10-Q 1 xq302mod.txt COMBINED 10Q 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 SEPTEMBER 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 Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No Indicate by check mark whether AEP Generating Company, 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 are accelerated filers (as defined in Rule 12b-2 of the Exchange Act). Yes No X The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at October 31, 2002 was 338,835,220. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended September 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 regulation, oversight and/or investigation of the energy sector or its participants. o The ability of AEP to successfully control its costs. o The success of acquiring new business ventures and disposing of existing investments that no longer match our corporate profile. 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 banking, capital and wholesale power markets. o Other risks and unforeseen events. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2002 vs. THIRD QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 AEP's 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, coal and other commodities o Coal mining, bulk commodity barging operations and other energy supply related businesses o Energy Delivery o Domestic electricity transmission o Domestic electricity distribution o Other Investments o Investments in foreign power and distribution projects o Telecommunication services Results of Operations Net Income for the third quarter was $425 million, an increase of $4 million compared to third quarter 2001. Earnings per share for the quarter were $1.25 compared to $1.31 in 2001, reflecting the effects of the sale of additional shares in 2002. Regulated integrated utilities and wholesale sales from our power plants showed strong increases in earnings when compared with the same period last year. However, lower earnings from energy trading and a loss from power generation in the United Kingdom offset the positives. AEP had Net Income of $318 million year-to-date compared to $919 million in 2001. Year-to-date earnings per share as of September 30, 2002 were $.97 compared to $2.85 in 2001, reflecting the combined effect of equity sales, discontinued operations and the cumulative effect of a change in accounting principle. The year-to-date loss for transitional goodwill impairment related to SEEBOARD and CitiPower resulted from the adoption of SFAS 142 (see Note 3) and has been reported as a cumulative effect of a change in accounting principle retroactive to January 1, 2002. Changes in Revenues

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to domestic energy delivery. The increase in Electricity Marketing and Trading revenues was primarily due to strong wholesale and retail sales as a result of favorable weather conditions in the third quarter. The increase in revenues year-to-date from Gas Marketing and Trading can be attributed to an increase in volumes, as we expanded our operations around Houston Pipe Line (HPL) which we acquired in June 2001. The decrease in Gas Marketing and Trading revenues in the third quarter resulted from a decrease in net gains from financial trading which offset the year-to-date increase attributed to the HPL acquisition. Other Investments decreased in both periods due to the elimination of factoring of accounts receivable of an unaffiliated utility. Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, we reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10 (see Note 2 and "New Accounting Pronouncements" in "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters"). Changes in Operating Expenses

