10-Q 1 xq202mod.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 JUNE 30, 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 July 31, 2002 was 338,835,220. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended June 30, 2002 CONTENTS

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 Liquidity in the wholesale markets o Other risks and unforeseen events. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 Net income for the second quarter was $62 million or $0.19 per share, a decrease of $170 million or $0.53 per share. AEP had a loss of $107 million ($0.33 per share) year-to-date compared with net income of $498 million ($1.54 per share) in 2001. A decline in system sales and margins, natural gas trading losses and charges associated with the impairment and divesture of foreign retail electricity and gas supply and distribution operations account for the decrease. 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. A recently issued accounting pronouncement will require us to report our trading transactions on a net basis beginning in the third quarter of 2002. Our adoption of this new standard will lead to a material decrease in both revenues and purchased energy expense. See "New Accounting Standard" section in Registrants' Combined Management Discussion and Analysis of Financial Condition, Contingencies and Other Matters. 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. 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 About 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 second quarter of 2002 decreased by $170 million and by $605 million year-to-date. Reduced margins resulting from lower wholesale energy prices, losses from gas trading and marketing and losses associated with the impairment and divesture of SEEBOARD in the UK and CitiPower in Australia, two foreign retail electricity and gas supply and distribution investments, account for the decreases. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. Also contributing to the year-to-date decrease was a transitional goodwill impairment loss related to SEEBOARD and CitiPower from the adoption of SFAS 142 (see Note 2) that has been reported as a cumulative effect of an accounting change retroactive to January 1, 2002. The rise in revenues from gas marketing and trading can be attributed to an increase in gas marketing and trading volume, up 123% year-to-date, as we expanded our gas trading operations around Houston Pipe Line (HPL) that we acquired in June 2001. Gas marketing and trading volume also rose in the second quarter as the Company continued unwinding positions that led to a first-quarter gas trading loss. The decrease in electric marketing and trading revenues was largely driven by the decline in system sales due to lower wholesale energy prices that decreased margins.

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.

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 second quarter of 2001. Net generation decreased 1.2% 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 and 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 an expansion of gas trading activity around our HPL pipeline assets. 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; the expenses of recently acquired businesses MEMCO, a barging line; Quaker Coal; and two power plants in the UK; and a charge associated with the impairment and divestiture of CitiPower, a retail electricity and gas supply and distribution subsidiary in Australia. 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. On July 19, 2002, AEP, through a wholly owned subsidiary entered into an agreement to sell CitiPower, and recorded a net impairment charge totaling $125 million. $163 million (excluding tax of $65 million) was recorded in operating expenses in the second quarter of 2002 (see Note 3). $27 million of net impairment loss has been classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see Note 2) and has been recorded as a cumulative effect of an accounting change retroactive to January 1, 2002. Other income decreased due to the gain from the sale of Frontera in 2001. The decrease in income taxes is predominately due to a decrease in pre-tax income. The decrease in interest was primarily due to the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.

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

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 $335 million and $342 million and for income taxes was $307 million and $107 million in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $2 million in 2002 and $21 million in 2001, respectively. See Notes to Financial Statements beginning on page L-1.

See Notes to Financial Statements beginning on page L-1. AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 $345,000 or 17% for the second quarter and $432,000 or 11% for the year-to-date period due to limits on recovery of return on capital related to operating and in-service ratios of the Rockport Plant. Increased recoverable operating expenses resulted in a $1,139,000 increase in operation revenues for the second quarter. A decrease in operating revenues of $9,493,000 for the year-to-date period 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 the first quarter of 2002 decreased Rockport Plant's generation. Operating expenses increased 3% in the second quarter and declined 8% for the year-to-date period as follows:

N.M. = Not Meaningful Fuel expense increased in the second quarter due to an increase in generation and decreased due to the decline in generation for the year-to-date period. The increases in other operation expense are primarily due to higher costs for employee benefits and property insurance. Maintenance expense decreased significantly in the second quarter due to scheduled boiler inspection and repair being in the first quarter 2002 verses second quarter 2001. Maintenance costs declines in both periods reflect cost control efforts. The decrease in income taxes attributable to operations for the year-to-date period is primarily due to an over-accrual of state income taxes during first quarter of 2001 based on an estimate of higher taxable income for the year 2001 than actually occurred. The over-accrual was adjusted beginning in the second quarter of 2001 resulting in higher comparable income taxes for the second quarter of 2002. Interest charges declined 23% in the second quarter and 11% for the year-to-date period due to lower interest rates on short-term borrowing through AEP's money pool reflecting market conditions and lower outstanding balances.

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

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 $1,132,000 and $1,143,000 and for income taxes was $1,217,000 and $1,350,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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. Results of Operations Net income increased $10.2 million or 28% for the quarter due to decreased interest charges and lower general operating expenses. Net income increased $3.7 million or 4% for the year-to-date period due to decreases in interest charges offset in part by lower wholesale energy prices that reduced margins. The following analyzes the changes in operating revenues:

*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 sales by the AEP Power Pool due to lower wholesale energy prices. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. 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. Energy delivery revenues decreased due to the continuing economic recession in 2002. The changes in the components of operating expenses were:

Fuel expense increased due to an increase in electric generation as certain plants that had undergone boiler plant maintenance in 2001 were available for service in 2002. The decline in electricity marketing and trading purchases was mainly due to reduced prices caused by market conditions affecting the electricity trading industry. Purchases from AEP affiliates decreased due to the increase in internal generation as a result of certain plants being available for service in 2002 that had undergone boiler plant maintenance in 2001. The decrease in other operations expense in the quarter is mainly due to a decrease in transmission equalization charges caused by a reduction in APCo's MLR. The decrease in maintenance expense is primarily due to the effect of boiler plant maintenance performed on certain plants in 2001. Depreciation and amortization expense increased predominantly 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 4 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 increase in income taxes from operations for the quarter was due to an increase 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 market conditions affecting the electricity trading industry in the second quarter and by decreased electricity demand in the first quarter resulting from mild weather and the slow economic recovery. The decrease in interest charges for the quarter was due to increased allowances for borrowed funds as a result of increased construction expenditures and lower AEP money pool interest rates and balances. Interest charges decreased for the year-to-date period primarily due to increased allowances for borrowed funds as a result of increased construction expenditures, the retirement of first mortgage bonds on March 1, 2001 and lower AEP money pool interest rates.

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

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

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 $47,676,000 and $54,957,000 and for income taxes was $36,585,000 and $17,064,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $1,684,000 in 2001, respectively. 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 SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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, 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. 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 determine the fair value of 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 the "Quantitative and Qualitative Disclosure About Market Risk" section of Part I, Item 2 for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Second quarter net income decreased $19 million or 36%, while the year-to-date net income decreased $30 million or 34% primarily due to a slow economic recovery, a significant decline in wholesale prices and the replacement of sales to ultimate retail customers with sales to the REP's in the ERCOT area beginning on January 1, 2002. Operating revenues decreased $171 million for the quarter and $371 million year-to-date as shown below:

*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 as a result of the elimination of retail sales in the ERCOT area as of January 1, 2002 and a decrease in energy trading. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. Revenues from sales to AEP affiliates rose substantially due to the supplying of electricity to the newly formed affiliated REP's.Although CPL sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT area, total revenues received were lower because of the lower wholesale prices. Operating expenses declined 27% for the quarter and 31% year-to-date. The changes in the components of operating expenses were:

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 and lower wholesale prices due to the slow economic recovery. The decrease in maintenance and other operation expenses resulted from the effects of a STP nuclear plant 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.

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

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

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 $40,588,000 and $46,083,000 and for income taxes was $44,322,000 and $11,307,000 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 SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 increased $30.7 million or 146% in the second quarter of 2002 and $26.9 million or 46% in the year-to-date period due to an extraordinary loss recorded in the prior period second quarter to recognize a stranded asset resulting from deregulation. A decline in revenues is mainly due to a decrease in wholesale sales revenues due to lower wholesale energy prices. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. The following analyzes the changes in operating revenues:

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in electric marketing and trading revenues was largely driven by the decline in sales by the AEP Power Pool due to lower wholesale energy prices that decreased margins. Operating expenses declined 18% in the second quarter of 2002 and 17% in the year-to-date period of 2002. The changes in the components of operating expenses were:

Electricity marketing and trading purchases also declined due to lower wholesale energy costs driven by market conditions. Other operation expense increased in both periods primarily due to post retirement benefits expense and property insurance. Maintenance expenses decreased in the second quarter and year-to-date of 2002 due to boiler overhaul work that was performed during 2001. Expenses for maintaining distribution overhead lines and underground lines were also lower in both periods of 2002. The increase in income taxes for the second quarter is predominately due to an increase in pre-tax income. The decrease in income taxes for the year-to-date period 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 offset in part by a decrease in deferred state taxes. The decrease in nonoperating income which was offset by a larger decrease 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. 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.

