ThZeal - The Zeal

10-Q 1 xq102mod.txt COMBINED 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended MARCH 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Transition Period from to

AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company, Public Service Company of Oklahoma and West Texas Utilities Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No -------- -------- The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at April 30, 2002 was 322,822,489.

This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, Appalachian Power Company, Central Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants. GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

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 subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: o Electric load and customer growth. o Abnormal weather conditions. o Available sources and costs of fuels. o Availability of generating capacity. o The speed and degree to which competition is introduced to our power generation business. o The structure and timing of a competitive market and its impact on energy prices or fixed rates. o The ability to recover stranded costs in connection with possible/proposed deregulation of generation. o New legislation and government regulations. o The ability of AEP to successfully control its costs. o The success of new business ventures. o International developments affecting AEP's foreign investments. o The economic climate and growth in AEP's service territory. o Inflationary trends. o Electricity and gas market prices. o Interest rates o Other risks and unforeseen events. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 American Electric Power Company, Inc.'s (AEP) principal operating business segments and their major activities are: o Wholesale o Generation of electricity for sale to retail and wholesale customers o Gas pipeline and storage services o Marketing and trading of electricity, gas and coal o Coal mining, bulk commodity barging operations and other energy supply related business. o Energy Delivery o Domestic electricity transmission, o Domestic electricity distribution o Other Investments o Foreign electric distribution and supply investments, o Telecommunication services. Net Income First quarter 2002 net income of $181 million or $0.56 per share was down 32% from last year's earnings of $266 million or $0.83 per share. Unfavorable market conditions and the effect of a March 2001 gain on the sale of the Frontera power plant caused the earnings decline. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Domestic Gas Pipeline and Storage Activities - We recognize revenues from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided. Transportation and storage revenues also include the accrual of earned, but unbilled and/or not yet metered gas. Energy Marketing and Trading Activities - We engage in non-regulated wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased energy expense for a purchase. Therefore, over the term of a trading contract an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading and derivative contract assets or liabilities. The majority of our trading activities represent physical forward electricity and gas contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity or gas in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and the realized cost is included in purchased energy expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity or gas in July. If we do nothing else with these contracts until settlement in July and if the commodity type, volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on operating results but has an offsetting and equal effect on trading contract assets and liabilities. Of course we could have also done a similar transaction but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to commodity type, volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. Trading of electricity and gas options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in revenues until the contracts settle. When these contracts settle, we record the net proceeds in revenues and reverse to revenues the prior cumulative unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on Company-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the Company-developed price models. This is particularly true for long-term contracts. We also mark-to-market derivatives that are not trading contracts in accordance with generally accepted accounting principles. Derivatives are contracts whose value is derived from the market value of an underlying commodity. As stated above, AEP records and reports upon settlement sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expense. If settled forward sale and purchase contracts were reported on a net basis, the amounts of revenues and purchased energy expense reported would have been:

We defer as regulatory assets or liabilities the effect on net income of marking to market open forward electricity trading contracts in our regulated jurisdictions since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Changes in mark-to-market valuations impact net income in our non-regulated gas and electricity business. Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk and causing our results of operations to be subject to volatility. See "Quantitative and Qualitative Disclosures Market Risks" section of this report for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities. RESULTS OF OPERATIONS Net income for the first quarter of 2002 decreased by $85 million from last year's results due to the effects of the sale of Frontera power plant in the first quarter of 2001 and strong performance last year from the wholesale business reflecting market conditions that were more favorable than in 2002. Lower energy demand in the first quarter of 2002 depressed margins from wholesale electric and gas marketing and trading. In March 2001 we completed the sale of Frontera, one of the generating plants required to be divested under the FERC approved merger settlement agreements. The sale resulted in a $46 million after tax gain. Increase (Decrease) (in millions) % - Revenues: Electric Marketing and Trading $(748) (8) Gas Marketing and Trading (15) - Domestic Electricity Delivery 9 1 Other Investments (67) (12) --- $(821) (6) ===== The decline in revenues is mainly due to a decrease in electric marketing and trading revenues. The decrease was driven largely by a decline in demand due to mild weather and the slow recovery from the economic recession. Heating degree days for the first quarter of 2002 were down 13.2 % from the same quarter last year. Electricity sales to industrial customers decreased 7.1% from the same period last year. The increase in gas trading volume can be attributed to the acquisition of Houston Pipe Line (HPL) and expansion of our gas trading operations around the pipeline. Revenues from other investments declined due to a decrease in SEEBOARD revenues resulting from regulator imposed price reductions. Increase (Decrease) (in millions) % - Fuel and Purchased Energy Expense: Electric Marketing and Trading $(932) (11) Gas Marketing and Trading 135 4 Other Investments 2 1 - Total Fuel and Purchased Energy Expense (795) (7) Maintenance and Other Operation Expense 84 9 Depreciation and Amortization Expense 23 7 Taxes Other Than Income Taxes 18 11 -- Total Operating Expenses $(670) (5) ===== The decrease in fuel and purchased energy expense was primarily attributable to a reduction in power generation and purchases and lower fuel costs reflecting lower market prices than in the first quarter of 2001. Net generation decreased 5% from last year due to the reduced demand for electricity and planned maintenance outages for various plants. The cost of purchased power for resale was also lower due to reduced demand, a continuation of the market conditions that developed in the fourth quarter of 2001. The increase in gas marketing and trading purchased energy expense was primarily due to the acquisition of HPL and expansion of gas trading activity around the pipeline. Maintenance and other operation expense increased largely as a result of material and labor costs incurred in connection with the construction of gas-fired plants for third parties plus the expenses of MEMCO, a barging line; Quaker Coal; and two power plants in the UK, all recently acquired businesses. These cost increases were partially offset by a reduction in trading incentive compensation. Project fees for the construction of gas-fired plants for third parties are recognized in revenues on a percentage of completion method, consequently, the charges to expense for material and labor costs do not adversely affect net income. Other income decreased due to the gain from the sale of Frontera in 2001. Other expenses increased due to a write off of goodwill on Gas Power Systems resulting from management's decision to exit the business (See Note 2). The decrease in income taxes is predominately due to a decrease in pre-tax income and changes in certain book/tax timing differences accounted for on a flow-through basis. The decrease in interest was primarily due to a decrease in the outstanding balance of long-term debt since the first quarter of 2001, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.

AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies pursuant to FERC approved long-term unit power agreements. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Net income declined $87,000 for the first quarter. A decrease in operating revenues of $10,632,000 resulted from a decrease in recoverable expenses, primarily fuel, as generation declined due to a decrease in the Rockport Plant's availability. Outages for planned maintenance at both units in 2002 decreased the Rockport Plant's generation by 32%. Operating expenses declined 18% as follows: Increase (Decrease) ------------------- (in thousands) % -------------- - Fuel $(10,145) (37) Rent - Rockport Plant Unit 2 - - Other Operation 264 9 Maintenance 1,050 55 Depreciation 47 1 Taxes Other Than Income Taxes 10 1 Income Taxes (1,818) (74) -------- Total $(10,592) (18) ======== Fuel expense decreased due to the decline in generation. The increase in other operation expense is primarily due to higher costs for employee benefits and property insurance. Maintenance expense increased due to planned outages in 2002. The decrease in income taxes attributable to operations is primarily due to an over-accrual of state income taxes based on an estimate of higher taxable income for the year 2001 than actually occurred. The over-accrual was adjusted later in 2001.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 917,000 retail customers in southwestern Virginia and southern West Virginia. APCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. APCo also sells wholesale power to municipalities. The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to APCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on APCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior cumulative unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing APCo to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $6.4 million or 10% mainly due to the effect of strong performance in 2001 by the wholesale business reflecting market conditions that were more favorable than in 2002. Lower electricity demand in the first quarter of 2002 depressed margins from wholesale electric marketing and trading. APCo, as a member of the AEP Power Pool, shares in the revenues and costs of wholesale marketing and trading activities conducted on its behalf by the AEP Power Pool. The following analyzes the changes in operating revenues: Increase (Decrease) (in millions) % Electricity Marketing $(517) (29) and Trading* Energy Delivery* 3 2 Sales to AEP Affiliates (5) (11) ----- Total $(519) (26) ===== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in revenues was due primarily to reduced margins caused by decreased electricity demand driven largely by mild weather and the slow recovery from the economic recession. Sales to AEP affiliates declined as a result of the mild weather and economic conditions that reduced electricity sales. Operating expenses declined 27% in 2002. The changes in the components of operating expenses were: Increase (Decrease) ------------------- (in millions) % ------------- - Fuel $ 12 13 Electricity Marketing and Trading Purchases (474) (32) Purchases from AEP Affiliates (45) (42) Other Operation 2 2 Maintenance (7) (22) Depreciation and Amortization 3 7 Taxes Other Than Income Taxes - - Income Taxes (3) (7) ----- Total $(512) (27) ===== Fuel expense increased due to an increase in electric generation as certain plants that had undergone boiler plant maintenance in the first quarter of 2001 were available for service in the first quarter of 2002. The decline in electricity marketing and trading purchases was mainly due to reduced prices caused by decreased electricity demand driven largely by mild weather and the economic recession. The decrease in maintenance expense is due to the effect of boiler plant maintenance performed on certain plants in the first quarter of 2001. Depreciation and amortization expense increased due to the additional accelerated amortization beginning in July 2001 of transition regulatory assets in connection with the discontinuance of SFAS 71 in the Company's West Virginia jurisdiction whereby net generation-related regulatory assets were transferred to the distribution portion of the business commensurate with their recovery through regulated rates (see Note 5 for further discussion of the effects of restructuring). Additional investments in distribution and production plant also contributed to the increase in depreciation and amortization expense. The decrease in income taxes from operations was due to a decrease in pre-tax operating income. Nonoperating income and expense decreased largely due to reduced margins on electricity trading outside of AEP's traditional marketing area caused by decreased electricity demand resulting from mild weather and the slow recovery from the economic recession. Interest charges decreased due primarily to increased allowances for borrowed funds as a result of increased construction expenditures and the retirement of first mortgage bonds on March 1, 2001 and the retirement of senior unsecured notes in June 2001. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $1,257,355 $1,773,894 Energy Delivery 154,995 152,097 Sales to AEP Affiliates 42,806 48,136 ---------- ---------- TOTAL OPERATING REVENUES 1,455,156 1,974,127 ---------- ---------- OPERATING EXPENSES: Fuel 107,490 95,476 Purchased Power: Electricity Marketing and Trading 1,005,599 1,479,528 AEP Affiliates 60,780 105,674 Other Operation 67,427 65,889 Maintenance 25,851 33,009 Depreciation and Amortization 46,772 43,717 Taxes Other Than Income Taxes 24,995 25,428 Income Taxes 34,688 37,254 ---------- ---------- TOTAL OPERATING EXPENSES 1,373,602 1,885,975 ---------- ---------- OPERATING INCOME 81,554 88,152 NONOPERATING INCOME 400,172 465,405 NONOPERATING EXPENSES 398,733 458,205 NONOPERATING INCOME TAX EXPENSE 264 2,149 INTEREST CHARGES 27,388 31,416 ---------- ---------- NET INCOME 55,341 61,787 PREFERRED STOCK DIVIDEND REQUIREMENTS 503 503 ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 54,838 $ 61,284 ========== ========== CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) NET INCOME $55,341 $61,787 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge 143 (417) ------- ------- COMPREHENSIVE INCOME $55,484 $61,370 ======= ======= The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $150,797 $120,584 NET INCOME 55,341 61,787 DEDUCTIONS: Cash Dividends Declared: Common Stock 30,984 32,399 Cumulative Preferred Stock 361 361 Capital Stock Expense 142 142 -------- -------- BALANCE AT END OF PERIOD $174,651 $149,469 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2002 December 31, 2001 -------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $2,084,311 $2,093,532 Transmission 1,212,470 1,222,226 Distribution 1,889,828 1,887,020 General 260,110 257,957 Construction Work in Progress 267,720 203,922 ---------- ---------- Total Electric Utility Plant 5,714,439 5,664,657 Accumulated Depreciation and Amortization 2,326,515 2,296,481 ---------- ---------- NET ELECTRIC UTILITY PLANT 3,387,924 3,368,176 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 51,497 53,736 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 521,221 316,249 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents - 13,663 Accounts Receivable: Customers 120,599 113,371 Affiliated Companies 98,805 63,368 Miscellaneous 20,983 11,847 Allowance for Uncollectible Accounts (2,259) (1,877) Fuel - at average cost 50,582 56,699 Materials and Supplies - at average cost 53,307 59,849 Accrued Utility Revenues 23,894 30,907 Energy Trading Contracts 766,378 566,284 Prepayments 21,694 16,018 ---------- ---------- TOTAL CURRENT ASSETS 1,153,983 930,129 ---------- ---------- REGULATORY ASSETS 391,518 397,383 ---------- ---------- DEFERRED CHARGES 45,939 42,265 ---------- ---------- TOTAL ASSETS $5,552,082 $5,107,938 ========== ========== See Notes to Financial Statements beginning on page L-1.

CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 CPL is a public utility engaged in the generation, sale, transmission and distribution of electric power in southern Texas. CPL also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to retail electric providers (REPs) in Texas, (see "Introduction of Customer Choice" section below). Wholesale power marketing and trading activities are conducted on CPL's behalf by AEPSC. CPL shares in the revenues and costs of forward trades with other utility systems and power marketers. Introduction of Customer Choice ------------------------------- On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. CPL currently operates in the ERCOT region of Texas. Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into a retail electric provider, a power generator, and a transmission and distribution utility. During the year 2000, CPL submitted a plan for separation that was subsequently approved by the PUCT. As a result of this legislation, CPL has functionally separated its generation from its transmission and distribution operations and formed a separate REP. Pending regulatory approval, CPL will corporately separate its generation from its transmission and distribution operations. The REP is a separate legal entity that is a subsidiary of AEP and is not owned by or consolidated with CPL. Since the REP is the electricity supplier to retail customers in the ERCOT area, CPL sells its generation to the REP and provides transmission and distribution services to retail customers in its ERCOT service territory. As a result of the formation of the REP, CPL no longer supplies electricity to retail customers in the ERCOT area. Instead CPL sells its generation to the REP. The implementation of REPs as suppliers to retail customers has caused a significant shift in CPL's sales as described below under "Results of Operations." Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to CPL. Trading activities allocated to CPL involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased power expense for a purchase. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize our share of a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and the realized cost is included in purchased power expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing CPL to market risk. See "Quantitative and Qualitative Disclosure About Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $10.6 million, or 30%, primarily due to mild winter weather and a slow recovery from the economic recession. Operating revenues decreased $200 million for the quarter as shown below: Increase (Decrease) (in millions) % Electricity Marketing and Trading* $(361) (76) Energy Delivery* 2 2 Sales to AEP Affiliates 159 N.M. ----- Total $(200) (33) ===== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. N.M. = Not Meaningful Electricity marketing and trading revenues decreased $361 million as a result of several factors, including the elimination of retail sales in the ERCOT area as of January 1, 2002, a decrease in energy trading, and mild winter weather. The significant increase in Sales to AEP Affiliates is due to the introduction on January 1, 2002 of customer choice of electricity supplier which resulted in CPL selling power at wholesale to a new affiliated REP. Operating expenses declined 36% in 2002. The changes in the components of operating expenses were: Increase (Decrease) ------------------- (in millions) % ------------- - Fuel $ (98) (64) Electricity Marketing and Trading Purchases (73) (36) Purchases from AEP Affiliates (5) (38) Other Operation (9) (12) Maintenance (6) (37) Depreciation and Amortization - - Taxes Other Than Income Taxes 8 43 Income Taxes (8) (44) ----- Total $(191) (36) ===== Fuel expense decreased due to a decrease in the average unit cost of fuel resulting from lower spot market natural gas prices. Electricity marketing and trading purchases decreased due to a decline in demand for electricity due to the slow economic recovery and the mild winter weather. The decrease in maintenance and other operation expenses resulted from the effects of a STP nuclear refueling outage in 2001. Taxes other than income taxes increased due to the effect of a favorable accrual adjustment in 2001 for ad valorem taxes. The decrease in income tax expense attributable to operations in 2002 was primarily due to a decrease in pre-tax operating income. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) OPERATING REVENUES: Electric Marketing and Trading $111,435 $472,294 Energy Delivery 112,127 110,330 Sales to Affiliates 179,661 20,788 -------- -------- Total Operating Revenues 403,223 603,412 -------- -------- OPERATING EXPENSES: Fuel 54,328 151,853 Purchased Power: Electric Marketing and Trading 128,325 201,796 Affiliates 7,927 12,770 Other Operation 65,986 75,071 Maintenance 10,959 17,287 Depreciation and Amortization 41,847 42,391 Taxes Other Than Income Taxes 27,922 19,488 Income Taxes 10,484 18,604 -------- -------- TOTAL OPERATING EXPENSES 347,778 539,260 -------- -------- OPERATING INCOME 55,445 64,152 NONOPERATING INCOME 9,531 3,199 NONOPERATING EXPENSES 9,387 837 NONOPERATING INCOME TAX EXPENSE 133 723 INTEREST CHARGES 31,011 30,760 -------- -------- NET INCOME 24,445 35,031 PREFERRED STOCK DIVIDEND REQUIREMENTS 60 60 -------- -------- EARNINGS APPLICABLE TO COMMON STOCK $ 24,385 $ 34,971 ======== ======== CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $826,197 $792,219 NET INCOME 24,445 35,031 DEDUCTIONS: Cash Dividends Declared: Common Stock 38,502 37,014 Preferred Stock 60 60 Other - 1 -------- -------- BALANCE AT END OF PERIOD $812,080 $790,175 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $18,505,000 and $24,938,000 and for income taxes was $18,482,000 and $6,071,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 Columbus Southern Power Company is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 678,000 retail customers in central and southern Ohio. CSPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. CSPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to CSPCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of a gain or loss in cash and reverse the previously recorded cumulative unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on CSPCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior cumulative unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing CSPCo to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $3.8 million or 10% due to depressed margins from electric marketing and trading caused by lower energy demand in the first quarter of 2002. Earnings from electric marketing and trading were much stronger in the first quarter of 2001 than in recent months due to milder weather and the slow recovery from the economic recession. The decline in revenues is mainly due to a decrease in electric marketing and trading revenues. The following analyzes the changes in operating revenues: Increase (Decrease) (in millions) % Electricity Marketing And Trading* $(168.7) (17) Energy Delivery* 3.6 4 Sales to AEP Affiliates (11.1) (59) ------- Total $(176.2) (16) ======= *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in electric marketing and trading was driven largely by a decline in demand due to mild winter weather and the slow recovery from the economic recession. Heating degree days for the first quarter of 2002 were down 11.8% from the same quarter last year. Electricity sales to industrial customers decreased 4%. Operating expenses declined 16% in 2002. The changes in the components of operating expenses were: Increase (Decrease) ------------------- (in millions) % ------------- - Fuel $ (1.4) (3) Electricity Marketing and Trading Purchases (161.7) (20) Purchases from AEP Affiliates (0.7) (1) Other Operation (0.4) (1) Maintenance (4.6) (25) Depreciation and Amortization 1.3 4 Taxes Other Than Income Taxes (0.4) (1) Income Taxes (5.8) (25) ------- Total $(173.7) (16) ======= The decrease in fuel expense was primarily attributable to a reduction in generation of 4.6% due to the reduced demand for electricity. Electricity marketing and trading purchases also declined due to reduced demand, a continuation of the market conditions that developed in the fourth quarter of 2001. Maintenance expenses decreased in the first quarter of 2002 due to boiler overhaul work that was performed during the first quarter of 2001. Expenses for maintaining distribution overhead lines and underground lines were also lower in 2002. A decrease in pre-tax operating income caused income taxes attributable to operations to decline. The increase in nonoperating income which was offset by a larger increase in non-operating expenses was due to a reduction in net gains from AEP Power Pool trading transactions outside of the AEP System's traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. The Company's share of the AEP Power Pool's gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in nonoperating income and expense. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand reflecting milder weather and the slow economic recovery. The decrease in interest was primarily due to a decrease in the outstanding balance of long-term debt since the first quarter of 2001, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $ 839,089 $1,007,831 Energy Delivery 102,548 98,996 Sales to AEP Affiliates 7,678 18,746 ---------- ---------- TOTAL OPERATING REVENUES 949,315 1,125,573 ---------- ---------- OPERATING EXPENSES: Fuel 45,650 47,030 Purchased Power: Electricity Marketing and Trading 637,921 799,639 AEP Affiliates 71,582 72,272 Other Operation 54,158 54,548 Maintenance 14,140 18,780 Depreciation and Amortization 32,736 31,482 Taxes Other Than Income Taxes 30,276 30,687 Income Taxes 17,304 23,020 ---------- ---------- TOTAL OPERATING EXPENSES 903,767 1,077,458 ---------- ---------- OPERATING INCOME 45,548 48,115 NONOPERATING INCOME 257,578 252,846 NONOPERATING EXPENSES 254,023 247,690 NONOPERATING INCOME TAX EXPENSE (CREDIT) 1,452 (2,133) INTEREST CHARGES 13,793 17,733 ---------- ---------- NET INCOME 33,858 37,671 PREFERRED STOCK DIVIDEND REQUIREMENTS 181 302 ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 33,677 $ 37,369 ========== ========== CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $176,103 $ 99,069 NET INCOME 33,858 37,671 DEDUCTIONS: Cash Dividends Declared: Common Stock 21,766 20,738 Cumulative Preferred Stock 175 262 Capital Stock Expense 254 254 -------- -------- BALANCE AT END OF PERIOD $187,766 $115,486 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $9,725,000 and $6,127,000 and for income taxes was $11,198,000 and $17,485,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $84,000 in 2001. See Notes to Financial Statements beginning on page L-1. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 567,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers including power trading transactions. I&M also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs. I&M is committed under unit power agreements to purchase all of AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to KPCo through 2004. Therefore, I&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, I&M's consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to I&M as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. The majority of trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting physical contracts. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contracts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since I&M is a cost-based rate-regulated entity, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). The deferral reflects the fact that power sales and purchases are included in regulated rates on a settlement basis. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. The change in the fair value of physical forward sale and purchase contracts outside AEP's traditional marketing area is included in nonoperating income on a net basis. Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred for contracts with delivery points in AEP's traditional marketing area and for contracts with delivery points outside of AEP's traditional marketing area the unrealized gain or loss is recognized as nonoperating income. When the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash is recognized in the income statement. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contacts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized in the income statement. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior cumulative unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing I&M to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $21 million or 66% due primarily to a reduction in generation as a result of a refueling outage at one unit of I&M's Cook Plant, maintenance outages at Rockport Plant and lower margins on electricity sales. Operating revenues decreased 20% due to decreased wholesale marketing and trading prices and the decline in generation due to power plant outages. The following analyzes the changes in operating revenues: Increase (Decrease) (in millions) % Electricity Marketing $(225.6) (20) and Trading* Energy Delivery* (3.4) (4) Sales to AEP Affiliates (23.8) (33) ------- Total $(252.8) (20) ======= *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in electricity marketing and trading revenues was due to a decline in wholesale prices reflecting soft demand caused by the slow economic recovery and mild winter weather. Revenues from sales to AEP affiliates declined significantly reflecting less power being available for sale as one unit of the Cook Nuclear Plant was shutdown for refueling and both units of Rockport Plant were scheduled for planned boiler maintenance. AEP Power Pool members are compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. With the outages in 2002, I&M's available generation declined resulting in less power being delivered to the AEP Power Pool. Operating expenses declined 19% in 2002. The changes in the components of operating expenses were: Increase (Decrease) ------------------- (in millions) % ------------- - Fuel $ (9.8) (15) Electricity Marketing and Trading Purchases (216.2) (24) Purchases from AEP Affiliates (10.0) (16) Other Operation 14.4 15 Maintenance 2.9 10 Depreciation and Amortization 1.1 3 Taxes Other Than Income Taxes - - Income Taxes (12.8) (68) ------- Total $(230.4) (19) ======= Fuel expense decreased primarily due to the decline in generation reflecting the plant outages, mild winter weather and a slow economic recovery. The decrease in electricity marketing and trading purchases resulted mainly from the decrease in energy prices. Purchases from AEP affiliates declined due to the Rockport Plant outages as I&M is required to purchase AEGCo's Rockport Plant generation under their unit power agreement. Other operation expense increased due to higher costs resulting from the generating plants outages, property insurance and employee benefit costs. The increase in maintenance expense is primarily due to costs related to the outages. Income tax expense attributable to operations decreased significantly due primarily to a decline in pre-tax operating income. The decrease in nonoperating income and nonoperating expenses is due to lower prices for power sold and purchased outside of AEP's traditional marketing area reflecting reduced demand. The decrease in nonoperating income tax expense reflects a decline in pre-tax nonoperating income. Interest charges decreased due to a decline in short-term rates and lower outstanding borrowings. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $ 917,013 $1,142,617 Energy Delivery 74,537 77,937 Sales to AEP Affiliates 47,209 70,984 ---------- ---------- TOTAL OPERATING REVENUES 1,038,759 1,291,538 ---------- ---------- OPERATING EXPENSES: Fuel 54,156 63,973 Purchased Power: Electricity Marketing and Trading 691,806 908,039 AEP Affiliates 53,507 63,548 Other Operation 111,766 97,363 Maintenance 31,043 28,175 Depreciation and Amortization 41,866 40,723 Taxes Other Than Income Taxes 18,241 18,238 Income Taxes 6,011 18,781 ---------- ---------- TOTAL OPERATING EXPENSES 1,008,396 1,238,840 ---------- ---------- OPERATING INCOME 30,363 52,698 NONOPERATING INCOME 295,185 302,274 NONOPERATING EXPENSES 291,491 295,714 NONOPERATING INCOME TAX EXPENSE (CREDIT) (425) 2,115 INTEREST CHARGES 23,424 24,780 ---------- ---------- NET INCOME 11,058 32,363 PREFERRED STOCK DIVIDEND REQUIREMENTS 1,155 1,155 ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 9,903 $ 31,208 ========== ========== CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) NET INCOME $11,058 $32,363 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge 1,259 (1,919) ------- ------- COMPREHENSIVE INCOME $12,317 $30,444 ======= ======= The common stock of I&M is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $74,605 $ 3,443 NET INCOME 11,058 32,363 DEDUCTIONS: Cash Dividends Declared - Cumulative Preferred Stock 1,122 1,122 Capital Stock Expense 33 33 ------- ------- BALANCE AT END OF PERIOD $84,508 $34,651 ======= ======= See Notes to Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $15,090,000 and $21,610,000 and for income taxes was $(470,000) and $7,471,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $991,000 in 2001. See Notes to Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 172,000 retail customers in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. KPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, KPCo's financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to KPCO as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. The majority of trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting physical contracts. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contacts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since KPCO is a cost-based rate-regulated entity, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). AEP's traditional marketing area is up to two transmission systems from the AEP Service territory. The change in the fair value of physical forward sale and purchase contracts outside AEP's traditional marketing area is included in nonoperating income on a net basis. Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred for contracts with delivery points in AEP's traditional marketing area and for contracts with delivery points outside of AEP's traditional marketing area the unrealized gain or loss is recognized as nonoperating income. When the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash is recognized in the income statement. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contacts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized in the income statement. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading assets or liabilities. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the cumulative prior unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing KPCO to market risk. See "Quantitative and Qualitative Disclosures About Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Decreases in revenues were offset by sharper decreases in operating expenses which resulted in an increase in net income of $3 million or 45%. The following analyzes the changes in operating revenues: Increase (Decrease) (in millions) % Electricity Marketing And Trading* $(103) (25) Energy Delivery* (1) (3) Sales to AEP Affiliates (4) (38) ----- Total $(108) (23) ===== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in revenues is due primarily to a decrease in electricity trading prices and mild winter weather. In the first quarter of 2002 the AEP Power Pool grew its electric trading business resulting in a significant increase in the number of forward electricity contracts entered into AEP's traditional marketing area (up to two transmission systems from AEP's service territory). This growth in volume was offset by reduced demand which lowered selling prices and margins. Depressed prices were experienced in both trading and wholesale sales, resulting in an overall decrease in revenues due to mild weather and a slow recovery from the economic recession. Retail activity for the period was comparable to that of the same period last year. Changes in the components of operating expenses were: Increase (Decrease) ------------------- (in millions) % ------------- - Fuel $ 4 21 Electricity Marketing and Trading Purchases (106) (30) Purchases from AEP Affiliates (7) (19) Other Operation (2) (15) Maintenance (1) (16) ----- Total $(112) (25) ===== Fuel expense increased due to difficulties experienced by one of the Company's main coal suppliers forcing KPCo to go to the open market to address shortfalls in supply at higher prices in the coal spot market. Management is exploring opportunities for alternative suppliers and contracted rates. Purchased power expense decreases were primarily attributable to lower prices resulting from mild winter weather and declining demand for electricity. Other operation expense decreased due to a decrease in trading incentive cost accruals. Maintenance expense decreased as a result of adjustments to labor force and contractor support, the latter being converted to an "as needed" versus full time basis. The decrease in nonoperating income and expenses was due to a decrease in power trading revenues and purchases from non-regulated AEP Power Pool trading transactions outside of the AEP System's traditional marketing area. As with power trading activity within the traditional marketing areas, non-regulated trading transactions also experienced declining prices due to reduced demand and mild weather. KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) OPERATING REVENUES: Electric Marketing and Trading $310,157 $413,133 Energy Delivery 35,129 36,327 Sales to AEP Affiliates 6,022 9,697 -------- -------- TOTAL OPERATING REVENUES 351,308 459,157 -------- -------- OPERATING EXPENSES: Fuel 21,767 17,956 Purchased Power Electricity Marketing and Trading 252,005 358,230 AEP Affiliates 28,941 35,635 Other Operation 12,469 14,728 Maintenance 4,549 5,429 Depreciation and Amortization 8,257 8,027 Taxes Other Than Income Taxes 2,135 2,049 Income Taxes 5,701 5,834 -------- -------- TOTAL OPERATING EXPENSES 335,824 447,888 -------- -------- OPERATING INCOME 15,484 11,269 NONOPERATING INCOME 101,984 113,516 NONOPERATING EXPENSES 100,912 111,273 NONOPERATING INCOME TAX CREDIT 190 567 INTEREST CHARGES 6,500 7,004 -------- -------- NET INCOME $ 10,246 $ 7,075 ======== ======== STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) NET INCOME $10,246 $ 7,075 STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge 516 (1,354) ------- ------- COMPREHENSIVE INCOME $10,762 $ 5,721 ======= ======= The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $48,833 $57,513 NET INCOME 10,246 7,075 CASH DIVIDENDS DECLARED: Common Stock 7,044 7,561 ------- ------- BALANCE AT END OF PERIOD $52,035 $57,027 ======= ======= See Notes to Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $6,328,000 and $4,529,000 and for income taxes was $3,053,000 and $4,354,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $22,000 and $661,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 OPCo is a public utility engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 698,000 customers in the northwestern, east central, eastern and southern sections of Ohio. As a member of the AEP Power Pool, OPCo shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers including power trading transactions. OPCo also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to OPCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of a gain or loss in cash and reverse the previously recorded cumulative unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on OPCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior cumulative unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing OPCo to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income increased $10.7 million or 20%. While revenues declined $316.1 million, operating expenses declined even more resulting in an increase in net income. Margins increased in 2002 for electricity sales to retail customers, reflecting the spread between capped or frozen retail rates and weak wholesale energy prices and cost of fuel. Weak wholesale prices, that benefited our retail sales, resulted in lower margins reducing earnings from wholesale energy marketing and trading. The following analyzes the changes in operating revenues: Increase (Decrease) (in millions) % Electricity Marketing $(294.6) (21) and Trading* Energy Delivery* 9.9 8 Sales to AEP Affiliates (31.4) (22) ----- Total $(316.1) (19) ======= *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decline in revenues is mainly due to a decrease in electric marketing and trading revenues. The decrease was driven largely by a decline in demand due to mild winter weather and the slow recovery from the economic recession. Heating degree days were down 12% and electricity sales to industrial customers decreased 2%. Revenues from sales to AEP affiliates declined as a result of the effects of the mild weather and the economy. Operating expenses declined 20% in 2002. The changes in the components of operating expenses were: Increase (Decrease) ------------------- (in millions) % ------------- - Fuel $ (58.2) (29) Electricity Marketing and Trading Purchases (282.1) (24) Purchases from AEP Affiliates (2.4) (14) Other Operation 2.1 2 Maintenance (6.4) (18) Depreciation and Amortization 2.6 4 Taxes Other Than Income Taxes 5.6 14 Income Taxes 3.8 12 --- Total $(335.0) (20) ======= The decrease in fuel expense was primarily attributable to a reduction in power generation and lower fuel costs reflecting lower market prices. Net generation decreased by 8% due to the reduced demand for electricity. The cost of purchased power for resale was also lower due to the reduced demand, a continuation of the market conditions that developed in the fourth quarter of 2001. Maintenance expense declined due primarily due to a reduction in boiler plant overhauls. Taxes other than income taxes increased due to changes in taxes assessed on utilities under the Ohio Restructuring Law. The law imposed a new state excise tax in 2002 replacing the state gross receipts tax and provided for a reduction in taxable rates on generation property. The increase in income taxes is predominately due to a increase in pre-tax operating income. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $1,132,192 $1,426,817 Energy Delivery 141,760 131,849 Sales to AEP Affiliates 109,634 140,999 ------- ------- TOTAL OPERATING REVENUES 1,383,586 1,699,665 --------- --------- OPERATING EXPENSES: Fuel 142,336 200,561 Purchased Power: Electricity Marketing and Trading 880,157 1,162,284 AEP Affiliates 14,227 16,622 Other Operation 90,520 88,406 Maintenance 28,988 35,400 Depreciation and Amortization 62,621 60,059 Taxes Other Than Income Taxes 45,839 40,236 Income Taxes 35,182 31,341 ------ ------ TOTAL OPERATING EXPENSES 1,299,870 1,634,909 --------- --------- OPERATING INCOME 83,716 64,756 NONOPERATING INCOME 356,341 370,474 NONOPERATING EXPENSES 350,823 356,858 NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,722 2,508 INTEREST CHARGES 21,461 22,467 ------ ------ NET INCOME 64,051 53,397 PREFERRED STOCK DIVIDEND REQUIREMENTS 314 314 --- --- EARNINGS APPLICABLE TO COMMON STOCK $ 63,737 $ 53,083 ======== ======== CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) NET INCOME $64,051 $53,397 OTHER COMPREHENSIVE LOSS Foreign Currency Exchange Rate Hedge (201) (220) ---- ---- COMPREHENSIVE INCOME $63,850 $53,177 ======= ======= The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $401,297 $398,086 NET INCOME 64,051 53,397 CASH DIVIDENDS DECLARED: Common Stock 32,582 35,744 Cumulative Preferred Stock 314 314 --- --- BALANCE AT END OF PERIOD $432,452 $415,425 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2002 December 31, 2001 -------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $3,018,212 $3,007,866 Transmission 894,334 891,283 Distribution 1,084,329 1,081,122 General 242,446 245,232 Construction Work in Progress 201,524 165,073 ------- ------- Total Electric Utility Plant 5,440,845 5,390,576 Accumulated Depreciation and Amortization 2,483,039 2,452,571 --------- --------- NET ELECTRIC UTILITY PLANT 2,957,806 2,938,005 --------- --------- OTHER PROPERTY AND INVESTMENTS 61,459 62,303 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 466,283 263,734 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 39,351 8,848 Accounts Receivable: Customers 93,816 84,694 Affiliated Companies 125,302 148,563 Miscellaneous 36,835 20,409 Allowance for Uncollectible Accounts (1,048) (1,379 Fuel - at average cost 98,417 84,724 Materials and Supplies - at average cost 81,491 88,768 Accrued Utility Revenues 5,368 - Energy Trading Contracts 685,740 472,246 Prepayments and Other 32,787 20,865 ------ ------ TOTAL CURRENT ASSETS 1,198,059 927,738 --------- ------- REGULATORY ASSETS 628,491 644,625 ------- ------- DEFERRED CHARGES 64,629 79,662 ------ ------ TOTAL ASSETS $5,376,727 $4,916,067 ========== ========== See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2002 December 31, 2001 -------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 40,000,000 Shares Outstanding - 27,952,473 Shares $321,201 $321,201 Paid-in Capital 462,483 462,483 Accumulated Other Comprehensive Income (Loss) (397) (196) Retained Earnings 432,452 401,297 ------- ------- Total Common Shareholder's Equity 1,215,739 1,184,785 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 16,648 16,648 Subject to Mandatory Redemption 8,850 8,850 Long-term Debt 1,199,009 1,203,841 --------- --------- TOTAL CAPITALIZATION 2,440,246 2,414,124 --------- --------- OTHER NONCURRENT LIABILITIES 126,924 130,386 ------- ------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 5,000 - Advances from Affiliates 389,386 300,213 Accounts Payable - General 124,685 134,418 Accounts Payable - Affiliated Companies 110,429 176,520 Customer Deposits 5,961 5,452 Taxes Accrued 148,268 126,770 Interest Accrued 24,850 17,679 Obligations Under Capital Leases 14,219 16,405 Energy Trading Contracts 656,059 456,047 Other 77,898 87,070 ------ ------ TOTAL CURRENT LIABILITIES 1,556,755 1,320,574 --------- --------- DEFERRED INCOME TAXES 796,885 797,889 ------- ------- DEFERRED INVESTMENT TAX CREDITS 21,160 21,925 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 410,895 214,487 ------- ------- DEFERRED CREDITS 23,862 16,682 ------ ------ CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $5,376,727 $4,916,067 ========== ========== See Notes to Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $13,900,000 and $10,887,000 and for income taxes was $(5,574,000) and $50,242,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $98,000 and $319,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 PSO is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 503,000 retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on PSO's behalf by AEPSC. PSO, along with the other AEP electric operating subsidiaries, shares in the forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, PSO's consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to PSO. Trading activities allocated to PSO involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contracts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since PSO is a cost-based rate-regulated entity, whose revenues are based on settled transactions, unrealized changes in the fair value of physical forward sale and purchase contracts are deferred as regulatory liabilities (gains) or regulatory assets (losses). Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred as a regulatory liability or a regulatory asset. When the contract settles the total gain or loss is realized in cash and recognized in the income statement. Physical forward trading sale contracts are included in revenues when the contracts settle. Physical forward trading purchase contracts are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts are deferred as regulatory liabilities (gains) or regulatory assets (losses). Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing PSO to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations The net loss incurred by PSO increased $0.1 million or 5.6% in 2002 primarily as a result of increased maintenance expense due to storm damage in 2002. The following analyzes the changes in operating revenues: Increase (Decrease) ------------------- (in millions) % ------------- - Electricity Marketing and Trading* $(102.6) (35) Energy Delivery* 3.3 7 Sales to AEP Affiliates (9.0) (81) ---- Total Revenues $(108.3) (30) ======= *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Operating revenues decreased as a result of a decline in fuel recovery revenue and a decline in our share of AEP's marketing and trading operations. The decrease in electric marketing and trading revenue was driven largely by a decline in demand due to mild winter weather and the slow recovery from the economic recession. Lower energy demand depressed margins from electric marketing and trading. Operating expenses are as follows: Increase (Decrease) ------------------- (in millions) % ------------- - Fuel $ (53.7) (48) Electricity Marketing and Trading Purchases (32.7) (25) Purchases from AEP Affiliates (20.5) (55) Other Operation (7.9) (23) Maintenance 4.3 44 Depreciation and Amortization 1.4 7 Taxes Other Than Income Taxes 0.1 N.M. Income Taxes 0.6 28 --- Total $(108.4) (31) ======= N.M. = Not Meaningful The decrease in fuel expense was primarily due to lower fuel costs reflecting lower market prices for natural gas and fuel oil. The cost per megawatt hour of purchased power was lower due to reduced demand, a continuation of the market conditions that developed in the fourth quarter of 2001. Other operation expense decreased due mainly to reduced power trading incentive accruals, lower transmission wheeling charges and reduced factoring and collections expenses. Maintenance expense increased largely as a result of increased expenses to repair damage to overhead lines caused by a winter storm in 2002. Depreciation expense increased due to the cost of repowering Northeast Station Units 1 & 2. The increase in income taxes is predominately due to an increase in pre-tax income, and changes in certain book/tax timing differences accounted for on a flow through basis. Lower interest rates and a reduction in outstanding borrowings caused the reduction in interest charges. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $194,024 $296,599 Energy Delivery 51,732 48,417 Sales to AEP Affiliates 2,094 11,123 ----- ------ TOTAL OPERATING REVENUES 247,850 356,139 ------- ------- OPERATING EXPENSES: Fuel 58,097 111,801 Purchased Power: Electricity Marketing and Trading 96,520 129,179 AEP Affiliates 16,845 37,367 Other Operation 26,639 34,557 Maintenance 14,169 9,830 Depreciation and Amortization 20,916 19,471 Taxes Other Than Income Taxes 7,848 7,793 Income Taxes (1,594) (2,199) ------ ------ TOTAL OPERATING EXPENSES 239,440 347,799 ------- ------- OPERATING INCOME 8,410 8,340 NONOPERATING INCOME 106 824 NONOPERATING EXPENSES 595 336 NONOPERATING INCOME TAX CREDIT (141) (115) INTEREST CHARGES 9,710 10,503 ----- ------ NET LOSS (1,648) (1,560) PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53 -- -- EARNINGS LOSS APPLICABLE TO COMMON STOCK $ (1,701) $ (1,613) ======== ======== CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $142,994 $137,688 NET LOSS (1,648) (1,560) CASH DIVIDENDS DECLARED: Common Stock 22,455 13,060 Preferred Stock 53 53 -- -- BALANCE AT END OF PERIOD $118,838 $123,015 ======== ======== The common stock of PSO is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2002 December 31, 2001 -------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $1,040,043 $1,034,711 Transmission 430,395 427,110 Distribution 989,002 972,806 General 200,141 203,572 Construction Work in Progress 40,799 56,900 ------ ------ Total Electric Utility Plant 2,700,380 2,695,099 Accumulated Depreciation and Amortization 1,199,198 1,184,443 --------- --------- NET ELECTRIC UTILITY PLANT 1,501,182 1,510,656 --------- --------- OTHER PROPERTY AND INVESTMENTS 41,425 41,020 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 22,890 55,215 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 7,841 5,795 Accounts Receivable: Customers 37,214 31,100 Affiliated Companies 8,524 10,905 Fuel - at LIFO costs 21,074 21,559 Materials and Supplies - at average costs 38,616 36,785 Energy Trading Contracts 37,507 162,200 Prepayments 1,861 2,368 ----- ----- TOTAL CURRENT ASSETS 152,637 270,712 ------- ------- REGULATORY ASSETS 29,791 35,004 ------ ------ DEFERRED CHARGES 25,831 5,290 ------ ----- TOTAL ASSETS $1,773,756 $1,917,897 ========== ========== See Notes to Financial Statements beginning on page L-1.