In the quarter and year-to-date, the increase in Fuel and Purchased Energy expense was primarily attributable to an increase in power generation. Net generation increased 3% due to increased demand for electricity and a reduction in planned power plant maintenance outages for various plants from 2001. The year-to-date increase in Gas Marketing expense was primarily due to an expansion of gas activity around our HPL pipeline assets. For the quarter, the decrease in Maintenance and Other Operation expense was due to a $35 million reduction in trading incentives, a $40 million reduction in administration costs due to severance expense recorded in the prior year, a $31 million reduction in other transmission and distribution expenses as well as a $12 million decline in nuclear outage expenses due to the reduction of planned outages. These favorable results were partially offset by an impairment charge due to a writedown of utility assets resulting from the inactivation of inefficient gas fired generating facilities at WTU of approximately $34 million (see Note 10). Year-to-date Maintenance and Other Operation expense increased largely as aresult of the expenses of recently acquired businesses including Quaker Coal; MEMCO, a barging line; planned material and labor costs incurred in connection with the construction of gas-fired plants for third parties; HPL; and two power plants in the UK. These cost increases were partially offset by a reduction in trading incentive compensation. Depreciation and Amortization expense for both periods increased due to plants acquired, and a plant placed into service in late 2001 as well the amortization of Texas generation related Regulatory Assets that were securitized in early 2002. For the year-to-date, period Taxes Other Than Income Taxes increased due to recently acquired businesses including Quaker Coal, MEMCo and HPL and two plants in the UK. Other Changes Other Income decreased in the year-to-date period due mainly to a gain on the sale of the Frontera generating plant in 2001 partially offset by an increase in both periods for other business development income due to the increased volume of those projects as well as minority interest in 2002. Other Expense increased in both periods due to an increase in expenses on other business development projects expenses in 2002. The increase in Income Taxes for the third quarter and the decrease in Income Taxes for the year-to-date period were predominately due to a corresponding increase/decrease in pre-tax income. The decrease in Interest was primarily due to the refinancing of long-term debt at favorable interest rates, a reduction in short-term interest rates and lower outstanding balances of short-term debt. In connection with the sale of CitiPower and SEEBOARD (see Note 4), we had recorded a net loss totaling $432 million as of September 30, 2002. Within the total net loss of $432 million is a $350 million transitional goodwill impairment loss from the adoption of SFAS 142 (see Note 3) reported as a cumulative effect of a change in accounting principle retroactive to January 1, 2002.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $328 million and $469 million and for income taxes was $242 million and $208 million in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $1 million in 2002 and $39 million in 2001. 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 THIRD QUARTER 2002 vs. THIRD QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 AEGCo is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. Operating Revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies pursuant to FERC approved long-term unit power agreements. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Results of Operations Net Income decreased $104,000 or 5% for the third quarter and $536,000 or 9% 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. Changes in Revenues The decreases in Operating Revenues of $1,429,000 or 2% for the third quarter and $10,922,000 or 6% for the year-to-date period resulted from decreases in recoverable expenses, primarily Fuel. Changes in Operating Expenses Operating expenses declined 2% in the third quarter and 6% for the year-to-date period as follows:

N.M. = Not Meaningful Fuel expense, which includes coal transportation cost and coal trading gains, decreased in the year-to-date period due to lower average fuel costs and a decrease in generation. Lower fuel cost contributed $6,600,000 of the decrease while decreased generation contributed $3,700,000. The decrease in generation reflects longer outages for planned maintenance and system enhancements in 2002. Other Operation expense decreased in the third quarter due to a decrease in the FERC assessment and lower costs allocated from affiliates. The increase in Other Operation expense for the year-to-date period is primarily due to higher costs for employee benefits and property insurance. Maintenance expense for the year-to-date period decreased even though the duration of outages lengthened. In 2002, due to the capital nature of the projects, more labor and related costs are being capitalized as part of system enhancements instead of expensed as maintenance projects. Taxes Other Than Income Taxes increased due to increased employer expense for employment taxes in the third quarter due to a change in estimate from the second quarter's level of expense. The decrease in Income Taxes attributable to operations for the year-to-date period is primarily due to a change in estimate 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 during the second and third quarters of 2001 resulting in higher comparable Income Taxes for the third quarter of 2002. Other Changes Interest Charges declined 14% in the third quarter and 12% 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. AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED)

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 $1,983,000 and $1,489,000 and for income taxes was $2,442,000 and $1,352,000 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 THIRD QUARTER 2002 vs. THIRD 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 Power Pool's generating capacity is allocated among its 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. Results of Operations Net Income increased $24 million or 78% for the quarter and $27 million or 21% year-to-date period due to higher retail sales and cost reductions. Changes in Revenues

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The increase in revenues for the quarter was due primarily to warmer summer weather as the third quarter of 2002 saw a 31% increase in cooling degree days over third quarter of 2001. Year-to-date revenues were comparable to those of last year as current quarter increases offset lower revenues for the first six months which were lower primarily as a result of lower demand caused by mild winter weather. Sales to AEP Affiliates increased quarter to quarter and year to year due to available generation to be delivered to the AEP Power Pool. Changes in Operating Expenses