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

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

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 $26,262,000 and $32,812,000 and for income taxes was $32,254,000 and $17,579,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $734,000 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 SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 $19.9 million or 73% in the second quarter and $41.2 million or 69% in the year-to-date period due primarily to a reduction in generation as a result of a refueling outage at both units of I&M's Cook Plant, reduced generation at Rockport Plant due to maintenance outages and lower margins on electricity sales. Operating revenues decreased 22% in the second quarter and 21% for the year-to-date period 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:

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. N.M. = Not Meaningful The decrease in electricity marketing and trading revenues was due to a decline in sales by the AEP Power Pool due to lower wholesale energy prices. 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 in each of the first two quarters of 2002 and both units of Rockport Plant underwent scheduled planned boiler maintenance in the first quarter of 2002. 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 in 2002. The changes in the components of operating expenses were:

Fuel expense decreased primarily due to the decline in generation reflecting the plant outages as both units of our nuclear plant were refueled in 2002. The decrease in electricity marketing and trading purchases resulted mainly from the decrease in energy prices. Purchases from AEP affiliates increased in the second quarter due to the timing of the Rockport Plant outages in first quarter of 2002 and in second quarter of 2001. I&M is required to purchase AEGCo's Rockport Plant generation under their unit power agreement. Other operation and maintenance expenses increased due to costs related to the nuclear plant refueling outages. The decrease in income tax expense attributable to operations is due primarily to a decline in pre-tax operating income. Nonoperating income and nonoperating expenses decreased 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.

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

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

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 $42,695,000 and $46,243,000 and for income taxes was $18,711,000 and $11,073,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $1,020,000 in 2001. See Notes to Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 the "Quantitative and Qualitative Disclosures About Market Risk" section of Part I, Item 2 for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Revenues decreased for both the quarter and year-to-date by 28% and 26%, respectively. These declines were offset by improvements in both operating and nonoperating margins resulting in increases in net income of 91% and 58% or $2.5 million for the quarter and $5.7 million year-to-date. The following analyzes the changes in operating revenues:

*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 in both the first and second quarter. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions.

Year-to-date fuel expense increased as a result of fewer credits from profits on trading power and increases in the cost of coal. Under the Kentucky commission's fuel clause mechanism, a portion of the profits on wholesale transactions are shared with the customers. This sharing is recognized through credits to fuel expense. As margins on wholesale electricity marketing and trading transactions declined, the amount of credits shared through the fuel clause adjustment mechanism decreased. The decreases in purchased power expense were attributable to lower prices resulting from general market trends and reduced volume of electricity traded stemming from continued soft demand in the wholesale power market. Other operation expense decreased due to reduced consumption of emission allowances, increased AEP transmission equalization credits and reduced accruals for trading incentive compensation. Under the AEP East Region Transmission Agreement, KPCo and certain affiliates share the costs associated with the ownership of their transmission system based upon each company' peak demand and investment. A decrease in KPCo's peak demand relative to its affiliates' peak demand was the main reason for the increase in transmission equalization credits. Maintenance expense increased as a result of planned power plant outages. Taxes other than income taxes increased with increases in payroll taxes and real and personal property taxes. Income taxes year-to-date have increased primarily as a result of increases in pre-tax income. Decreases in nonoperating income and expenses were due to decreases 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.

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

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

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 $13,485,000 and $13,692,000 and for income taxes was $7,024,000 and $6,010,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $22,021 and $760,000 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 SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 $44.8 million in the second quarter of 2002 and $55.4 million in the year-to-date period due to the effect of an extraordinary loss recorded in the second quarter of 2001 to recognize a stranded asset resulting from deregulation. The decline in revenues is mainly due to a decrease in electric marketing and trading revenues due to lower wholesale energy prices. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. The following analyzes the changes in operating revenues:

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Operating expenses declined 22% in the second quarter of 2002 and 21% in the year-to-date period of 2002. The changes in the components of operating expenses were:

The fuel expense decrease reflects a reduction of 17% in the average cost fuel for generation offset in part by a 10% increase in MWH generated. Electricity marketing and trading purchases declined due to lower wholesale energy costs driven by market conditions. Other operation expense increased in both periods primarily due to post retirement benefits expense. Maintenance expenses decreased in the second quarter and year-to-date of 2002 due to boiler overhaul work that was performed during 2001. Depreciation expense increased in both periods due to the placement of selective catalytic reduction (SCR) technology in service at the Gavin Plant in the second quarter of 2001. The increase in income taxes for both periods is predominately due to an increase in pre-tax income. The decrease in nonoperating income as well as a decrease in nonoperating 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. The decrease in interest was primarily due to a slightly smaller decrease in the outstanding balances of long-term debt in both periods as compared to year end balances in both periods, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.

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

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

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

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

Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $36,585,000 and $40,580,000 and for income taxes was $29,187,000 and $54,694,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $98,000 and $522,000 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 SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 AEP's 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 Net income declined by 2.5% for the quarter and 4% for the year-to-date period as substantial decreases in revenues were nearly offset by comparable decreases in operating expenses. The following analyzes the changes in operating revenues:

*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 AEP marketing and trading revenues shared with PSO. Revenues from AEP's power marketing and trading operations declined as a result of lower prices for wholesale power transactions. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. Significant change in operating expenses are as follows:

The decrease in fuel expense was primarily due to amortization of previously overrecovered fuel costs through the fuel clause recovery mechanism and a reduction in the cost of fuel reflecting lower market prices for natural gas and fuel oil. The decrease in electric marketing and trading purchases resulted mainly from the decrease in energy prices. The increase in the quarter and the decrease year-to-date in purchases from AEP affiliates results mainly from the availability of internal generation. Other operation expense decreased in the year-to-date period primarily due to lower transmission, administrative, and customer service expenses. Maintenance expense decreased in the second quarter due primarily to lower production power plant costs and distribution costs for overhead and underground facilities. Year-to-date 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 for both the quarter and year-to-date due to the cost of repowering Northeast Station Units 1 & 2.

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

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

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 $17,870,000 and $19,011,000 and for income taxes was $2,575,000 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 SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 increased slightly in the second quarter and decreased $11 million or 30%, for the first half of 2002. The decrease for the first half of 2002 resulted from reduced wholesale prices and margins due to a decline in demand for electricity which resulted from mild weather and a slow economic recovery. Operating revenues decreased 19% in the second quarter and 20% for the year-to-date period due to decreased wholesale marketing and trading prices. The changes in the components of revenues were as follows:

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. All of the components of revenues decreased in 2002 as a result of reduced wholesale prices due to reduced energy demand as a result of a decrease in marketing and trading activity, and the slow economic recovery. Operating expenses decreased 20% in the second quarter and the year-to-date period due to a significant decrease in electricity marketing and trading purchases and fuel expense.

Fuel expense decreased due to lower natural gas prices as a result of a mild winter and the slow economic recovery. Decreasing purchased power prices resulted in decreases to both electricity marketing and trading purchases and electricity purchases from AEP affiliates for the second quarter and first half of 2002. The first half of 2002 was also affected by milder than normal winter. The acquisition of Dolet Hills mining operation in June 2001 caused other operation expense to increase in 2002. Maintenance expense decreased for the first half of 2002 as a result of costs incurred last year to restore service and make repairs following a severe ice storm. The decrease in depreciation and amortization expense was due primarily to a decrease in excess earnings accruals under the Texas restructuring legislation offset by new expenses from the acquisition of the Dolet Hills mining operation. The increase in income taxes for the second quarter of 2002 is predominately due to the reversal of deferred taxes in excess of the statutory tax rate, and an increase in pre-tax income. Income taxes attributable to operations decreased for the first half of 2002 due to a significant decrease in pre-tax income. Nonoperating income decreased for the first half of 2002 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 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.