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

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $5,157,000 and $5,736,000 and for income taxes was $1,783,000 and $1,978,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2002 vs. FIRST QUARTER 2001 SWEPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in northeastern Texas, northwestern Louisiana, and western Arkansas. SWEPCo also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on SWEPCo's behalf by AEPSC. SWEPCo, along with the other AEP electric operating subsidiaries, shares in AEP's forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - Our financial statements reflect the actions of regulators since our electricity supply sales in the Louisiana jurisdiction and our transmission and distribution operations are cost-based rate-regulated. As a result of the regulators' actions, our financial statements can recognize revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to SWEPCo. Trading activities allocated to SWEPCo involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We generally recognize revenues from open trading activities based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of open trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased power expense for a purchase. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and realized cost is included in purchased power expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match, then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing SWEPCo to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $12.7 million or 64% for the quarter. The decrease resulted primarily from reduced wholesale prices and margins due to a decline in demand for electricity which resulted from mild winter weather and a slow economic recovery. Operating revenues decreased 22% in 2002 because of a significant decrease in wholesale marketing and trading revenues. The changes in the components of revenues were as follows: Increase (Decrease) (in millions) % Electricity Marketing and Trading* $(80.1) (25) Energy Delivery* (9.1) (12) Sales to AEP Affiliates (5.7) (20) ---- Total $(94.9) (22) ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Operating revenues decreased in 2002 as a result of reduced wholesale prices due to reduced energy demand as a result of the mild winter weather and the slow recovery from the economic recession. Operating expenses decreased by 21% in 2002 mostly due to a significant decrease in electricity marketing and trading purchases and fuel expense. Increase (Decrease) ------------------- (in millions) % ------------- - Fuel $(29.3) (25) Electricity Marketing and Trading Purchases (43.7) (28) Purchases from AEP Affiliates (5.6) (40) Other Operation 2.9 7 Maintenance (3.4) (22) Depreciation and Amortization 2.0 7 Taxes Other Than Income Taxes 0.2 1 Income Taxes (5.5) (71) ---- Total $(82.4) (21) ====== Fuel expense decreased due to lower natural gas prices as a result of a mild winter and the slow recovery from the economic recession that started in the fourth quarter of 2001. A milder than normal winter and decreasing purchased power prices resulted in decreases to both electricity marketing and trading purchases and electricity purchases from AEP affiliates. Due to the acquisition of Dolet Hills mining operation in June 2001, other operation expense increased in 2002. Maintenance expense decreased as a result of costs incurred last year to restore service and make repairs following a severe ice storm. The increase in depreciation and amortization expense was due primarily to the acquisition of the Dolet Hills mining operation. Income taxes attributable to operations decreased due to a significant decrease in pre-tax income. Nonoperating income decreased due primarily to a reduction in interest income earned on under-recovered fuel which resulted from significant natural gas price increases in the second half of 2000 and early 2001. During 2001 gas price declines and a PUCT approved fuel rate and fuel surcharge increases lowered the unrecovered fuel balance thus lowering interest income. Also a decrease in allowance for funds used during construction due to lower construction balances reduced nonoperating income. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $238,854 $318,986 Energy Delivery 68,935 78,057 Sales to AEP Affiliated 22,959 28,646 ------ ------ TOTAL OPERATING REVENUES 330,748 425,689 ------- ------- OPERATING EXPENSES: Fuel 88,883 118,246 Purchased Power: Electricity Marketing and Trading 111,095 154,795 AEP Affiliated 8,441 14,062 Other Operation 42,151 39,268 Maintenance 11,838 15,236 Depreciation and Amortization 30,140 28,130 Taxes Other Than Income Taxes 14,466 14,266 Income Taxes 2,234 7,700 ----- ----- TOTAL OPERATING EXPENSES 309,248 391,703 ------- ------- OPERATING INCOME 21,500 33,986 NONOPERATING INCOME 102 834 NONOPERATING EXPENSES 566 640 NONOPERATING INCOME TAX EXPENSE (CREDIT) 28 (53) INTEREST CHARGES 13,818 14,364 ------ ------ NET INCOME 7,190 19,869 PREFERRED STOCK DIVIDEND REQUIREMENTS 57 57 -- -- EARNINGS APPLICABLE TO COMMON STOCK $7,133 $ 19,812 ====== ======== CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $308,915 $293,989 NET INCOME 7,190 19,869 DEDUCTIONS: Cash Dividends Declared: Common Stock 18,964 18,553 Preferred Stock 57 57 -- -- BALANCE AT END OF PERIOD $297,084 $295,248 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2002 December 31, 2001 -------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $1,440,947 $1,429,356 Transmission 561,473 538,749 Distribution 1,049,876 1,042,523 General 375,438 376,016 Construction Work in Progress 38,948 74,120 ------ ------ Total Electric Utility Plant 3,466,682 3,460,764 Accumulated Depreciation and Amortization 1,574,868 1,550,618 --------- --------- NET ELECTRIC UTILITY PLANT 1,891,814 1,910,146 --------- --------- OTHER PROPERTY AND INVESTMENTS 43,561 43,000 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 26,271 63,372 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 1,888 5,415 Accounts Receivable: Customers 48,236 44,588 Affiliated Companies 18,067 12,069 Allowance for Uncollectible Accounts (250) (89) Fuel Inventory - at average cost 69,845 52,212 Under-recovered Fuel - 2,501 Materials and Supplies - at average cost 33,398 32,527 Energy Trading Contracts 43,047 186,159 Prepayments 16,127 18,716 ------ ------ TOTAL CURRENT ASSETS 230,358 354,098 ------- ------- REGULATORY ASSETS 49,211 51,989 ------ ------ DEFERRED CHARGES 91,325 67,753 ------ ------ TOTAL ASSETS $2,332,540 $2,490,358 ========== ========== See Notes to Financial Statements beginning on page L-1. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2002 December 31, 2001 -------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $18 Par Value: Authorized - 7,600,000 Shares Outstanding - 7,536,640 Shares $135,660 $135,660 Paid-in Capital 245,000 245,000 Retained Earnings 297,084 308,915 ------- ------- Total Common Shareowner's Equity 677,744 689,575 Preferred Stock 4,704 4,704 SWEPCO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCO 110,000 110,000 Long-term Debt 494,217 494,688 ------- ------- TOTAL CAPITALIZATION 1,286,665 1,298,967 --------- --------- OTHER NONCURRENT LIABILITIES 36,197 34,997 ------ ------ CURRENT LIABILITIES: Long-term Debt Due Within One Year 595 150,595 Advances from Affiliates 272,326 117,367 Accounts Payable - General 68,939 71,810 Accounts Payable - Affiliated Companies 39,186 37,469 Customer Deposits 20,596 19,880 Taxes Accrued 63,253 36,522 Interest Accrued 13,697 13,631 Energy Trading Contracts 49,709 192,318 Over-recovered Fuel 7,613 - Other 20,801 26,166 ------ ------ TOTAL CURRENT LIABILITIES 556,715 665,758 ------- ------- DEFERRED INCOME TAXES 366,113 369,781 ------- ------- DEFERRED INVESTMENT TAX CREDITS 47,583 48,714 ------ ------ REGULATORY LIABILITIES AND DEFERRED CREDITS 14,982 17,828 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 24,285 54,313 ------ ------ CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $2,332,540 $2,490,358 ========== ========== See Notes to Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $10,203,000 and $13,877,000 and for income taxes was $8,581,000 and $3,164,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. WEST TEXAS UTILITIES COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS -------------------------------------------------------- FIRST QUARTER 2002 vs. FIRST QUARTER 2001 WTU is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in west and central Texas. WTU sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to retail electric providers (REPs) in Texas (see "Introduction of Customer Choice" section below). Wholesale power marketing and trading activities are conducted on WTU's behalf by AEPSC. WTU, along with the other AEP electric operating subsidiaries, shares in AEP's forward trades with other utility systems and power marketers. Introduction of Customer Choice On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. WTU currently operates in both the ERCOT and SPP (Southwest Power Pool) regions of Texas, with the majority of its operations being in the ERCOT territory. Under the Texas Restructuring Legislation, each electric utility has been required to submit a plan to structurally unbundle its business into a retail electric provider, a power generator, and a transmission and distribution utility. During the year 2000, WTU submitted a plan for separation that was subsequently approved by the PUCT. As a result of this legislation, WTU has functionally separated its generation from its transmission and distribution operations and formed a separate REP. Pending regulatory approval, WTU will corporately separate its generation from its transmission and distribution operations. The REP is a separate legal entity that is a subsidiary of AEP and is not owned by or consolidated with WTU. Since the REP is the electricity supplier to retail customers in the ERCOT area, WTU sells its generation to the REP and provides transmission and distribution services to retail customers in its ERCOT service territory. As a result of the formation of the REP, WTU no longer supplies electricity to retail customers in the ERCOT area. Instead WTU sells its generation to the REP. The implementation of REPs as suppliers to retail customers has caused a significant shift in WTU's sales as described below under "Results of Operations." Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to WTU. Trading activities allocated to WTU involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized cumulative gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased power expense for a purchase. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize our share of a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and the realized cost is included in purchased power expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match, then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing WTU to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income increased $3.1 million or 348% for the quarter. This increase is due mostly to significant decreases in both average unit costs of fuel and average costs of purchased power. Overall operating revenues decreased $53.8 million for the quarter as shown below: Increase (Decrease) (in millions) % Electricity Marketing and Trading* $(100.0) (66) Energy Delivery* 2.0 5 Sales to AEP Affiliates 44.2 N.M. ---- Total $ (53.8) (28) ======= *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. N.M. = Not Meaningful Electricity marketing and trading revenues decreased $100.0 million as a result of several factors, including the elimination of retail sales in the ERCOT as of January 1st, 2002, a decrease in energy trading, and a milder than normal winter. Sales to AEP affiliates increased $44.2 million due to revenues to the newly-created affiliated REP. Due mostly to a decrease in fuel expense and electricity marketing and trading purchases, operating expenses declined $59.5 million. Changes in the components of operating expenses are shown below: Increase (Decrease) (in millions) % Fuel $(34.9) (58) Electricity Marketing and Trading Purchases (17.2) (28) Purchases from AEP Affiliates (8.8) (43) Other Operation (1.6) (6) Maintenance (0.2) (5) Depreciation and Amortization (0.2) (2) Taxes Other Than Income Taxes 0.3 4 Income Taxes 3.1 N.M. --- Total $(59.5) (31) ====== N.M. = Not Meaningful Although there was only a slight decrease in the consumption of fuel, fuel expense decreased significantly due mostly to a decrease in the average unit cost of fuel as a result of lower spot market natural gas prices. A milder than normal winter coupled with decreasing purchased power prices lead to a decrease in both electricity marketing and trading purchases and electricity purchases from AEP affiliates. A decrease in other operation expense was the result of a decrease in ERCOT transmission-related fees. Income taxes attributable to operations increased due to a significant increase in pre-tax income. A decrease in nonoperating income was caused by a decrease in mark-to-market financial energy trading losses. WEST TEXAS UTILITIES COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $ 50,365 $150,341 Energy Delivery 40,629 38,642 Sales to AEP Affiliates 50,242 6,023 ------ ----- Total Operating Revenues 141,236 195,006 ------- ------- OPERATING EXPENSES: Fuel 24,980 59,905 Purchased Power: Electricity Marketing and Trading 44,123 61,300 AEP Affiliates 11,650 20,392 Other Operation 24,170 25,756 Maintenance 4,356 4,562 Depreciation and Amortization 11,569 11,771 Taxes Other Than Income Taxes 6,300 6,038 Income Taxes (Credit) 2,943 (110) ----- ---- Total Operating Expenses 130,091 189,614 ------- ------- OPERATING INCOME 11,145 5,392 NONOPERATING INCOME (LOSS) (1,488) 2,045 NONOPERATING EXPENSES 1,372 332 NONOPERATING INCOME TAX EXPENSE (CREDIT) (989) 282 INTEREST CHARGES 5,282 5,932 ----- ----- NET INCOME 3,992 891 PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26 -- -- EARNINGS APPLICABLE TO COMMON STOCK $3,966 $ 865 ====== ===== STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2002 2001 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $105,970 $122,588 NET INCOME 3,992 891 DEDUCTIONS: Cash Dividends Declared: Common Stock 6,749 7,206 Preferred Stock 26 26 -- -- BALANCE AT END OF PERIOD $103,187 $116,247 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. WEST TEXAS UTILITIES COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2002 December 31, 2001 -------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $ 442,078 $ 443,508 Transmission 253,347 250,023 Distribution 437,265 431,969 General 108,580 112,797 Construction Work in Progress 18,749 22,575 ------ ------ Total Electric Utility Plant 1,260,019 1,260,872 Accumulated Depreciation and Amortization 547,380 546,162 ------- ------- NET ELECTRIC UTILITY PLANT 712,639 714,710 ------- ------- OTHER PROPERTY AND INVESTMENTS 25,634 24,933 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 14,120 21,532 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 556 2,454 Accounts Receivable: Customers 30,945 18,720 Affiliated Companies 24,928 8,656 Allowance for Uncollectible Accounts (237) (196) Fuel - at average cost 8,977 8,307 Materials and Supplies - at average cost 11,426 11,190 Under-recovered Fuel Costs 33,419 32,791 Energy Trading Contracts 25,383 63,252 Prepayments and Other Current Assets 453 966 --- --- TOTAL CURRENT ASSETS 135,850 146,140 ------- ------- REGULATORY ASSETS 11,786 13,659 ------ ------ DEFERRED CHARGES 15,358 2,446 ------ ----- TOTAL ASSETS $915,387 $923,420 ======== ======== See Notes to Financial Statements beginning on page L-1. WEST TEXAS UTILITIES COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2002 December 31, 2001 -------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 7,800,000 Shares Outstanding - 5,488,560 Shares $137,214 $137,214 Paid-in Capital 2,236 2,236 Retained Earnings 103,187 105,970 ------- ------- Total Common Shareowner's Equity 242,637 245,420 Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,482 2,482 Long-term Debt 220,998 220,967 ------- ------- TOTAL CAPITZALIZATION 466,117 468,869 ------- ------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 35,000 35,000 Advances from Affiliates 89,168 50,448 Accounts Payable - General 17,958 33,782 Accounts Payable - Affiliated Companies 26,263 11,388 Customer Deposits - 4,191 Taxes Accrued 21,563 17,358 Interest Accrued 2,832 1,244 Energy Trading Contracts 21,843 65,414 Other 13,875 12,001 ------ ------ TOTAL CURRENT LIABILITIES 228,502 230,826 ------- ------- DEFERRED INCOME TAXES 145,078 145,049 ------- ------- DEFERRED INVESTMENT TAX CREDITS 22,463 22,781 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 12,183 18,455 ------ ------ REGULATORY LIABILITIES AND DEFERRED CREDITS 41,044 37,440 ------ ------ CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $915,387 $923,420 ======== ======== See Notes to Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $2,097,000 and $2,162,000 and for income taxes was ($1,575,000) and ($2,957,000) in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. NOTES TO FINANCIAL STATEMENTS MARCH 31, 2002 (UNAUDITED) The notes to financial statements are a combined presentation for AEP and its subsidiary registrants as follows:

1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 2001 Annual Report as incorporated in and filed with the Form 10-K. Certain prior period financial statement items were reclassified to conform to current period presentation. Reclassifications had no effect on previously reported net income. In the opinion of management, the unaudited financial statements reflect all normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. GOODWILL AND OTHER INTANGIBLE ASSETS SFAS 142, "Goodwill and Other Intangible Assets" was effective for AEP on January 1, 2002. The adoption of SFAS 142 requires the transition testing for impairment of all indefinite lived intangibles by the end of the first quarter and initial testing of goodwill by the end of the second quarter of 2002. In the first quarter of 2002, AEP completed testing the goodwill of its domestic operations and its indefinite lived intangible assets and there was no impairment. We recently began testing for goodwill impairment of our UK operations as required by SFAS 142 and will complete the initial testing in the second quarter of 2002. If after completing our transition testing we determine that any goodwill is impaired, the transitional impairment loss from the adoption of SFAS 142 will be reported as a cumulative effect of an accounting change retroactive to January 1, 2002. Also see "Possible Divestitures" in Management's Discussion and Analysis for related discussion of potential material losses. SFAS 142 also changed the accounting and reporting for goodwill and other intangible assets. Effective with the adoption of SFAS 142 on January 1, 2002 the amortization of goodwill ceased. SFAS 142 requires that other intangible assets be separately identified and if they have finite lives, they must be amortized over that life. New reporting requirements imposed by SFAS 142 include the disclosures shown below. Goodwill The changes in the carrying amount of goodwill for the three months ended March 31, 2002 by operating segment are:

In the first quarter of 2002, AEP recognized a goodwill impairment loss of $12 million ($8 million net of tax) as a result of management's decision to exit its Gas Power Systems business that was developing customized generators powered by surplus helicopter engines. Management elected to exit this business due to technical problems with the underlying technology and recognized an impairment loss for all goodwill related to the acquisition of Gas Power Systems. As required by SFAS 142 the following tables show the transitional disclosures to adjust reported net income and earnings per share to exclude amortization expense recognized in prior periods related to goodwill and intangible assets that are no longer being amortized and adjustments for changes in amortization periods for intangible assets that continue to be amortized.