Fuel expense increased for the quarter and year-to-date as a result of an increase in APCo generation. Mountaineer, Amos, and Glen Lyn plants had undergone boiler plant maintenance in 2001 which resulted in increased availability and a decrease in maintenance in 2002. Electricity Marketing Purchases increased for the quarter and year-to-date as a result of increased purchases from third parties for resale to wholesale customers and to meet internal demand. The overall decrease for both periods in Purchases from AEP Affiliates is a result of increased internal generation due to plant availability as disclosed above in the discussion of Fuel expense. The decrease in Other Operation expense for both periods is due primarily to a decrease in transmission equalization charges caused by a reduction in APCo's MLR ratio, a decrease in power trading incentive compensation expense, and energy delivery severance accruals recorded in 2001 for which there was no comparable activity in 2002. These favorable variances were partially offset by an increase in insurance premiums and other employee benefit costs. The decrease in Maintenance expense year-to-date is primarily due to boiler plant maintenance at Amos, Mountaineer, and Glen Lyn plants in the year 2001 for which there was less activity in 2002. In addition, there were fewer maintenance needs for electric plant, station equipment, and company owned structures and improvements. Depreciation and Amortization expense increased during both periods due to increased amortization for the net generation-related regulatory assets related to the Company's Virginia and West Virginia jurisdictions that are being recovered through regulated rates. Additionally, investment in production plant in service, primarily emission control related, also contributed to the increase in depreciation and amortization expense. The increase in Income Taxes for the quarter and year-to-date was due to an increase in pre-tax income. Other Changes Nonoperating Income for the quarter increased due to a net gain in power trading activity. The Nonoperating Income decrease year-to-date was due to a decrease in net power trading gains driven by a decline in market prices. Year-to-date Interest Charges decreased primarily as a result of lower AEP money pool balances and interest rates and the retirement of first mortgage bonds in 2001. Nonoperating Income Tax Expense increased in both periods due to the increase in nonoperating pre-tax income and year-to-date due to a change in the allocation of tax savings from AEP.

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 $68,305,000 and $70,286,000 and for income taxes was $38,425,000 and $21,521,000 in 2002 and 2001, respectively. There were no noncash payments for the capital leases in 2002. Noncash acquisitions under capital leases were $2,576,000 in 2001. 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 THIRD QUARTER 2002 vs. THIRD QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 CPL is a public utility engaged in the generation, purchase, 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 its affiliated REP in Texas. 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. 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 REP, 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 affiliated REP. Pending regulatory approval, CPL will separate its generation from its transmission and distribution operations. The affiliated REP is a separate legal entity that is an AEP subsidiary that is not owned by or consolidated with CPL. Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, CPL sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers in the CPL service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, CPL no longer supplies electricity directly to retail customers. The implementation of affiliated REPs as suppliers to retail customers has caused a significant shift in CPL's sales as described below under "Results of Operations." Results of Operations Third quarter Net Income increased $10 million or 12% primarily due to decreased interest charges and the absence in 2002 of special tax assessments recorded in the third quarter of 2001. Year-to-date Net Income decreased $20 million or 12% primarily due to a slow economic recovery and a significant decline in wholesale margins.

*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 electricity sales in the ERCOT region as of January 1, 2002 and a decrease in energy trading margins offset in part by the ICR adjustments (see Note 6). Also contributing to the decrease was a decline in wholesale power prices due to soft market demand. Sales to AEP Affiliates increased primarily due to increased revenues to the newly-created affiliated REP. Although CPL sold electricity to the affiliated REP instead of directly to retail customers, total revenues decreased due to lower wholesale prices. For the quarter, the effect of the ICR adjustments and revenue associated with securitized assets offset negative wholesale effects (see Note 6). Changes in Operating Expenses