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

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

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 $21,331,000 and $25,743,000 and for income taxes was $24,479,000 and $4,144,000 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 SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 Southwest Power Pool (SPP) 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 that was unbundled from WTU and also sells its generation to other REPs in the area. 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 the "Quantitative and Qualitative Disclosures about Market Risk" section of Part I, Item 2 for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $5.5 million or 89% for the quarter and $2.4 million or 34% for the year-to-date period. The decreases are primarily due to a downturn in the overall economy, a significant decline in wholesale prices, and the diversion of retail sales from the ultimate retail customer to the REPs in the ERCOT region as of January 1, 2002. Overall operating revenues decreased $50.8 million for the quarter and $104.6 million year-to-date as shown below:

*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 primarily as a result of the elimination of retail electricity sales in the ERCOT region as of January 1, 2002. Also contributing to the decrease was a decline in prices for power trading transactions. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. Sales to AEP affiliates increased primarily due to increased revenues to the newly-created affiliated REP. Although WTU sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT region, total revenues received were lower because of the lower wholesale prices. Operating expenses declined $43.7 million for the quarter and $103.3 million year-to-date, primarily due to decreases in fuel expense and purchased power. Changes in the components of operating expenses are shown below:

Fuel expense decreased significantly primarily due to a decrease in the average unit cost of fuel as a result of lower spot market natural gas prices. The decline in electricity marketing and trading purchases was mainly due to reduced prices caused by decreased electricity demand driven largely by the downturn in the economy. The quarter-to-date decrease in income taxes is predominately due to a decrease in pre-tax income. Nonoperating income and expense increased significantly during the quarter and year-to-date as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties.

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

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

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

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

Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $9,841,000 and $10,139,000 and for income taxes was $2,408,000 and ($2,957,000) in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1.

