the disclosure controls and procedures accomplished 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 events warrant. There have been no changes in AEP's internal controls over financial reporting (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) during the first quarter of 2004 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 5, Commitments and Contingencies, incorporated herein by reference. Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities --------------------------------------------------------------------- The following table provides information about purchases by AEP (or its publicly-traded subsidiaries) during the quarter ended March 31, 2004 of equity securities that are registered by AEP (or its publicly-traded subsidiaries) pursuant to Section 12 of the Exchange Act:

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: The following reports on Form 8-K were filed during the quarter ended March 31, 2004.

SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/Joseph M. Buonaiuto ---------------------- Joseph M. Buonaiuto Controller and Chief Accounting Officer AEP 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/Joseph M. Buonaiuto ---------------------- Joseph M. Buonaiuto Controller and Chief Accounting Officer Date: May 7, 2004 EX-12 2 aepex12.htm EXHIBIT 12

EXHIBIT 12

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in millions except ratio data)

	Year Ended December 31,					Twelve Months Ended
	1999	2000	2001	2002	2003	3/31/04
Fixed Charges:
Interest on Long-term Debt	$608	$608	$599	$642	$735	$738
Interest on Short-term Debt	149	258	143	62	23	20
Miscellaneous Interest Charges	78	161	133	103	80	89
Estimated Interest Element in Lease Rentals	212	223	222	229	203	203
Preferred Stock Dividends	28	32	15	18	15	12

Total Fixed Charges	$1,075	$1,282	$1,112	$1,054	$1,056	$1,062

Earnings:
Income Before Income Taxes	$1,327	$779	$1,513	$800	$880	$844
Plus Fixed Charges (as above)	1,075	1,282	1,112	1,054	1,056	1,062
Less Undistributed Earnings in Equity Investments	46	46	28	12	10	16

Total Earnings	$2,356	$2,015	$2,597	$1,842	$1,926	$1,890

Ratio of Earnings to Fixed Charges	2.19	1.57	2.33	1.74	1.82	1.77

EX-31 3 exh31-1.htm EXHIBIT 31.1

EXHIBIT 31.1
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Michael G. Morris, certify that:

1. I have reviewed this report on Form 10-Q of:

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
Southwestern Electric Power Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15e and 15d-15e) for the registrant and have:

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2004

By: /s/ Michael G. Morris

Michael G. Morris
Chief Executive Officer

EX-31 4 exh31-2.htm EXHIBIT 31.2

EXHIBIT 31.2
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Susan Tomasky, certify that:

1. I have reviewed this report on Form 10-Q of:

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15e and 15d-15e) for the registrant and have:

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2004

By: /s/ Susan Tomasky

Susan Tomasky
Chief Financial Officer

EX-32 5 exh32-1.htm EXHIBIT 32.1

Exhibit 32.1

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of the Companies (as defined below) on Form 10-Q for the quarterly period ended March 31, 2004 as filed with the Securities and Exchange Commission on the date hereof (the “Reports”), I, Michael G. Morris, the chief executive officer of

(the “Companies”), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002 that, based on my knowledge (i) the Reports fully comply with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Reports fairly presents, in all material respects, the financial condition and results of operations of the Companies.

/s/ Michael G. Morris

Michael G. Morris
May 7, 2004

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32 6 exh32-2.htm EXHIBIT 32.2

Exhibit 32.2

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

/s/ Susan Tomasky

Susan Tomasky
May 7, 2004

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