Fuel expense decreased both for the quarter and year-to-date due to a decrease in the average unit cost of fuel and decreased generation. The increase in Electricity Marketing expense and the decrease in Purchases from AEP Affiliates is due to higher MWH purchases from the market at prices lower than CPL's generation cost. ICR adjustments in the third quarter also had the effect of increasing Electricity Marketing expense and decreasing Affiliates Purchase Power, resulting in a negative Affiliated Purchase Power expense for the quarter (see Note 6). Other Operation expense decreased both for the quarter and year-to-date due primarily to the elimination of factoring of accounts receivable and lower ERCOT transmission related expenses. Maintenance expense decreased for the year due to a refueling outage for STP during 2001. The increase in Depreciation and Amortization is attributable to the amortization of regulatory assets that were securitized in the first quarter of 2002, offset by the reduction of excess earnings expense in 2002 under Texas Restructuring Legislation. The increase year-to-date in Taxes Other Than Income Taxes resulted primarily from higher local franchise taxes, offset by one-time third quarter 2001 assessments and decreased gross receipts tax, due to deregulation. For the quarter, the decrease was primarily attributable to the one-time third quarter 2001 assessments described above. The decrease in Income Taxes for the year-to-date period is due to a decrease in pre-tax income. Other Changes Nonoperating Income and Nonoperating Expenses increased significantly during the quarter and the year-to-date period as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. Interest Charges decreased primarily due to the issuance of lower interest rates securitization bonds used to refinance regulatory assets in accordance with the Texas Restructuring Legislation. Nonoperating Income Tax Expense decreased both for the quarter and year-to-date due to the recording of the investment tax credit amortization related to power plants as Nonoperating Income Tax Credits since the time of deregulation of CPL's power plants. As a result of CPL's recent ability to purchase electricity at a significantly lower price than its current cost to generate electricity, CPL proposed in September 2002 to "inactivate" various, high-cost gas fired generating facilities. CPL recorded an impairment charge in the third quarter 2002 of approximately $100 million related to these plants which was deferred and recorded in Regulatory Assets, to be included as a stranded cost in the Texas 2004 true-up proceeding (see Note 10).

The common stock of CPL 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 $63,005,000 and $80,612,000 and for income taxes was $44,322,000 and $11,939,000 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 THIRD QUARTER 2002 vs. THIRD QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 CSPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 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 its 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. Results of Operations Net Income increased $11 million or 17% in the third quarter of 2002 due to higher retail sales and reduced interest charges. Net Income increased $38 million or 30% in the year-to-date period due to reduced interest charges and a $26 million extraordinary loss recorded in the prior period second quarter to recognize a stranded asset resulting from deregulation. Changes in Revenues

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The quarter and year-to-date increase in revenues is mainly due to higher residential and commercial sales that resulted from above normal temperatures during the third quarter compared with milder weather in 2001.

Electricity Marketing Purchases increased in the quarter and year to date periods due to increased purchases from third parties for resale to wholesale customers and to meet internal demand. Other Operation expense increased in both periods primarily due to increases in benefits expense as a result of higher benefit costs and application of a lower discount rate. Maintenance expenses decreased in the year-to-date period of 2002 due to boiler overhaul work that was performed during 2001. Expenses for maintaining distribution overhead lines were also lower in 2002. The increase in Income Taxes for both periods is predominately due to an increase in pre-tax income. Other Changes The decrease in Nonoperating Income in both periods 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. Our 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. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand. The decrease in Nonoperating Expense in the quarter and year-to-date was due to lower energy trading overheads resulting from a decrease in trading incentives. Non-Operating Income Tax expense increased in both periods due to the flow-through of deferred taxes and a change in the allocation of tax savings from AEP. The decrease in Interest in both periods 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 CSPCo 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 $37,204,000 and $49,126,000 and for income taxes was $32,254,000 and $17,579,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $1,019,000 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 THIRD QUARTER 2002 vs. THIRD 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 approximately 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 utility systems and power marketers including power trading transactions. I&M also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among its 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. Under the terms of unit power agreements, I&M purchases 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. Results of Operations The $10 million or 41% increase in Net Income for the third quarter reflects increased sales of electricity to retail customers and a decrease in Other Operation expense. Net Income decreased $31 million or 36% in the year-to-date period due primarily to a reduction in generation in 2002 as a result of a refueling outage at each unit of I&M's Cook Plant and maintenance outages at Rockport Plant. Operating revenues increased 6% in the third quarter reflecting increased sales to retail customers and AEP affiliates. The 2% decrease in operating revenues for the year-to-date period reflects the decrease in generation in 2002 due to power plant outages.