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. In the second quarter of 2002 we completed initial testing for goodwill impairment of our UK and Australian retail electricity and supply operations. As a result of that testing, we determined that we had a net transitional impairment loss of $350 million, which is reported as a cumulative effect of an accounting principle change. 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 six months ended June 30, 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. The transitional impairment loss related to SEEBOARD goodwill, which is reported as a cumulative effect of an accounting change, is excluded from the above schedule. Under SFAS 144, SEEBOARD's assets, including goodwill, are reported as available for sale on one line in the balance sheet. See Note 3 related to the sale of SEEBOARD and CitiPower. 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. Net Income Six Months Ended June 30, 2002 2001 ---- ---- (in millions) Reported Net Income (Loss) $(107) $498 Add back: Goodwill amortization - 19 Add back amortization for intangibles with indefinite lives under SFAS 142 - 4 ----- ---- Adjusted Net Income (Loss) $(107) $521 ===== ==== Earnings Per Share (Basic and Dilutive) Six Months Ended June 30, 2002 2001 ---- ---- Reported Earnings (Loss) per Share $(0.33) $1.54 Add back: Goodwill amortization - 0.06 Add back amortization for intangibles with indefinite lives under SFAS 142 - - ------ ----- Adjusted Earnings (Loss) per Share $(0.33) $1.60 ====== ===== Acquired Intangible Assets Acquired intangible assets subject to amortization are $42 million at June 30, 2002 and $53 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 $2 million for the six months ended June 30, 2002. Estimated aggregate amortization expense is $4.5 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 $324 million and $421 million at June 30, 2002 and December 31, 2001. The reduction in the carrying values of the CitiPower retail supply and distribution licenses since December 31, 2001 results from impairment charges recorded in the second quarter of 2002 and changes in the foreign currency exchange rate. See Note 3 related to the pending sale of CitiPower. 3. ACQUISITIONS AND DISPOSITIONS Disposition of SEEBOARD On June 18, 2002, AEP, through a wholly owned subsidiary, entered into an agreement, subject to European Union ("EU") approval, to sell its consolidated subsidiary SEEBOARD, a UK electricity supply and distribution company. EU approval was received July 25, 2002 and the sale was completed on July 29, 2002. AEP received approximately $1.04 billion in cash from the sale, subject to a working capital true up, and the buyer assumed SEEBOARD debt of approximately $1.12 billion, resulting in a net impairment loss of $345 million using June 30, 2002 exchange rates. In accordance with SFAS 144 the results of operations of SEEBOARD have been classified as discontinued operations in the accompanying financial statements. $22 million of the net impairment loss was recorded in the second quarter and is classified as discontinued operations. The remaining $323 million of the net loss has been classified as a transitional impairment loss from the adoption of SFAS 142 (see Note 2) and has been reported as a cumulative effect of an accounting change retroactive to January 1, 2002. Proceeds from the sale of SEEBOARD were used to pay down bank facilities and short-term debt. The assets and liabilities of SEEBOARD have been aggregated on the balance sheet as assets held for sale and liabilities held for sale. The major classes of SEEBOARD's assets and liabilities held for sale are: June 30, 2002 December 31, 2001 (in millions) Assets Current Assets $ 324 $ 324 Plant, Property and Equipment, Net 1,457 1,283 Goodwill 867 1,129 Other Assets 102 96 ------ ------ Total Assets Held For Sale $2,750 $2,832 ====== ====== Liabilities Current Liabilities $ 881 $ 752 Long-term Debt 739 701 Deferred Income Taxes 327 268 Other Liabilities 8 77 ------ ------ Total Liabilities Held For Sale $1,955 $1,798 ====== ====== Disposition of CitiPower On July 19, 2002, AEP, through a wholly owned subsidiary entered into an agreement to sell Citipower, a retail electricity and gas supply and distribution subsidiary in Australia. AEP will receive net cash of approximately $181 million and the buyer will assume CitiPower debt of approximately $774 million. The transaction is subject to a net asset true up and is anticipated to close in the third quarter of 2002. AEP recorded a net impairment charge totaling $125 million. $98 million was recorded in the second quarter of 2002 and relates to an impairment loss on the distribution license intangible asset. The remaining $27 million of net impairment loss has been classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see Note 2) and has been recorded as a cumulative effect of an accounting change retroactive to January 1, 2002. Since the transaction occurred after the balance sheet date of June 30, 2002, but before the issuance of the financial statements, CitiPower's results of operation were not classified as discontinued operation in accordance with SFAS 144. CitiPower's results of operation will be reclassified as discontinued operations in the third quarter. Also, CitiPower's assets and liabilities have not been aggregated on the balance sheet as assets held for sale and liabilities held for sale. This too will occur in the third quarter in accordance with SFAS 144. Acquisition of European Trading 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. Results of operations are included in AEP's 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. REPs Transfer 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. 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. 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. On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users - Ohio and American Municipal Power - Ohio filed a complaint with the PUCO alleging that CSPCo and OPCo have violated the PUCO's orders regarding implementation of their transition plan and violated other applicable law by failing to participate in an RTO. The complainants seek, among other relief, an order from the PUCO suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred and imposing a $25,000 per company forfeiture for each day AEP fails to comply with its commitment to transfer control of transmission assets to an RTO. Due to FERC delays in the approval of our RTO filings, CSPCo and OPCo have been unable to implement their RTO participation plan. Management is unable to predict the timing of FERC's final approval of RTOs and the timing of an RTO being operational or the outcome of this proceeding before the PUCO. 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. Pursuant to 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. However, the Virginia restructuring law allows rates to be adjusted in certain circumstances including changes in fuel prices (see Note 5). See the 2001 Annual Report for further discussion of Virginia restructuring. 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 provisions 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. Two unaffiliated Texas utilities reached settlement agreements approved by the PUCT regarding recovery of stranded generation costs. CPL is not presently engaged in any settlement discussions with the PUCT. CPL's generation-related regulatory assets subject to recovery as stranded costs are approximately $1.1 billion of which $949 million has been securitized pending the 2004 true-up proceeding's determination of stranded costs recovery including the recovery of stranded generation-related regulatory assets. WTU and SWEPCo do not have any recoverable Texas generation-related regulatory assets. 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. As discussed in Note 5 "Rate Matters", WTU filed its final fuel reconciliation for its ERCOT service territory with the PUCT in June 2002. 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 June 30, 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. West Virginia Restructuring - Affecting AEP and APCo As discussed in Note 7 of the 2001 Annual Report, the West Virginia Legislature in 2000 approved an electricity restructuring plan. Before implementation of the plan, the West Virginia Legislature needed to enact legislation to preserve the revenues of state and local government. In the past two legislative sessions, which usually end in March each year, the West Virginia Legislature has not enacted the required legislation. Due to the lack of activity, the Public Service Commission of West Virginia closed two proceedings related to electricity restructuring in the summer of 2002. The two West Virginia Commission orders related to the dismissal of the respective dockets intended originally to determine whether West Virginia should deregulate the generation business, and to develop the Commission's Deregulation Plan and related Commission rules to implement the Plan. Management is currently reviewing the impact of these two orders to determine if the West Virginia Jurisdiction meets the conditions to apply SFAS 71. 5. RATE MATTERS Fuel Reconciliation - Affecting AEP and WTU In June 2002 WTU filed with the PUCT to reconcile fuel costs and to defer any unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 2000 through December 2001 will be the final fuel reconciliation for WTU's ERCOT service territory. Texas restructuring legislation eliminated fuel clause recovery mechanisms beginning in 2002 for the ERCOT area and provides for a 2004 true-up proceeding to determine recovery of final fuel balances. At December 31, 2001, the under-recovery balance associated with WTU's ERCOT service area was $26.4 million including interest. WTU also requested authority to surcharge its SPP customers. WTU's SPP customers will continue to be subject to fuel reconciliations until competition begins. The under-recovery balance at December 31, 2001 for WTU's service within SPP was $0.7 million including interest. During the reconciliation period, WTU incurred $292.7 million of eligible fuel and fuel related expenses serving both ERCOT and SPP retail customers. The PUCT is not expected to act on this issue prior to the end of 2002. FERC Wholesale Fuel Complaint - Affecting AEP and WTU As discussed in Note 5 of 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 plant 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 AEP subsidiaries which are the Texas retail electric providers (REP) for the ERCOT area, CPL REP and WTU REP, filed with the PUCT in May 2002 to increase the fuel portion of their "price-to-beat" rate in compliance with the Texas Restructuring Legislation and rules issued by the PUCT. 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. On July 15, 2002, the PUCT required further hearings to reconsider the validity of their existing rules for fuel factor adjustments. On July 24, 2002, CPL REP and WTU REP filed a petition with the District Court seeking an injunction commanding the PUCT to proceed to a final order based on the existing rules and prohibiting the PUCT from conducting a remand proceeding. The District Court issued an order on August 9, 2002 requiring the PUCT to comply with the existing rules. CPL REP and WTU REP are unable to predict the response of the PUCT to the Court's order and when or if they will be able to adjust the fuel portion of their "price-to-beat" rates. A delay or denial of CPL REP's or WTU REP's request to increase the fuel portion of their "price-to-beat" rates could reduce AEP's future results of operations and cash flows. FERC Transmission Rates - Affecting AEP, CPL, PSO, SWEPCo and WTU In November 2001 FERC issued an order requiring CPL, PSO, SWEPCo and WTU to submit revised open access transmission tariffs, and calculate and issue refunds for overcharges from January 1, 1997. The order resulted from a remand by an appeals court of a tariff compliance filing order issued in November 1998 that had been appealed by certain customers. CPL and WTU recorded refund provisions of $1.7 million and $0.7 million, respectively, including interest in 2001 for this order. PSO and SWEPCo recorded $100,000 each in 2001 for this order making the AEP total $2.6 million. On July 26, 2002, FERC approved a revised open access transmission tariff. Refunds are to be completed within 30 days. The amount of the refunds are being calculated. Management does not expect the refunds to be materially different from the amounts provided in 2001. Texas Transmission Cost Recovery - Affecting AEP, CPL and WTU On July 15, 2002, CPL and WTU filed a petition to update their Transmission Cost Recovery Factor (TCRF) as of September 1, 2002. The TCRF allows for the pass through of changes in wholesale transmission costs billed to the distribution service providers by transmission service providers. CPL and WTU are seeking TCRF increases of $0.8 million and $0.2 million, respectively. The requested increases include amounts for an interim increase granted by the PUCT for one unaffiliated transmission service provider. The PUCT has not ruled on whether interim amounts qualify for a TCRF. If the interim amount is disallowed, CPL's and WTU's increase would be reduced to $0.4 million and $0.1 million, respectively. Virginia Fuel Rate Filing - Affecting AEP and APCo In July 2002 APCo filed with the Virginia SCC requesting an increase in fuel rates effective January 1, 2003. The request would increase annual revenues by approximately $28 million. A public hearing is scheduled for September 23, 2002 related to this filing. 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, gas and coal. 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 six months ended June 30, 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 Equity Units In June 2002, AEP issued 6.9 million equity units at $50 per unit ($345 million). Each equity-linked security consists of a forward purchase contract and a senior note issued by AEP. The forward purchase contracts obligate the holders to purchase from AEP shares of AEP common stock on the stock purchase date of August 16, 2005. The purchase price per equity unit is $50. The number of shares to be purchased under the forward purchase contract will be determined under a formula based upon the average closing price of AEP common stock near the stock purchase date. The senior notes have a principal amount of $50 each and mature on August 16, 2007. The senior notes are pledged as collateral to secure the purchase of common stock under the forward purchase contracts. Holders may satisfy their obligation under the forward purchase contracts by allowing the senior notes to be remarketed. The proceeds from the remarketing will be used to purchase a portfolio of U.S. treasury securities that holders pledge to AEP to secure their obligations under the forward purchase contracts. Alternatively, holders may choose to continue holding the senior notes and use other resources as consideration for the purchase of stock under the forward purchase contracts. AEP will make quarterly interest payments on the senior notes at the initial annual rate of 5.75%. The interest rate can be reset through a remarketing, which is initially scheduled for May 2005. AEP will pay the purchaser contract adjustment payments at the annual rate of 3.50% on the forward purchase contracts. The present value of the contract adjustment payments has been recorded as a liability in equity unit senior notes offset by a charge to paid-in capital. Interest payments on the senior notes are reported as interest expense and contract adjustment payments are charged against the liability. Accretion of the contract adjustment payment liability is reported as interest expense. We apply the treasury stock method to the equity units to calculate diluted earnings per share. Common Stock In June 2002, AEP issued 16 million shares of common stock at $40.90 per share through an equity offering and received net proceeds of $634 million. Proceeds from the sale of equity units and common stock were used to pay down short-term debt and establish a cash liquidity reserve fund. Issuances and Retirements of Long-term Debt 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 4). 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 Other issuances and retirements of long-term debt and other securities during the first six months of 2002 were: Type of Principal Interest Company Debt Amount Rate Due Date ------- ------- --------- -------- -------- Issuances (in millions) (%) --------- APCo Senior Unsecured Notes $ 450 4.80 2005 I&M Installment Purchase Contracts 50 4.90 2025 KPCo Senior Unsecured Notes 125 5.50 2007 SWEPCo Senior Unsecured Notes 200 4.50 2005 Non-Registrant AEP Subs. Revolving Credit Agreement 143 Variable 2003 Retirements CPL Senior Unsecured Notes $150 Variable 2002 I&M Installment Purchase Contract 50 Variable 2014 KPCo First Mortgage Bonds 15 7.90 2023 OPCo First Mortgage Bonds 5 8.80 2022 SWEPCo Senior Unsecured Notes 150 Variable 2002 Non-Registrant AEP Subs. Notes Payable 12 Variable 2002-2007 Related Activities AEP Credit renewed its sale of receivables agreement during the second quarter of 2002. At June 30, 2002, the sale of receivables agreement provided commitments of $600 million to purchase receivables from AEP Credit, of which $455 million was outstanding. All of the receivables sold, represented affiliate receivables. The commitment's new term under the sale of receivables agreement will remain at $600 million until May 28, 2003. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of the receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivables less an allowance for anticipated uncollectible accounts. In April 2002, AEP closed on a bridge loan facility consisting of a $1,125 million 364-day revolving credit facility and a $600 million 364-day term loan facility to prepare for corporate separation. We borrowed $600 million under the term loan facility and loaned the amounts borrowed to CPL ($200 million), CSPCo ($250 million) and OPCo ($150 million). Pricing on the facilities and intercompany loans is based on a spread over LIBOR. AEP has available $3.5 billion in bank facilities consisting of a $2.5 billion 364-day facility and a $1.0 billion five-year facility maturing on May 31, 2005. On May 22, 2002, AEP renewed the $2.5 billion facility for another year extending the maturity date to May 21, 2003. Upon the issuance of the $450 million 4.80% unsecured notes due in 2005, APCo announced the following debt would be redeemed in July; $75 million of 8.25% junior subordinated debentures due 2026, $90 million of 8% junior subordinated debentures due 2027, $40 million of 6.65% first mortgage bonds due 2003 and $30 million of 6.85% first mortgage bonds due 2003. Upon issuance of the $125 million 5.50% unsecured notes due 2007, KPCo announced the redemption of $45 million of first mortgage bonds on August 1. In preparation for corporate restructuring, management announced the following bonds would be redeemed in July, CSPCo's $72.8 million remaining outstanding principal amount of the 8-3/8% junior subordinated debentures due 2025 and $40 million of the 7.92% junior subordinated debentures due 2027 and OPCo's $85 million remaining outstanding principal of the 8.16% junior subordinated debentures due 2025 and $50 million of the 7.92% junior subordinated debentures due 2027. 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 which could have resulted in the imposition of 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. Most of those states have submitted conforming compliance plans and the appeal filed by AEP subsidiaries and other utilities in the D.C. Circuit Court to review this ruling has been dismissed. 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 imposed 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 responded 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 in May 2002 advising that no changes in the growth factors used to set the NOx budgets were warranted. In June 2002 AEP subsidiaries joined other utilities and industrial organizations in seeking a review of Federal EPA's action in the D.C. Circuit Court. 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 June 30, 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 160 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 purportedly owned the cushion gas had entered into a financing arrangement with a group of banks. These banks purported to have certain rights to the cushion gas in certain events of default. We have been informed by the banks of Bammel Trust's default under the terms of their financing agreement. The banks filed a lawsuit against HPL seeking a declaratory judgment that they have a valid and enforceable security interest in this cushion gas which would permit them to cause the withdrawal of this gas from the storage facility. Management is unable to predict the outcome of this lawsuit or its impact on results of operation and cash flows. 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 the lawsuit related to the cushion gas financing agreement, our future results of operations, cash flows and possibly financial condition could be adversely impacted. Energy Market Investigations - Affecting AEP In February 2002 the FERC issued an order directing its Staff to conduct a fact-finding investigation into whether any entity, including Enron Corp., manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward. In April 2002 AEP furnished certain information to the FERC in response to their related data request. Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron 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 required senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative. Senior management complied with the order and denied our involvement with those trading practices. On May 21, 2002, the FERC issued a further data request with respect to this matter to us and over 100 other market participants requesting information for the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back" trading in the Western System Coordinating Council (WSCC), which involves the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price (collectively, "wash sales"). Similarly, on May 22, 2002, the FERC issued an additional data request with respect to this matter to us and other market participants requesting similar information for the same period with respect to the sale of natural gas products in the WSCC and Texas. After reviewing our records, we responded to the FERC that we did not participate in any "wash sale" transactions involving power or gas in the relevant market. We further informed the FERC that certain of our traders did engage in trades on the Intercontinental Exchange, an electronic electricity trading platform owned by a group of electricity trading companies, including us, on September 21, 2001, the day on which all brokerage commissions for trades on that exchange were donated to charities for the victims of the September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a "wash sale" but do have certain characteristics in common with such sales. In response to a request from the California attorney general for a copy of AEP's responses to the FERC inquires, we provided the pertinent information. The PUCT also issued similar data requests to AEP and other power marketers. AEP responded to such data request by the July 2, 2002 response date. The US Commodity Futures Trading Commission (CFTC) issued a subpoena to us on June 17, 2002 requesting information with respect to "wash sale" trading practices. We responded to CFTC. In addition, the US Department of Justice made a civil investigation demand to us and other electric generating companies concerning their investigation of the Intercontinental Exchange. We have recently completed a review of our trading activities in the United States for the last three years involving sequential trades with the same terms and counterparties. The revenue from such trading is not material to our financial statements. We believe that substantially all these transactions involve economic substance and risk transference and do not constitute "wash sales". FERC Proposed Security Standards In July 2002 the FERC published for comment its proposed security standards as part of the Standards for Market Design (SMD). These standards are intended to ensure all market participants have a basic security program that effectively protects the electric grid and related market activities and require compliance by January 1, 2004. The impact of these proposed standards is far-reaching and has significant penalties for non-compliance. These standards apply to marketers, transmission owners, and power producers. For the AEP System this includes: regulated and non-regulated power generation plants, transmission systems, distribution systems, regulated and non-regulated energy trading, and related areas of business. These standards represent a significant effort that will impact the entire AEP System. Unless the cost can be recovered from customers, results of operations and cash flows would be adversely affected. FERC Market Power Mitigation A FERC order on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power systems status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows. Minority Interest in Finance Subsidiary - Affecting AEP In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated subsidiary, and sold a non-controlling preferred member interest in Caddis to an unconsolidated special purpose entity (Steelhead) for $750 million. Under the provisions of the Caddis formation agreements, the preferred member interest receives quarterly a preferred return equal to an adjusted floating reference rate. The $750 million received replaced interim funding used to acquire Houston Pipe Line Company in June 2001. The preferred interest is supported by natural gas pipeline assets and $321.4 million of preferred stock issued by an AEP subsidiary to the AEP affiliate which has the managing member interest in Caddis. Such preferred stock is convertible into AEP common stock upon the occurrence of certain events including AEP's stock price closing below $18.75 for ten consecutive trading days. AEP can elect not to have the transaction supported by such preferred stock if the preferred interest were reduced by $225 million. In addition, Caddis has the right to redeem the preferred member interest at any time. The initial period of the preferred interest is through August 2006. At the end of the initial period, Caddis will either reset the preferred rate, re-market the preferred member interests to new investors, redeem the preferred member interests, in whole or in part including accrued return, or liquidate in accordance with the provisions of applicable agreements. Steelhead has the right to terminate the transaction and liquidate Caddis upon the occurrence of certain events including a default in the payment of the preferred return. Steelhead's rights include: forcing a liquidation of Caddis and acting as the liquidator, and requiring the conversion of the $321.4 million of AEP subsidiary preferred stock into AEP common stock. If the preferred member interest exercised its rights to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the preferred member interest. Liquidation of the preferred interest or of Caddis could negatively impact AEP's liquidity. Caddis and the AEP subsidiary which acts as its managing member are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from AEP. The results of operations, cash flows and financial position of Caddis and such managing member are consolidated with AEP for financial reporting purposes. The preferred member interest and payments of the preferred return are reported on AEP's income statement and balance sheet as Minority Interest in Finance Subsidiary. Foreign Distribution Projects - Affecting AEP We own a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 we converted a $66 million note receivable and accrued interest into a 20% equity interest in Caiua (Brazilian electric operating company), a subsidiary of Vale. Vale and Caiua have experienced losses from operations and our investment has been affected by the devaluation of the Brazilian Real. The cumulative equity share of operating and foreign currency translation losses through June 30, 2002 is approximately $47 million and $58 million, respectively, net of tax. The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 is approximately $46 million and $54 million, respectively, net of tax. Both investments are covered by a put option, which, if exercised, requires our partners in Vale to purchase our Vale and Caiua shares at a minimum price equal to the U.S. dollar equivalent of the original purchase price. As a result, management has concluded that the investment carrying amount should not be reduced below the put option value unless it is deemed to be an other than temporary impairment and our partners in Vale are deemed unable to fulfill their responsibilities under the put option. In January 2002, management evaluated through an independent third-party, the ability of its Vale partners to fulfill their responsibilities under the put option agreement and concluded that our partners should be able to fulfill their responsibilities. Management believes that the decline in the value of its investment in Vale in US dollars is not other than temporary. As a result and pursuant to the put option agreement, these losses have not been applied to reduce the carrying values of the Vale and Caiua investments. As a result we will not recognize any future earnings from Vale and Caiua until the operating losses are recovered. In addition, our partners have a principal payment due in November 2002 in the amount of $55 million. Our partners plan to refinance the debt before the payment comes due. Should the impairment of our investment become other than temporary due to our partners in Vale becoming unable to fulfill their responsibilities, it would have an adverse effect on future results of operations. Management will continue to monitor both the status of the losses and its partners ability to fulfill their obligations under the put option. Investments in Telecommunications Companies - Affecting AEP AEP provides telecommunications services to business and telecommunication companies through a broadband fiber optic network. AEP conducts its operations through an ownership interest in a joint venture, AFN Networks, LLC (AFN), and through its AEP Communications and C3 subsidiaries. Management is currently reassessing its telecommunications business strategy and considering certain changes that could include additional investment in AFN, possible financial control of the joint venture's operations, and a reorganization of its other telecommunications operations in order to optimize the value of such assets. The review of the telecommunications business strategy is expected to be completed in the third quarter of 2002. In connection with the completion of this assessment and reorganization activities, management will review its investment in telecommunication companies for any impairment of value. Management is unable to determine whether there is any impairment until such evaluation is complete. At June 30, 2002 AEP's investment in telecommunications companies was approximately $252 million. 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 and year-to-date period ended June 30, 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. In April 2002 Moody's Investors Service placed AEP and five of its registrant subsidiaries (CPL, CSPCo, OPCo, SWEPCo and WTU) on credit rating watch for possible downgrade. The review of SWEPCo could conclude with more than a one notch downgrade. Moody's confirmed the credit ratings of four of AEP registrant subsidiaries (APCo, I&M, KPCo, and PSO). In May 2002, Standard & Poors confirmed AEP and its registrant subsidiaries senior unsecured debt rating. First Mortgage Bond ratings of all the registrant subsidiaries were lowered to "BBB+" from "A". AEP's commercial paper programs short-term ratings of A2 and P2 were confirmed by Moody's and Standard and Poor's, respectively. The review of the companies' debt position and credit rating is being completed in anticipation of corporate separation. We are working with the rating agencies 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. At June 30, 2002, the ratings of AEP's subsidiaries' first mortgage bonds are listed in the following table: Company Moody's S&P Fitch APCo A3 BBB+ A- CPL A3 BBB+ A CSPCo A3 BBB+ A I&M Baa1 BBB+ BBB+ KPCo Baa1 BBB+ BBB+ OPCo A3 BBB+ A- PSO A1 BBB+ A+ SWEPCo A1 BBB+ A WTU A2 BBB+ A The ratings at June 30, 2002 for senior unsecured debt are listed in the following table: Company Moody's S&P Fitch aEP Baa1 BBB+ BBB+ AEP Resources* Baa1 BBB+ BBB+ APCo Baa1 BBB+ BBB+ CPL Baa1 BBB+ BBB+ CSPCo A3 BBB+ A- I&M Baa2 BBB+ BBB KPCo Baa2 BBB+ BBB OPCo A3 BBB+ BBB+ PSO A2 BBB+ A SWEPCo A2 BBB+ A- WTU - BBB+ - *The rating is for a series of senior notes issued with a Support Agreement from AEP. 