Acquired Intangible Assets Acquired intangible assets subject to amortization are $31 million at March 31, 2002 and $20 million at December 31, 2001 net of accumulated amortization. The gross carrying amount and accumulated amortization by major asset class are:

Amortization of intangible assets was $0.5 million for the three months ended March 31, 2002. Estimated aggregate amortization expense is $2.2 million for each year 2003 through 2008. Acquired intangible assets no longer subject to amortization are comprised of distribution licenses for CitiPower operating franchises with a carrying amount of $440 million and $421 million at March 31, 2002 and December 31, 2001. Fluctuations in the carrying values of the CitiPower retail supply and distribution licenses since December 31, 2001 represent changes in the foreign currency exchange rate. 3. ACQUISITIONS AND DISPOSITIONS In January 2002 AEP acquired for $2 million the existing trading operations, including 34 key staff, of Enron's Norway and Sweden-based energy trading businesses. The acquisition is an addition to the growing energy trading operation in Europe based in the U.K., where we now trade power and gas in the U.K., France, Germany, and the Netherlands and coal throughout the world. Results of operations are included in the consolidated income statements from the acquisition date. Based on a preliminary purchase price allocation the excess of cost over fair value of the net assets acquired is approximately $2 million which is recorded as goodwill. The allocation of the purchase price is subject to revision after completion of a final appraisal of the fair values of the assets acquired and liabilities assumed. In April 2002 AEP reached a definitive agreement to transfer two of its Texas retail electric providers (REPs) to Centrica, a provider of retail energy and other consumer services. An independent appraiser will establish a fair market value for the transaction after mid-June 2002. This approach satisfies the parties<180> desire to have the transfer price reflect the actual fair market value on a date nearer to closing, and is consistent with the pooling of interests accounting limitations imposed on AEP until June 15, 2002, in connection with its merger with Central and South West Corp. If the appraised value is outside the range of $133 million to $153 million, the transaction need not be completed. AEP will provide Centrica with a power supply contract for the two REPs and all back-office services related to these customers for a two-year period following closing. In addition, AEP retains the right to share in earnings from the two REPs above a threshold amount through 2006 in the event the Texas retail market develops increased earnings opportunities. AEP will also receive an up-front payment of approximately $39 million from Centrica associated with the back-office service agreement. Completion of the transaction is contingent upon the fair market value appraisal meeting the required contractual guidelines, regulatory approval from the PUCT and federal anti-trust clearance. AEP and Centrica expect to complete the regulatory approval process and conclude the transaction by the end of 2002. 4. RATE MATTERS As discussed in Note 5 of the Notes to Financial Statements in the 2001 Annual Report, certain WTU wholesale customers filed a complaint with FERC alleging that WTU had overcharged them through the fuel adjustment clause for certain purchased power costs since 1997. The customers allege WTU had billed them for not only the cost of a 1999 Oklaunion outage, but also certain additional costs that are not permissible under the fuel adjustment clause. Negotiations to settle the complaint and update the contracts are continuing. In March 2002 WTU recorded a provision for refund of $2.2 million before income taxes. The actual refund and final resolution of this matter could differ materially from this estimate and may have a negative impact on future results of operations, cash flow and financial condition. Texas Retail Price-to-Beat Rates - Affecting AEP The Texas retail electric providers (REP) for the ERCOT area, CPL REP and WTU REP, filed with the PUCT to increase the fuel portion of their "price-to-beat" rate. The Texas legislation provides for the adjustment of the fuel portion of the rate up to twice annually based on changes in the market price of fuel using a natural gas price index. Any rate adjustment approved by the PUCT would be effective on June 28, 2002 or a later date ordered by the PUCT. 5. INDUSTRY RESTRUCTURING As discussed in the 2001 Annual Report, customer choice began in four of the eleven state retail jurisdictions in which the AEP domestic electric utility companies operate. The following paragraphs discuss significant events occurring in 2002 related to customer choice and industry restructuring. Ohio Restructuring - Affecting AEP, CSPCo and OPCo As discussed in Note 7 of the Notes to Financial Statements in the 2001 Annual Report, CSPCo and OPCo filed an appeal with the Ohio Supreme Court related to a tax expense issue which would result in duplicate expense of $40 million and $50 million, respectively, for a twelve month period beginning on May 1, 2001. On April 3, 2002, the Ohio Supreme Court rejected the companies' arguments related to a duplicate tax period and affirmed the PUCO's order which established the effective date of tax credit riders in rates. This ruling had no impact on results of operations as the companies had recorded an extraordinary loss when the prepaid asset was stranded by a PUCO order in 2001. Virginia Restructuring - Affecting AEP and APCo On January 1, 2002, choice of electricity supplier for retail customers began in Virginia. Presently, APCo continues to service virtually all its previous customers. Per settlement agreements and terms of the restructuring law, APCo's capped rates are the rates which were in effect on July 1, 1999 and no wires charge will be collected during 2002. See the 2001 Annual Report for further discussion. Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU As discussed in the 2001 Annual Report, on January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in other areas of Texas including the SPP area. All of SWEPCo's Texas service territory and a small portion of WTU's service territory are located in the SPP area. CPL operates entirely in the ERCOT area of Texas. Under the Texas Legislation, the PUCT approved business separation plans for the utility companies. The business separation plans provided for CPL and WTU to establish separate companies and divide their integrated utility operations and assets into a power generation company, a transmission and distribution utility and a retail electric provider. Due to the delay in the start of competition in the SPP area and lack of regulatory approval for our corporate separation plan, only CPL's and WTU's retail electric providers commenced operations on January 1, 2002. Operations for CPL, SWEPCo and WTU have been functionally separated. The companies anticipate completing legal separation following receipt of the appropriate regulatory approvals. In February 2002 CPL through a subsidiary issued $797 million of transition notes approved under the securization clauses in the Texas Restructuring Legislation. The transition notes provide more economical financing for certain transition generation related regulatory assets during their recovery period. A 2004 true-up proceeding will determine the amount of total stranded costs, if any, including the final fuel recovery, net regulatory asset recovery, certain environmental costs, accumulated excess earnings offsets and other issues. The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale of and/or exchange of generation assets, the issuance of power generation company stock to the public or the use of an ECOM model. To the extent that the final 2004 true-up proceeding determines that CPL should recover additional stranded costs, the additional amount recoverable can also be securitized. The PUCT ordered CPL to reduce distribution rates by $54.8 million over a five-year period beginning January 1, 2002 in order to return estimated excess earnings for 1999, 2000 and 2001. The Texas Restructuring Legislation intended that excess earnings would be used to reduce stranded cost. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. The PUCT currently estimates that CPL will have no stranded cost and has ordered the rate reduction to return excess earnings, pending the outcome of the 2004 true-up proceeding. Since CPL expensed excess earnings amounts 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. Beginning January 1, 2002, fuel costs for CPL and WTU in ERCOT are no longer subject to PUCT fuel reconciliation proceedings. Consequently, CPL and WTU will file a final fuel reconciliation with the PUCT which reconciles their fuel costs through the period ending December 31, 2001. These final fuel balances will be included in each company's 2004 true-up proceeding. The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP, CPL and WTU to the risk of fuel market price increases and could adversely affect results of operations. In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding to recover all or a portion of their generation-related regulatory assets, unrecovered fuel balances, stranded costs and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Michigan Restructuring - Affecting AEP and I&M Customer choice commenced for I&M's Michigan customers on January 1, 2002. Effective with that date the rates on I&M's Michigan customers' bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M's total rates in Michigan remain unchanged and reflect cost of service. At this time, none of I&M's customers have elected to change suppliers and no competing suppliers are active in I&M's Michigan service territory. Management has concluded that as of March 31, 2002 the requirements to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan continue to be cost-based regulated. As a result I&M has not yet discontinued regulatory accounting under SFAS 71. 6. BUSINESS SEGMENTS AEP has three business segments: Wholesale, Energy Delivery and Other. The business activities of each of these segments are as follows: Wholesale o Generation of electricity for sale to retail and wholesale customers, o Marketing and trading of electricity and gas worldwide. o Gas pipeline and storage services and other energy supply related business o Coal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery o Domestic electricity transmission o Domestic electricity distribution Other o Foreign electricity distribution and supply investments o Telecommunication services Segment results of operations for the three months ended March 31, 2002 and 2001 are shown below. These amounts include certain estimates and allocations where necessary. We have used Earnings before Interest and Income Taxes (EBIT) as a measure of segment operating performance. The EBIT measure is total operating revenues net of total operating expenses and other income and deductions from income. It differs from net income in that it does not take into account interest expense or income taxes. EBIT is believed to be a reasonable gauge of results of operations. By excluding interest and income taxes, EBIT does not give guidance regarding the demand of debt service or other interest requirements, or tax liabilities or taxation rates. The effects of interest expense and taxes on overall corporate performance can be seen in the consolidated statements of income. The amounts shown for the three business segments reported by AEP include certain estimates and allocations where necessary.

All of the registrant subsidiaries except AEGCo have two business segments. The segment results for each of these subsidiaries are reported in the table below. AEGCo has one segment, a wholesale generation business. AEGCo's results of operations are reported in AEGCo's financial statements.

7. FINANCING AND RELATED ACTIVITIES In the first quarter of 2002, CPL Transition Funding LLC, a subsidiary of CPL, issued $797 million of transition notes under the provisions of the Texas Restructuring Legislation (See Note 5). The proceeds were used to reduce CPL's debt and retire 4.5 million shares of CPL's common stock. The notes were issued under the following classes: Principal Interest Scheduled Final Final Class Amount Rate Payment Date Maturity Date ----- --------- -------- --------------- ------------- (in millions) (%) A-1 129 3.54 2005 2007 A-2 154 5.01 2008 2010 A-3 107 5.56 2010 2012 A-4 215 5.96 2013 2015 A-5 192 6.25 2016 2017 A subsidiary of AEP also increased borrowing on its revolving credit agreement by $73 million. The agreement has a variable interest rate and is due in 2003. The following table lists long-term debt retirements during the first quarter of 2002 by the registrant subsidiaries:

8. CONTINGENCIES Litigation Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo As discussed in Note 8 of the Notes to Financial Statements in the 2001 Annual Report, AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case. The alleged modification of the generating units occurred over a 20 year period. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In 2001 the 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. In February 2001 the government filed a motion requesting a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. The Circuit Court dismissed the motion as pre-mature. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future results of operations and cash flows. NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The NOx Rule has been upheld on appeal. The compliance date for the NOx Rule is May 31, 2004. The NOx Rule required states to submit plans to comply with its provisions. In 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit approvable compliance plans. Those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA assumption of state air quality management programs. AEP subsidiaries and other utilities requested that the D.C. Circuit Court review this ruling. In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Affected utilities including certain AEP operating companies, petitioned the D.C. Circuit Court to review the Section 126 Rule. After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. In August 2001 the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. On April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date for the Section 126 Rule. Federal EPA published a notice in the Federal Register on May 1, 2002 advising that no changes in the growth factors used to set the NOx budgets were warranted. In 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. AEP is installing selective catalytic reduction (SCR) technology to reduce NOx emission. During 2001 SCR on OPCo's Gavin Plant commenced operations. Installation of SCR technology on Amos and Mountaineer plants was completed and commenced operation in May 2002. Construction of SCR technology at certain other AEP generating units continues with completion scheduled in May 2003 through 2006. Our estimates indicate that AEP's compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures of approximately $1.6 billion, including amounts spent through March 31, 2002. Estimated compliance costs by registrant subsidiaries are as follows: Estimated Compliance Costs ---------------- (in millions) AEGCo $125 APCo 365 CPL 57 CSPCo 106 I&M 202 KPCo 140 OPCo 606 SWEPCo 28 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo At the date of Enron's bankruptcy AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities remained unsettled at the date of Enron's bankruptcy. In connection with the acquisition of HPL, we acquired from BAM Lease Company, a now-bankrupt subsidiary of Enron, the right to use under a 30-year lease, with a renewal right for another 20 years, the Bammel gas storage facility. The lease includes the use of the Bammel storage reservoir and the related above ground compression, treating and delivery systems. We also entered into a "right to use" agreement with BAM Lease Company which allows us to use approximately 55 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the facility. The Bammel Trust which is the nominal owner of the cushion gas has entered into a financing arrangement with a group of banks which purports to provide rights to the cushion gas in certain circumstances. The banks consented to our use of the cushion gas coextensive for the term of the lease of the Bammel gas storage facility. We have been informed by the banks of Bammel Trust's default under the terms of their financing agreement and it is not clear what, if any, rights the banks will assert with respect to the cushion gas. In the fourth quarter of 2001 AEP provided $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. The amounts for certain subsidiary registrants were: Amounts Amounts Net of Registrant Provided Tax -------- --- (in millions) APCo $5.2 $3.4 CSPCo 3.2 2.1 I&M 3.4 2.2 KPCo 1.3 0.8 OPCo 4.3 2.8 The amounts provided were based on an analysis of contracts where AEP and Enron are counterparties, the offsetting of receivables and payables, the application of deposits from Enron and management's analysis of the HPL related purchase contingencies and indemnifications. If there are any adverse unforeseen developments in the bankruptcy proceeding or in Bammel Trust's default under the cushion gas financing agreement, our future results of operations, cash flows and possibly financial condition could be adversely impacted. California Energy Market Investigation by FERC - Affecting AEP On February 13, 2002, the FERC issued an order directing its Staff to conduct a fact-finding investigation into whether any entity, including Enron Corp., manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward. In April 2002, AEP furnished certain information to the FERC in response to their related data request. Pursuant to the FERC's February 13, 2002 order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron Corp. and, allegedly, traders of other companies active in the wholesale electricity and ancillary services markets in the West, particularly California, during the years 2000 and 2001. This data request was issued to AEP as part of a group of over 100 entities designated by the FERC as all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator and/or the California Power Exchange. The May 8, 2002 FERC data request requires senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative. Senior management intends to fully comply with the order by the May 22, 2002 response date. Other AEP and its subsidiary registrants continue to be involved in certain other matters discussed in the 2001 Annual Report. REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS This is our combined presentation of management's discussion and analysis of financial condition, contingencies and other matters for AEP and its registrant subsidiaries. Management's discussion and analysis of results of operations for AEP and each of its registrant subsidiaries for the quarter ended March 31, 2002 is presented with their financial statements earlier in this document. FINANCIAL CONDITION The rating agencies have been conducting credit reviews of AEP and its registrant subsidiaries as we prepare for corporate separation. As of April 30, 2002, the ratings of AEP's commercial paper, the registrant subsidiaries' first mortgage bonds and the senior unsecured debt of AEP and its registrant subsidiaries is unchanged from year end. However, on April 19, 2002, Moody's Investors Service announced that AEP and five of its registrant subsidiaries (CPL, CSPCo, OPCo, SWEPCo and WTU) had been placed on credit rating watch for possible downgrade. The review of the companies' debt position and credit rating is being completed in anticipation of corporate separation. We are working with Moody's and providing information to support AEP's current credit rating. If our credit ratings are lowered, the interest rates we pay on borrowings will potentially rise thereby increasing our interest expense unless we can reduce our borrowings. Cash from operations and short-term borrowings provide working capital and meet other short-term cash needs. We generally use short-term borrowings to fund property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include issuance of common stock, preferred stock or long-term debt and sale-leaseback or leasing agreements. We operate a money pool and sell accounts receivables to provide liquidity for the domestic electric subsidiaries. Short-term borrowings are supported by a bank-sponsored receivables purchase agreement, a term loan facility and three revolving credit agreements. During the first quarter of 2002 cash flow from operations was negative $14 million, including $181 million from net income and $290 million from depreciation, amortization and deferred taxes. Capital expenditures including acquisitions were $378 million and dividends on common stock were $193 million. Cash from the issuance of $797 million of transition funding bonds provided funds to cover the operating funds deficiency, reduce debt, fund construction and pay dividends. Major construction expenditures included amounts for emission control technology on several coal-fired generating units (see discussion in Note 8). During the fourth quarter of 2001, Quaker Coal Co., MEMCO Barge Line, Inc. and two coal-fired generating plants in the UK were acquired using short-term borrowings and available cash. Long-term financing arrangements are being negotiated for the UK generating plants and will be announced as completed. Completion of this financing is anticipated in the second quarter of 2002. Long-term funding arrangements are often complex and take time to complete. As discussed in the annual report, we filed with the SEC in April 2002 for authorization to issue a combination of up to $3 billion in equity or debt to improve our financial condition as measured by our debt to equity ratio. We currently anticipate an equity offering between $1 billion and $1.5 billion. This issuance proposes to include AEP common stock and other equity or convertible debt instruments. Total consolidated plant and property additions including capital leases for the first quarter period were $354 million. The following table shows the plant and property additions by certain registrant subsidiaries: Company Amount ------- ------ (in millions) APCo $63 CPL 21 I&M 27 OPCo 66 SWEPCo 12 Possible Divestitures We have a strong commitment to continually evaluate the need to reallocate resources to areas that effectively match investments with our strategy, provide greater potential for meaningful financial returns, and to dispose of investments that do not meet these principles. In particular, we have recently entered into a definitive agreement to dispose of two of our Texas retail electric providers which serve retail residential and small commercial customers in Texas. The disposal price will not be determined until a date closer to the consummation of the transaction, which is expected to be during the fourth quarter of 2002. Other investments and assets being evaluated for potential disposition include: o SEEBOARD and CitiPower, our energy delivery and retail supply businesses in the UK and Australia. In connection with our evaluations, we have retained investment advisors and are assessing the relative interests of several strategic and financial buyers of these operations. At SEEBOARD, we have provided interested parties an information memorandum and, based upon their initial level of interest, have provided some of those parties the opportunity to pursue more detailed due diligence procedures. We expect to receive offers from these parties to purchase SEEBOARD that are capable of acceptance late in the second quarter. At CitiPower, we have distributed an information memorandum and expect to receive similar offers late in June. o our power generation interests in Medway Power in the UK, Nanyang Electric in China, Pacific Hydro in Australia, and certain cogeneration facilities in the US, our joint investment in power distribution in Brazil, and our domestic telecommunications assets. A recommendation, if one is proposed by management, to dispose of any of these investments will be subject to the approval and authority of our Board of Directors. The ultimate timing of a recommendation to our Board for a disposition of one or more of these assets will depend upon market conditions and the value of any buyer's proposal to us. If, based on the outcome of our evaluations, our recommendation to and approval of our Board, we choose to dispose of these assets, we would expect to realize non-recurring losses in the aggregate that will have a material impact on our results of operations. Corporate Separation As discussed in the 2001 Annual Report, we have filed with the FERC and SEC seeking approval to separate our regulated and unregulated operations. Our plan for corporate separation allows us to meet the requirements of Texas and Ohio restructuring legislation. We intend to transfer the generation assets from the integrated electric operating companies in Ohio and Texas (CSPCo, OPCo, CPL and WTU) to unregulated generation companies. We proposed amendments to the power pooling agreements for all operating companies. Only those operating companies that continue to exist as integrated utilities would be included in the amended power pooling agreements, which would govern energy exchanges among members and the allocation of their off system purchases and sales. Several state commissions, wholesale customer groups and other interested parties intervened in the FERC proceeding. We have negotiated settlement agreements with the intervenors. The settlement agreements have been filed at the FERC for review and approval. FERC and SEC approval of our corporate separation plan is required for its implementation. In order to execute this separation, we will be required to retire various debt securities and to transfer assets between legal entities. RTO Formation As discussed in the 2001 Annual Report, FERC Order No. 2000 and many of the settlement agreements with the state regulatory commissions to approve the AEP-CSW merger required the transfer of control of our transmission system to an RTO. Certain AEP subsidiaries participated in the formation of the Alliance RTO. Other subsidiaries are members of ERCOT or SPP. The FERC expressed its opinion that large RTOs will better support competition and reliability of electric service. In May 2002 AEP announced an agreement with the PJM Interconnection to pursue terms for participation in its RTO. Final agreements are expected to be negotiated. Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, our transmission operations or results of operations and cash flows. OTHER MATTERS Industry Restructuring As discussed in Note 5 and the 2001 Annual Report, restructuring and customer choice began in four of the eleven state retail jurisdictions in which the AEP electric utility companies operate. Restructuring legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the supply of electricity. Customer choice of electricity supplier began on January 1, 2001 for Ohio customers and on January 1, 2002, for Michigan, Texas and Virginia customers. In Ohio, Michigan and Virginia virtually all customers continue to receive electric generation, transmission and distribution services from our electric operating companies. In the Texas jurisdiction competition began in the ERCOT area but was delayed in the SPP area. In 2001 the PUCT issued an order requiring CPL to reduce future distribution rates by $54.8 million over a five-year period beginning January 1, 2002 in order to return estimated excess earnings for 1999, 2000 and 2001. The Texas Restructuring Legislation intended that excess earnings would be used to reduce stranded cost. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. The PUCT currently estimates that CPL will have no stranded cost and has ordered the rate reduction to return excess earnings, pending the outcome of the 2004 true-up proceeding. CPL expensed excess earnings amounts in 1999, 2000 and 2001. Consequently, the order has no effect on reported net income. Beginning January 1, 2002, fuel costs are no longer subject to PUCT fuel reconciliation proceedings under the Texas Restructuring Legislation. Consequently, CPL and WTU will file a final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. These final fuel balances will be included in each company's 2004 true-up proceeding. The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP, CPL and WTU to the risk of fuel market price increases and could adversely affect future results of operations beginning in 2002. In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding to recover all or a portion of their generation-related regulatory assets, unrecovered fuel balances, stranded costs and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Litigation Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo As discussed in the 2001 Annual Report, AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case. The alleged modification of the generating units occurred over a 20 year period. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In 2001 the 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. In February 2001 the government filed a motion requesting a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. The Circuit Court dismissed the motion as premature. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future results of operations and cash flows. NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The NOx Rule has been upheld on appeal. The compliance date for the NOx Rule is May 31, 2004. The NOx Rule required states to submit plans to comply with its provisions. In 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit approvable compliance plans. Those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA assumption of state air quality management programs. AEP subsidiaries and other utilities requested that the D.C. Circuit Court review this ruling. In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Affected utilities including certain AEP operating companies, petitioned the D.C. Circuit Court to review the Section 126 Rule. After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. In August 2001 the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. On April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date for the Section 126 Rule. Federal EPA published a notice in the Federal Register on May 1, 2002 advising that no changes in the growth factors used to set the NOx budgets were warranted. In 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. AEP is installing selective catalytic reduction (SCR) technology to reduce NOx emission. During 2001 SCR on OPCo's Gavin Plant commenced operations. Installation of SCR technology on Amos and Mountaineer plants was completed and commenced operation in May 2002. Construction of SCR technology at certain other AEP generating units continues with completion scheduled in May 2003 through 2006. Our estimates indicate that AEP's compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures of approximately $1.6 billion, including amounts spent through March 31, 2002. The following table shows the estimated compliance cost for certain of AEP's registrant subsidiaries. Company Amount ------- ------ (in millions) APCo $365 CPL 57 I&M 202 OPCo 606 SWEPCo 28 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital or operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo At the date of Enron's bankruptcy AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities remained unsettled at the date of Enron's bankruptcy. In connection with the acquisition of HPL, we acquired from BAM Lease Company, a now-bankrupt subsidiary of Enron, the right to use under a 30-year lease, with a renewal right for another 20 years, the Bammel gas storage facility. The lease includes the use of the Bammel storage reservoir and the related above ground compression, treating and delivery systems. We also entered into a "right to use" agreement with BAM Lease Company which allows us to use approximately 55 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the facility. The Bammel Trust which is the nominal owner of the cushion gas has entered into a financing arrangement with a group of banks which purports to provide rights to the cushion gas in certain circumstances. The banks consented to our use of the cushion gas coextensive for the term of the lease of the Bammel gas storage facility. We have been informed by the banks of Bammel Trust's default under the terms of their financing agreement and it is not clear what, if any, rights the banks will assert with respect to the cushion gas. In the fourth quarter of 2001 AEP provided $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. The amounts for certain subsidiary registrants were: Amounts Amounts Net of Registrant Provided Tax -------- --- (in millions) APCo $5.2 $3.4 CSPCo 3.2 2.1 I&M 3.4 2.2 KPCo 1.3 0.8 OPCo 4.3 2.8 The amounts provided were based on an analysis of contracts where AEP and Enron are counterparties, the offsetting of receivables and payables, the application of deposits from Enron and management's analysis of the HPL related purchase contingencies and indemnifications. If there are any adverse unforeseen developments in the bankruptcy proceeding or in Bammel Trust's default under the cushion gas financing agreement, our future results of operations, cash flows and possibly financial condition could be adversely impacted. California Energy Market Investigation by FERC - Affecting AEP On February 13, 2002, the FERC issued an order directing its Staff to conduct a fact-finding investigation into whether any entity, including Enron Corp., manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward. In April 2002, AEP furnished certain information to the FERC in response to their related data request. Pursuant to the FERC's February 13, 2002 order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron Corp. and, allegedly, traders of other companies active in the wholesale electricity and ancillary services markets in the West, particularly California, during the years 2000 and 2001. This data request was issued to AEP as part of a group of over 100 entities designated by the FERC as all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator and/or the California Power Exchange. The May 8, 2002 FERC data request requires senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative. Senior management intends to fully comply with the order by the May 22, 2002 response date. Other AEP and its subsidiary registrants continue to be involved in certain other matters discussed in the 2001 Annual Report. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market Risks - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU As a major power producer and trader of wholesale electricity and natural gas, we have certain market risks inherent in our business activities. These risks include commodity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates. Policies and procedures have been established to identify, assess, and manage market risk exposures in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Management Committee and administered by a Chief Risk Officer. The Risk Management Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers. We use a risk measurement model which calculates Value at Risk (VaR) to measure our commodity price risk. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assuming a 95% confidence level and a one-day holding period. Based on this VaR analysis, at March 31, 2002 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 high, average, and low market risk as measured by VaR at: March 31, December 31, 2002 2001 ---- ---- High Average Low High Average Low (in millions) (in millions) AEP $24 $16 $8 $28 $14 $5 APCo 4 2 1 4 1 - CPL - - - 3 1 - CSPCo 3 1 1 2 1 - I&M 3 1 1 3 1 - KPCo 1 1 - 1 - - OPCo 4 2 1 3 1 - PSO - - - 2 1 - SWEPCo - - - 3 1 - WTU - - - 1 1 - We also 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 weekly prices. The risk of potential loss in fair value attributable to AEP's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $657 million at March 31, 2002 and $673 million at December 31, 2001. However, since we would not expect to liquidate our entire debt portfolio in a one year holding period, a near term change in interest rates should not materially affect results of operations or consolidated financial position. AEGCo is not exposed to risk from changes in interest rates on short-term and long-term borrowings used to finance operations since financing costs are recovered through the unit power agreements. AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001 for CSPCo and OPCo) and in the ERCOT area of Texas (effective January 1, 2002 for CPL and WTU) or frozen by settlement agreements in Indiana, Michigan and West Virginia. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. We employ 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. However, we engage in trading of electricity, gas and to a lesser degree coal, oil, natural gas liquids, and emission allowances and as a result the Company is subject to price risk. The amount of risk taken by the traders is controlled by the management of the trading operations and the Company's Chief Risk Officer and his staff. When the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to the limits unless specifically approved by the Risk Management Committee. We employ fair value hedges, cash flow hedges and swaps 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 cash flow forward hedge contracts to lock-in prices on transactions denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations in debt denominated in foreign currencies. We do not hedge all foreign currency exposure. AEP limits credit risk by extending unsecured credit to entities based on internal ratings. In addition, AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. This data, in conjunction with the ratings information, is used to determine appropriate risk parameters. AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from certain below investment grade counterparties in our normal course of business. We trade electricity and gas contracts with numerous counterparties. Since our open energy trading contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that our credit and market exposures with any one counterparty is not material to financial condition at March 31, 2002. At March 31, 2002 approximately 7% of the counterparties were below investment grade as expressed in terms of Net Mark to Market Assets. Net Mark to Market Assets represents the aggregate difference (either positive or negative) between the forward market price for the remaining term of the contract and the contractual price. The following table approximates counterparty credit quality and exposure for AEP. Futures, Forwards and Counterparty Swap Contracts Options Total Credit Quality: March 31, 2002 (in millions) AAA/Exchanges $ 1 $ - $ 1 AA 104 39 143 A 304 14 318 BBB 1,021 260 1,281 Below Investment Grade 94 43 137 ------- ---- --- Total $1,524 $356 $1,880 ====== ==== ====== The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. We enter into transactions for electricity and natural gas as part of wholesale trading operations. Electric and gas transactions are executed over the counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers and counterparties require cash or cash related instruments to be deposited on these transactions as margin against open positions. The combined margin deposits at March 31, 2002 and December 31, 2001 were $230 million and $55 million. These margin accounts are restricted and therefore are not included in cash and cash equivalents on the Balance Sheet. We can be subject to further margin requirements should related commodity prices change. We recognize the net change in the fair value of all open trading contracts, a practice commonly called mark-to-market accounting, in accordance with generally accepted accounting principles and include the net change in mark-to-market amounts on a net discounted basis in revenues. The marking to market of open trading contracts in the first quarter of 2002 resulted in an unrealized increase in revenues of $43 million. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. The fair value of open long-term trading contracts are based mainly on Company developed valuation models. This fair value is present valued and reduced by appropriate reserves for counterparty credit risks and liquidity risk. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. Forward price curves are developed for inclusion in the model based on broker quotes and other available market data. The curves are within the range between the bid and ask prices. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid price of the bid ask prices if we have a long position and the ask price if we have a short position. This provides for a conservative valuation net of the reserves. The use of these models to fair value open long-term trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market prices, at the time of settlement, do not correlate with the Company developed price models. The effect on the Consolidated Statements of Income of marking to market open electricity trading contracts in the Company's regulated jurisdictions is deferred as regulatory assets or liabilities since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading are reported as assets and liabilities, respectively. The following table shows net revenues (revenues less fuel and purchased energy expense) and their relationship to the mark-to-market revenues (the change in fair value of open trading positions). March 31, --------- 2002 ---- (in millions) Revenues (including mark-to-market adjustment) $13,414 Fuel and Purchased Energy Expense 11,307 ------- Net Revenues $ 2,107 ======= Mark-to-Market Revenues on Open Trading Positions $47* === Percentage of Net Revenues Represented by Mark-to-Market on Open Trading Positions 2% == *Excludes reversal of $266 million of mark to market for contracts that settled in the 1st quarter of 2002. The following tables analyze the changes in fair values of trading assets and liabilities. The first table "Net Fair Value of Energy Trading Contracts and Related Derivatives" shows how the net fair value of energy trading contracts was derived from the amounts included in the balance sheet line item "energy trading and derivative contracts." The next table "Energy Trading Contracts and Related Derivatives" disaggregates realized and unrealized changes in fair value; identifies changes in fair value as a result of changes in valuation methodologies; and reconciles the net fair value of energy trading contracts and related derivatives at December 31, 2001 of $448 million to March 31, 2002 of $355 million. Contracts realized/settled during the period include both sales and purchase contracts. The third table "Energy Trading Contract Maturities" shows exposures to changes in fair values and realization periods over time for each method used to determine fair value. Net Fair Value of Energy Trading Contracts and Related Derivatives March 31, December 31, ------------- ------------ 2002 2001 ---- ---- (in millions) (in millions) Energy Trading and Derivative Contracts: Current Asset $ 9,327 $ 8,572 Long-term Asset 3,268 2,370 Current Liability (9,231) (8,311) Long-term Liability (3,066) (2,183) ------ ------ Net Fair Value of Energy Trading Contracts and Derivative Contracts 298 448 Less non-trading related derivatives (57) - --- --- Net Fair Value of Energy Trading Contracts and Related Derivatives $ 355 $ 448 ===== ===== The above net fair value of energy trading contracts and related derivatives includes $47 million, at March 31, 2002, in unrealized mark-to-market gains that are recognized in the income statement for the quarter ended March 31, 2002. Also included in the above net fair value of energy trading contracts and related derivatives are option premiums that are deferred until the related contracts settle and the portion of changes in fair values of electricity trading contracts that are deferred for ratemaking purposes.