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The increase in Electricity Marketing and Trading revenues in the third quarter and year-to-date was due to increased sales to I&M's retail customers due to warmer summer weather partially offset by lower wholesale energy prices. The increase in Sales to AEP Affiliates in the third quarter reflects increased generation from Cook Plant in 2002. In September 2001 problems with the water intake system forced Cook Plant into an unplanned outage. Revenues from Sales to AEP Affiliates in the year-to-date period decreased significantly reflecting less power being available for sale as each of the Cook Nuclear Plant units was shutdown for refueling in the first six months of 2002 and both units of Rockport Plant underwent scheduled planned boiler maintenance in the first quarter of 2002. With the outages in 2002, I&M's available generation decreased resulting in less power being delivered to the AEP Power Pool.

The increase in Fuel expense for the third quarter reflects an increase in nuclear and fossil fuel costs as generation rose significantly in 2002. Fuel expense for the year-to-date period decreased primarily due to the decrease in generation reflecting the plant outages as both units of the nuclear plant were refueled in 2002 and Rockport Plant's outage time increased. In addition, gains on coal trading lowered the average fuel cost. The increase in Electricity Marketing Purchases in both periods is due to increased purchases from third parties for sales for resale and to meet internal demand. Purchases from AEP Affiliates decreased in both periods due to lower purchase volumes and lower cost of power acquired from AEGCo and the AEP Power Pool. For the third quarter, Other Operation expense decreased due to lower trading incentives, the effect of recording severances in 2001 for energy delivery employees, and lower nuclear operations costs reflecting the effects of the 2001 outage at Cook Plant. Other Operation and Maintenance expenses increased for the year-to-date period due to costs related to the nuclear plant refueling outages. The increase in Maintenance expense for the third quarter reflects amortization of deferred refueling expenses. The decrease in Income Tax expense attributable to operations for the year-to-date period is due primarily to a decline in pre-tax operating income. Other Changes Nonoperating Income decreased in the quarter and year-to-date periods due to a reduction in power trading margins outside of AEP's traditional marketing area resulting from the overall decline of wholesale energy markets. Nonoperating Expenses decreased due to reductions in variable compensation expense associated with wholesale trading. Nonoperating Income Taxes decreased in the year-to-date period due to a decrease in pre-tax 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 $63,987,000 and $67,657,000 and for income taxes was $21,225,000 and $13,079,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $1,023,000 in 2001. See Notes to Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2002 vs. THIRD 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 173,000 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 its 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. Results of Operations Net Income increased approximately $1 million or 13% in the third quarter and $6 million or 42% in the year-to-date period primarily due to reduced capacity charges and increased transmission equalization credits resulting from the decrease in MLR. Increased retail sales due to warmer summer weather also contributed to the increase in Net Income. Changes in Revenues

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The increase in revenues in the third quarter is due primarily to increased sales to retail customers reflecting warmer summer weather and increased fuel recovery revenues. This was partly offset by lower Sales to AEP Affiliates in both periods because of planned outages in 2002. KPCo's generation decreased resulting in less power being delivered to the AEP Power Pool.