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, convertible securities, 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 come from the parent company's commercial paper program and are loaned to subsidiaries through inter-company notes. The commercial paper program is backed by $3.5 billion in bank facilities of which $1 billion matures in May 2005 and $2.5 billion matures in May 2003. At June 30, 2002, approximately $1.4 billion was outstanding in commercial paper. In addition, AEP has a $1.725 billion bank facility maturing in April 2003 that is available for debt refinancing in anticipation of corporate separation. At June 30, 2002, $600 million was outstanding under that facility. We anticipate repayment of the facility through the issuance of bonds by certain subsidiaries. The pricing on the facility is based on a spread over LIBOR. During the first half of 2002 cash flow from operations was $96 million, including $107 million from a net loss and $912 million from depreciation, amortization and deferred taxes. Capital expenditures including acquisitions were $785 million and dividends on common stock were $387 million. Cash from operations and the issuance of common stock, common equity units and transition funding bonds provided funds to 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 third quarter of 2002. Long-term funding arrangements are often complex and take time to complete. In anticipation of corporate separation, CPL and WTU both initiated tenders for their first mortgage bonds in July. The cumulative amounts tendered for CPL and WTU was $401 million and $89 million, respectively. In order to pay for a portion of these retired bonds, as well as previously retired bonds, AEP borrowed $600 million under the term loan facility. In turn, AEP loaned the amounts it borrowed to CPL ($200 million), CSPCo ($250 million) and OPCo ($150 million). In June 2002 we issued 16 million shares of AEP common stock and 6.9 million equity units. We used the proceeds from the issuances of $968 million to establish a $300 million cash liquidity reserve and to reduce debt. The cash reserve enhances our liquidity and is included in cash and cash equivalents on AEP's consolidated balance sheet. Total consolidated plant and property additions including capital leases for the six months ended June 30, 2002 were $865 million. The following table shows the plant and property additions by certain registrant subsidiaries: Company Amount ------- ------ (in millions) APCo $129 CPL 65 I&M 69 OPCo 158 SWEPCo 36 Pending and 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 July 2002 we completed the sale of SEEBOARD, an energy delivery and power supply business in the UK, receiving cash of approximately $1.04 billion which will be used to reduce debt. The sale resulted in a loss of $345 million (See Note 3). We have 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. In July 2002 we reached an agreement to sell CitiPower, our energy delivery and retail supply businesses in Australia. It is anticipated that AEP will receive approximately $180 million in cash and the sale will result in a $125 million loss (See Note 3). AEP provides telecommunications services to business and telecommunication companies through a broadband fiber optic network. AEP conducts its operations through an ownership interest in a joint venture, AFN Networks, LLC (AFN), and through its AEP Communications and C3 subsidiaries. Management is currently reassessing its telecommunications business strategy and considering certain changes that could include additional investment in AFN, possible financial control of the joint venture's operations, and a reorganization of its other telecommunications operations in order to optimize the value of such assets. The review of the telecommunications business strategy is expected to be completed in the third quarter of 2002. In connection with the completion of this assessment and reorganization activities, management will review its investment in telecommunication companies for any impairment of value. Management is unable to determine whether there is any impairment until such evaluation is complete. At June 30, 2002 AEP's investment in telecommunications companies was approximately $252 million. 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 six state regulatory commissions and other major 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 RTOs. 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 competitive, reliable electric service and rejected the Alliance RTO's filing. In May 2002 AEP announced an agreement with the PJM Interconnection to pursue terms for certain subsidiares to participate in its RTO. Final agreements are expected to be negotiated. In July 2002 the FERC tentatively approved certain AEP subsidiaries' decision to join PJM subject to certain conditions being met. The performance of these conditions are only partially under AEP's control. In other RTO developments FERC recently accepted conditionally, filings related to a proposed consolidation of the Midwest Independent System Operator (MISO) and the SPP. In that order the FERC required the AEP subsidiaries in SPP to file reasons why those subsidiaries should not be required to join MISO. AEP filed with the FERC a response that additional analysis was required prior to AEP making an RTO decision. The SPP companies are also regulated by state public utility commissions, and the Louisiana and Arkansas commissions also filed responses to the FERC's RTO order indicating that additional analysis was required. Management is unable to predict the final 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 4 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 the Texas jurisdiction competition began in the ERCOT area but was delayed in the SPP area. In Ohio, Michigan and Virginia virtually all customers continue to receive electric generation, transmission and distribution services from our electric operating companies. On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users - Ohio and American Municipal Power - Ohio filed a complaint with the PUCO alleging that CSPCo and OPCo have violated the PUCO's orders regarding implementation of their transition plan and violated other applicable law by failing to participate in an RTO. The complainants seek, among other relief, an order from the PUCO suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred and imposing a $25,000 per company forfeiture for each day AEP fails to comply with its commitment to transfer control of transmission assets to an RTO. Due to FERC delays in the approval of our RTO filings, CSPCo and OPCo have been unable to implement their RTO plan. Management is unable to predict the timing of FERC's final approval of RTOs and the timing of an RTO being operational or the outcome of this proceeding before the PUCO. 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 for CPL and WTU in ERCOT 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. Two unaffiliated Texas utilities reached settlement agreements approved by the PUCT regarding recovery of stranded generation costs. CPL is not presently engaged in any settlement discussions with the PUCT. Under the Texas Legislation, a 2004 true-up proceeding will determine recovery of stranded costs including final fuel recovery balances, net regulatory assets, certain environmental costs, accumulated excess earnings and other issues. CPL's generation-related regulatory assets subject to recovery as stranded costs are approximately $1.1 billion of which $949 million has been securitized pending the 2004 true-up proceeding's determination of stranded costs recovery including the recovery of stranded generation-related regulatory assets. WTU and SWEPCo do not have any recoverable Texas generation-related regulatory assets. 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 which could have resulted in the imposition of 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. Most of those states have submitted conforming compliance plans and the appeal filed by AEP subsidiaries and other utilities in the D.C. Circuit Court to review this ruling has been dismissed. 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 in May 2002 advising that no changes in the growth factors used to set the NOx budgets were warranted. In June 2002 AEP subsidiaries joined other utilities and industrial organizations in seeking a review of Federal EPA's action in the D.C. Circuit Court. 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 June 30, 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 purportedly owned the cushion gas had entered into a financing arrangement with a group of banks. The banks purported to have certain rights to the cushion gas in certain events of default. We have been informed by the banks of Bammel Trust's default under the terms of their financing agreement. The banks filed a lawsuit against HPL seeking a declaratory judgment that they have a valid and enforceable security interest in this cushion gas which would permit them to cause the withdrawal of this gas from the storage facility. Management is unable to predict the outcome of this lawsuit or its impact on results of operation and cash flows. 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 the lawsuit related to the cushion gas financing agreement, our future results of operations, cash flows and possibly financial condition could be adversely impacted. Energy Market Investigations - Affecting AEP In February 2002 the FERC issued an order directing its Staff to conduct a fact-finding investigation into whether any entity, including Enron Corp., manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward. In April 2002 AEP furnished certain information to the FERC in response to their related data request. Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron 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 required senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative. Senior management complied with the order and denied our involvement with those trading practices. On May 21, 2002, the FERC issued a further data request with respect to this matter to us and over 100 other market participants requesting information for the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back" trading in the Western System Coordinating Council (WSCC), which involves the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price (collectively, "wash sales"). Similarly, on May 22, 2002, the FERC issued an additional data request with respect to this matter to us and other market participants requesting similar information for the same period with respect to the sale of natural gas products in the WSCC and Texas. After reviewing our records, we responded to the FERC that we did not participate in any "wash sale" transactions involving power or gas in the relevant market. We further informed the FERC that certain of our traders did engage in trades on the Intercontinental Exchange, an electronic electricity trading platform owned by a group of electricity trading companies, including us, on September 21, 2001, the day on which all brokerage commissions for trades on that exchange were donated to charities for the victims of the September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a "wash sale" but do have certain characteristics in common with such sales. In response to a request from the California attorney general for a copy of AEP's responses to the FERC inquires, we provided the pertinent information. The PUCT also issued similar data requests to AEP and other power marketers. AEP responded to such data request by the July 2, 2002 response date. The US Commodity Futures Trading Commission (CFTC) issued a subpoena on June 17, 2002 requesting information with respect to "wash sale" trading practices. We responded to CFTC. In addition, the US Department of Justice made a civil investigation demand to us and other electric generating companies concerning their investigation of the Intercontinental Exchange. We have recently completed a review of our trading activities in the United States for the last three years involving sequential trades with the same terms and counterparties. The revenue from such trading is not material to our financial statements. We believe that substantially all these transactions involve economic substance and risk transference and do not constitute "wash sales". Minority Interest in Finance Subsidiary - Affecting AEP In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated subsidiary, and sold a non-controlling preferred member interest in Caddis to an unconsolidated special purpose entity (Steelhead) for $750 million. Under the provisions of the Caddis formation agreements, the preferred member interest receives quarterly a preferred return equal to an adjusted floating reference rate. The $750 million received replaced interim funding used to acquire Houston Pipe Line Company in June 2001. The preferred interest is supported by natural gas pipeline assets and $321.4 million of preferred stock issued by an AEP subsidiary to the AEP affiliate which has the managing member interest in Caddis. Such preferred stock is convertible into AEP common stock upon the occurrence of certain events including AEP's stock price closing below $18.75 for ten consecutive trading days. AEP can elect not to have the transaction supported by such preferred stock if the preferred interest were reduced by $225 million. In addition, Caddis has the right to redeem the preferred member interest at any time. The initial period of the preferred interest is through August 2006. At the end of the initial period, Caddis will either reset the preferred rate, re-market the preferred member interests to new investors, redeem the preferred member interests, in whole or in part including accrued return, or liquidate in accordance with the provisions of applicable agreements. Steelhead has the right to terminate the transaction and liquidate Caddis upon the occurrence of certain events including a default in the payment of the preferred return. Steelhead's rights include: forcing a liquidation of Caddis and acting as the liquidator, and requiring the conversion of the $321.4 million of AEP subsidiary preferred stock into AEP common stock. If the preferred member interest exercised its rights to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the preferred member interest. Liquidation of the preferred interest or of Caddis could negatively impact AEP's liquidity. Foreign Distribution Projects - Affecting AEP We own a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 we converted a $66 million note receivable and accrued interest into a 20% equity interest in Caiua (Brazilian electric operating company), a subsidiary of Vale. Vale and Caiua have experienced losses from operations and our investment has been affected by the devaluation of the Brazilian Real. The cumulative equity share of operating and foreign currency translation losses through June 30, 2002 is approximately $47 million and $58 million, respectively, net of tax. The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 is approximately $46 million and $54 million, respectively, net of tax. Both investments are covered by a put option, which, if exercised, requires our partners in Vale to purchase our Vale and Caiua shares at a minimum price equal to the U.S. dollar equivalent of the original purchase price. As a result, management has concluded that the investment carrying amount should not be reduced below the put option value unless it is deemed to be an other than temporary impairment and our partners in Vale are deemed unable to fulfill their responsibilities under the put option. In January 2002, management evaluated through an independent third-party, the ability of its Vale partners to fulfill their responsibilities under the put option agreement and concluded that our partners should be able to fulfill their responsibilities. Management believes that the decline in the value of its investment in Vale in US dollars is not other than temporary. As a result and pursuant to the put option agreement, these losses have not been applied to reduce the carrying values of the Vale and Caiua investments. As a result we will not recognize any future earnings from Vale and Caiua until the operating losses are recovered. In addition, our partners have a principal payment due in November 2002 in the amount of $55 million. Our partners plan to refinance the debt before the payment comes due. Should the impairment of our investment become other than temporary due to our partners in Vale becoming unable to fulfill their responsibilities, it would have an adverse effect on future results of operations. Management will continue to monitor both the status of the losses and its partners ability to fulfill their obligations under the put option. FERC Proposed Security Standards In July 2002 the FERC published for comment its proposed security standards as part of the Standards for Market Design (SMD). These standards are intended to ensure all market participants have a basic security program that effectively protects the electric grid and related market activities and require compliance by January 1, 2004. The impact of these proposed standards is far-reaching and has significant penalties for non-compliance. These standards apply to marketers, transmission owners, and power producers. For the AEP System this includes: regulated and non-regulated power generation plants, transmission systems, distribution systems, regulated and non-regulated energy trading, and related areas of business. These standards represent a significant effort that will impact the entire AEP System. Unless the cost can be recovered from customers, results of operations and cash flows would be adversely affected. FERC Market Power Mitigation A FERC order on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power systems status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows. Other AEP and its subsidiary registrants continue to be involved in certain other matters discussed in the 2001 Annual Report. New Accounting Standard In June 2002, the FASB's Emerging Issues Task Force (EITF) in Issue No. 02-3 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities", reached a consensus that energy trading contracts (whether realized or unrealized and whether financially or physically settled) should be shown net in the income statement and that expanded disclosures of energy trading activities are required. This consensus is effective for periods ending after July 15, 2002 and reclassification of prior period amounts is required. Our adoption of EITF Issue No. 02-3 in the third quarter 2002 financial statements will lead to a material decrease in both revenues and purchased energy expense. There will be no impact on results of operations. Previous guidance in EITF Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities", permitted settled forward energy trading contract sales and purchases to be shown either gross or net in the income statement. AEP currently records, and reports upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expense. The table below shows the amounts of revenues and purchased energy expense that AEP would report if forward sales and purchase contracts that settle financially were accounted for on a net basis. The determination of net trading revenues under EITF Issue No. 02-3 may yield a different result than calculating net revenues on the basis of financially settled transactions only. We are currently assessing the application of EITF Issue No. 02-3 to report trading transactions on a net basis.