(a) "(Gain) Loss from Contracts Realized or Otherwise Settled During the Period" include realized gains from energy trading contracts and related derivatives that settled during 2002 that were entered into prior to 2002, as well as during 2002. "Adjustments to gains or losses for Contracts Entered into and Settled During the Period" discloses the realized gains from settled energy trading contracts that were both entered into and closed within 2002 that are included in the total gains of $271 million, but not included in the ending balance of open contracts. (b) The "Fair Value of New Open Contracts When Entered Into During Period" represents the fair value of long-term contracts entered into with customers during 2002. 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 representative of the delivery location. (c) "Change in market Value of Contracts" represents the fair value change in the trading portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. (d) The net change in the fair value of energy trading contracts for 2002 that resulted in a decrease of $93 million ($355 million less $448 million) represents the balance sheet change. The net mark-to-market gain on energy trading contracts of $47 million represents the impact on earnings related to open trading contracts as of March 31, 2002. The difference is related primarily to settlement of prior period open energy trading contracts ($266 million decrease); regulatory deferrals of certain mark-to-market gains that were recorded as regulatory liabilities and not reflected in the income statement for those companies that operate in regulated jurisdictions; and deferrals of option premiums included in the above analysis, which do not have a mark-to-market income statement impact. Energy Trading Contracts (in thousands)

(a) "Prices Actively Quoted" represents the Company's exchange traded natural gas futures. (b) "Prices Provided by Other External Sources" represents the Company's positions in natural gas, power, and coal at points where over-the-counter broker quotes are available. Some prices from external sources are quoted as strips (one bid/ask for Nov-Mar, Apr-Oct, etc). Such transactions have also been included in this category. (c) "Prices Based on Models and Other Valuation Methods" contain the following: the value of the Company's adjustments for liquidity and counterparty credit exposure, the value of contracts not quoted by an exchange or an over-the-counter broker, the value of transactions for which an internally developed price curve was developed as a result of the long dated nature of certain transactions, and the value of certain structured transactions. PART II. OTHER INFORMATION Item 5. Other Information. AEP and APCo Reference is made to pages 17 and 18 of the Annual Report on Form 10-K for the year ended December 31, 2001 (2001 10-K) for a discussion of APCo's proposed transmission facilities. On April 23, 2002,the Forest Service issued its Supplemental Draft Environmental Impact Statement (SDEIS). In the SDEIS, the Forest Service identified the Wyoming-Jacksons Ferry Project as the preferred alternative. AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Reference is made to page 26 of the 2001 10-K for a discussion of the ozone and particulate matter National Ambient Air Quality Standards. On March 26, 2002, the U. S. Court of Appeals issued a unanimous decision holding that Federal EPA's promulgation of revised national ambient air quality standards for fine particulate matter and ozone was not arbitrary and capricious. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges. (b) Reports on Form 8-K: AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo OPCo, PSO, SWEPCo and WTU No reports on Form 8-K were filed during the quarter ended March 31, 2002. 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 signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto ----------------------- ---------------------------- Armando A. Pena Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer AEP GENERATING COMPANY APPALACHIAN POWER COMPANY CENTRAL POWER AND LIGHT COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY WEST TEXAS UTILITIES COMPANY By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto ----------------------- ---------------------------- Armando A. Pena Joseph M. Buonaiuto Vice President and Controller and Chief Accounting Officer Treasurer Date: May 13, 2002