N.M. = Not Meaningful Fuel expense increased in both periods as a result of increases in the cost of coal and decreases in credits to Fuel expense. Under the Kentucky commission's fuel clause mechanism, a portion of the profits on wholesale power trading transactions are shared with the retail customers. This sharing is recognized through credits to Fuel expense that match the increased retail revenues. As margins on wholesale electricity marketing and trading transactions declined, the amount of credits shared through the fuel clause adjustment mechanism decreased. Third quarter Electricity Marketing Purchases expense increased compared to prior year due to increased purchases from third parties for resale to wholesale customers and to meet internal demand. Year-to-date Purchases from AEP Affiliates declined due to a decrease in capacity charges from the AEP Power Pool as KPCo's MLR declined. Also contributing to the year-to-date decline were fewer purchases and lower prices on power purchased from AEGCo. Other Operation expense decreased for both periods due to reduced consumption of emission allowances, reduced accruals for trading incentive compensation and increased AEP transmission equalization credits. Under the AEP Transmission Equalization Agreement, KPCo and certain eastern region affiliates share the costs associated with the ownership of their transmission system based upon each company's 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 in both periods primarily as a result of planned power plant outages. Taxes Other Than Income Taxes increased year-to-date primarily due to increases in real and personal property taxes. Income Taxes year-to-date and quarter-to-date have increased primarily as a result of increases in pre-tax income. Other Changes Year-to-date Nonoperating Income decreased as a result of decreased margins on power trading activity outside of the AEP System's traditional marketing area resulting from soft market demand. Nonoperating Expenses decreased quarter and year-to-date as a result of decreases in trading incentives.

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 $19,560,000 and $18,899,000 and for income taxes was $7,025,000 and $6,011,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $22,021 and $817,000 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 THIRD QUARTER 2002 vs. THIRD 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 utility systems and power marketers including power trading transactions. OPCo also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among its 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. Results of Operations Net Income increased $29 million or 56% in the third quarter of 2002 primarily due to increased sales to residential and commercial customers. Year-to-date Net Income increased $84 million or 73% due to the effect of an extraordinary loss recorded in the second quarter of 2001 to recognize a stranded asset resulting from deregulation, and decreases in fuel and maintenance expenses.

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The increase in revenues is mainly attributable to increased residential and commercial sales during the third quarter due to warmer weather. The decrease in revenues from Sales to AEP Affiliates was mainly attributable to a decrease in the price of power delivered to the AEP Power Pool.

The Fuel expense decrease for the quarter and year-to-date reflect a year-to-date reduction of 22% in the average cost of fuel for generation offset in part by a 2% year-to-date increase in MWH generated. The decrease in fuel costs are the result of purchasing coal at lower prices on the open market in 2002. Electricity Marketing Purchases increased for the quarter and year-to-date due to increased purchases from third parties for resale to wholesale customers and to meet internal demand. Other Operation expense decreased for the quarter due to lower COLI expense caused by mid-year cash surrender value adjustments. The year-to-date increase in Other Operation expense was due to higher current year benefit expense caused by increased benefit costs and a lower discount rate utilized to determine OPEB and pension expense offsetting the quarter's COLI expense reduction. Maintenance expenses decreased in the third 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 increase in depreciation expense from the placement of additional plant into service at the Gavin Plant in 2001. The decrease in Taxes Other Than Income Taxes during the third quarter is due to a reduction in tax rates on generation property. The increase in Income Taxes for both periods is predominately due to an increase in pre-tax income due to the replacement of higher priced affiliated coal purchases with nonaffiliated coal purchases. Other Changes Nonoperating Income decreased in the third quarter due to the decreases in power trading margins from AEP Power Pool trading transactions outside of the AEP's Systems 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. On a year-to-date basis Nonoperating Income decreased due to lower power trading margins and the loss of the 2001 interest income from the coal subsidiary deposits. The coal subsidiaries were sold in July 2001. Nonoperating Expenses decreased during both periods due to reductions in variable incentive compensation expenses associated with wholesale trading. The increase in Nonoperating Income Tax Expense results from the prior period sale of the Ohio Coal companies in the third quarter 2001. The decrease in Interest Charges was primarily due to a decrease in the outstanding balances of long-term debt in both periods, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.

The common stock of OPCo 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 $56,864,000 and $59,492,000 and for income taxes was $29,981,000 and $55,806,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $98,000 and $595,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2002 vs. THIRD 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. Results of Operations Net Income decreased by $10 million or 20% for the quarter and $10 million or 17% for the year-to-date period. The decreases primarily resulted from reduced wholesale margins due to a decline in demand for electricity resulting from mild weather and a slow economic recovery.