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 June 30, 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 for the: Six Months Ended Year Ended June 30, December 31, 2002 2001 ---- ---- High Average Low High Average Low (in millions) (in millions) AEP $22 $12 $6 $28 $14 $5 APCo 3 2 1 4 1 - CPL - - - 3 1 - CSPCo 2 1 - 2 1 - I&M 2 1 - 3 1 - KPCo 1 - - 1 - - OPCo 3 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 $639 million at June 30, 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 certain power trading transactions and certain 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 June 30, 2002. At June 30, 2002 approximately 8% 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: June 30, 2002 (in millions) AAA/Exchanges $ - $51 $ 51 AA 115 - 115 A 327 - 327 BBB 784 7 791 Below Investment Grade 103 2 105 ------ --- ------ Total $1,329 $60 $1,389 ====== === ====== 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 June 30, 2002 and December 31, 2001 were $241 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 second quarter of 2002 resulted in an unrealized increase in revenues of $40 million and unrealized increase in revenues of $87 million year-to-date. 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). Six Months Ended June 30, 2002 (in millions) Revenues (including mark-to-market adjustment) $27,942 Fuel and Purchased Energy Expense 23,813 ------- Net Revenues $ 4,129 ======= Mark-to-Market Revenues on Open Trading Positions $87* === Percentage of Net Revenues Represented by Mark-to-Market on Open Trading Positions 2% = *Excludes reversal of $294 million of mark to market for contracts that settled in 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 June 30, 2002 of $187 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 June 30, December 31, --------------- ------------ 2002 2001 ---- ---- (in millions) (in millions) Energy Trading and Derivative Contracts: Current Asset $ 9,466 $ 8,572 Long-term Asset 3,672 2,370 Current Liability (9,538) (8,311) Long-term Liability (3,444) (2,183) ------- ------- Net Fair Value of Energy Trading Contracts and Derivative Contracts 156 448 Less non-trading related derivatives (31) - ------- ------- Net Fair Value of Energy Trading Contracts and Related Derivatives $ 187 $ 448 ======= ======= The above net fair value of energy trading contracts and related derivatives includes $47 million, at June 30, 2002, in unrealized mark-to-market gains that are recognized in the income statement at June 30, 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 $367 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) The Company changed the discount rate applied to its trading portfolio from BBB+ Utility to LIBOR in the second quarter which increased fair value by $10 million. In addition, the Company changed its methodology in valuing a spread option model so as to more accurately reflect the exercising of power transactions at optimal prices which reduced fair value by $9 million. (d) "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. (e) The net change in the fair value of energy trading contracts for 2002 that resulted in a decrease of $261 million ($187 million less $448 million) represents the balance sheet change. The net mark-to-market gain on energy trading contracts of $47 million and net mark-to-market gain on gas inventory positions of $40 million represent the impact on earnings related to open trading positions as of June 30, 2002. The difference is related primarily to settlement of prior period open energy trading contracts ($294 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.

(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. Item 4. Submission of Matters to a Vote of Security Holders. --------------------------------------------------- AEP The annual meeting of shareholders was held in Columbus, Ohio, on April 23, 2002. The holders of shares entitled to vote at the meeting or their proxies cast votes at the meeting with respect to the following three matters, as indicated below: 1. Election of thirteen directors to hold office until the next annual meeting and until their successors are duly elected. Each nominee for director received the votes of shareholders as follows:

2. Approve the appointment by the Board of Directors of Deloitte & Touche LLP as independent auditors of AEP for the year 2002. The proposal was approved by a vote of the shareholders as follows: Votes FOR 244,793,710 Votes AGAINST 9,303,198 Votes ABSTAINED 6,062,395 Broker NON-VOTES* 0 3. Shareholder proposal submitted by Ronald Marsico. The proposal was disapproved by a vote of the shareholders as follows: Votes FOR 14,495,798 Votes AGAINST 192,849,019 Votes ABSTAINED 6,062,395 Broker NON-VOTES* 42,882,546 *A non-vote occurs when a nominee holding shares for a beneficial owner votes on one proposal, but does not vote on another proposal because the nominee does not have discretionary voting power and has not received instructions from the beneficial owner. APCo The annual meeting of stockholders was held on April 23, 2002 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR each of the following seven persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley, III Henry W. Fayne Susan Tomasky Armando A. Pena Joseph H. Vipperman Robert P. Powers CPL Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 11, 2002, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley III Henry W. Fayne Susan Tomasky Armando A. Pena Joseph H. Vipperman Robert P. Powers I&M Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 23, 2002, the following thirteen persons were elected directors to hold office for one year or until their successors are elected and qualify: Karl G. Boyd Robert P. Powers E. Linn Draper, Jr. John R. Sampson John E. Ehler Thomas V. Shockley, III Henry W. Fayne David B. Synowiec David L. Lahrman Susan Tomasky Marc E. Lewis Joseph H. Vipperman Susanne M. Moorman OPCo The annual meeting of shareholders was held on May 7, 2002 at 1 Riverside Plaza, Columbus, Ohio. At the meeting there were 27,952,473 votes cast FOR: 1. Each of the following seven persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley, III Henry W. Fayne Susan Tomasky Armando A. Pena Joseph H. Vipperman Robert P. Powers 2. Approval of amendment to Article Second of the Amended Articles of Incorporation of OPCo providing that the principal office of OPCo is to be located at 1 Riverside Plaza, Columbus, Franklin County, Ohio, and there were no votes against, abstentions or broker non-votes. SWEPCo Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 10, 2002, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley III Henry W. Fayne Susan Tomasky Armando A. Pena Joseph H. Vipperman Robert P. Powers Item 5. Other Information. AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Reference is made to page 29 of the Annual Report on Form 10-K for the year ended December 31, 2001 (2001 10-K) for a discussion of regional haze. On May 24, 2002, the D.C. Circuit Court issued an opinion and order vacating in part and upholding in part the regional haze rule. The court held that Federal EPA could not establish Best Available Retrofit Technology standards for entire groups of emission sources without regard to improvement in visibility attributable to individual source controls. Federal EPA has filed a petition seeking rehearing by the entire D.C. Circuit Court. AEP Reference is made to pages 31 through 33 of the 2001 10-K for a discussion of the Clean Water Act. On May 8, 2002, the U.S. District Court for the Southern District of West Virginia issued an injunction prohibiting the U.S. Army Corps of Engineers from issuing permits under Section 404 of the Clean Water Act for the primary purpose of disposal of waste mining overburden and spoil. On June 17, 2002, the court denied a request for stay filed by the U.S. Department of Justice and intervenor, Kentucky Coal Association. The court clarified that the decision only applies to the Corps' Huntington District. The court also advised that the ruling does not apply to dredged material placed back in the stream but does apply to activities other than coal mining that require Section 404 permits. The intervenor-defendants have filed an appeal to the U.S. Fourth Circuit Court of Appeals and the court has set a briefing schedule. The effect on permitting activities of certain AEP subsidiaries under Section 404 cannot be predicted but could be significant. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: OPCo Exhibit 3(d) - Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated June 3, 2002. Exhibit 3(e) - Composite copy of the Amended Articles of Incorporation of OPCo (amended as of June 3, 2002). AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges. AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Exhibit 99.1 - Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. Exhibit 99.2 - Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. (b) Reports on Form 8-K: Company Reporting Date of Report Item Reported AEP June 5, 2002 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits APCo June 13, 2002 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits AEP June 18, 2002 Item 5. Other Events and Regulation FD Disclosure SWEPCo June 20, 2002 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits KPCo June 25, 2002 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits AEGCo, CPL, CSPCo, I&M, OPCo, PSO, and WTU No reports on Form 8-K were filed during the quarter ended June 30, 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: August 13, 2002

KENTUCKY POWER CO 10-Q