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Operating revenues decreased during the quarter and for the year-to-date periods as a result of a decline in fuel recovery revenue. Additionally, the quarterly results were impacted by decreases due to the ICR adjustments (see Note 6), decreases in usage by existing customers and decreases in growth in the number of customers resulting from the slowing economy. The Sales to AEP Affiliates revenue is negative for the quarter due to the impact of the ICR adjustments (see Note 6).

N.M. = Not Meaningful The decrease in Fuel expense for both the quarter and year-to-date was primarily due to the amortization of previously overrecovered fuel costs, lower market prices for natural gas and fuel oil and deferral of newly underrecovered fuel costs due to the ICR adjustments through the fuel clause recovery mechanism (see Note 6). The decrease in the quarter and year-to-date Electricity Marketing expense resulted mainly from a decrease in energy prices and the ICR adjustments (see Note 6). The increase in the quarter and year-to-date in Purchases from AEP Affiliates results mainly from the availability of internal generation and the ICR adjustments (see Note 6). 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 third quarter due primarily to lower production 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 primarily due to the additional depreciable capitalized costs involved in repowering Northeast Station Units 1 & 2 completed in 2001. Taxes Other Than Income Taxes increased in the quarter and year-to-date primarily due to the increase in ad valorem taxes. Income Taxes decreased in the quarter and year-to-date periods primarily due to a decrease in pre-tax income.

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 $24,853,000 and $24,351,000 and for income taxes was $2,962,000 and $7,386,000 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 THIRD QUARTER 2002 vs. THIRD 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 to approximately 435,000 retail customers 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. Results of Operations Net Income decreased slightly in the third quarter and decreased $12 million or 14%, for the year-to-date period. The decrease for the year-to-date period primarily resulted from reduced wholesale margins due to a decline in demand for electricity resulting from mild weather and a slow economic recovery.

*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The increase in revenues for the quarter mainly result from a $31 million increase due to ICR adjustments (see Note 6). Operating revenues decreased 3% for the year-to-date period due to decreased fuel revenues offset in part by the addition of the Dolet Hills mining operation, increased wholesale revenues and the positive impact of the ICR adjustments (see Note 6). Changes in Operating Expenses Operating expenses increased 11% in the third quarter due to a significant increase in Electricity Marketing Purchases and Purchases from AEP Affiliates offset by a decrease in Fuel expense. Operating expenses decreased 1% for the year-to-date period due to a decrease in Fuel expense offset by an increase in purchased power.

Fuel expense decreased for the quarter and year-to-date due to a reduction in MWH generated, a decrease in deferred fuel expense in the quarter and a decrease in the cost of fuel in the year-to-date period. Purchased power for the quarter and year-to-date increased due to reduced generation and the impact of ICR adjustments (see Note 6). The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June 2001 caused Other Operation expense to increase in year-to-date 2002. Year-to-date and the quarter were impacted by both the addition of Dolet Hills and the ICR adjustments (see Note 6). The increase in Depreciation and Amortization expense for the quarter is due to a favorable excess earnings adjustment in 2001 as required by Texas Restructuring Legislation. The increase year-to-date is primarily due to the addition of Dolet Hills in June 2001. The decrease in Income Taxes for the quarter and year-to-date periods was due to a decrease in pre-tax 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 $34,860,000 and $38,614,000 and for income taxes was $24,102,000 and $5,524,000 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 THIRD QUARTER 2002 vs. THIRD 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 also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated REP in Texas. 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. On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. WTU 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 was required to submit a plan to structurally unbundle its business into a REP, 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 affiliated REP. Pending regulatory approval, WTU will separate its generation from its transmission and distribution operations. The affiliated REP is a separate legal entity that is an AEP subsidiary, that is not owned by or consolidated with WTU. Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, WTU sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers in the WTU service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, WTU no longer supplies electricity directly to retail customers. The implementation of affiliated REPs as suppliers to retail customers has caused a significant shift in WTU's sales as described below under "Results of Operations." Results of Operations Net Income decreased $18 million or 130% for the quarter and $21 million or 98% year-to-date. The decreases are primarily due to a $22 million impairment charge, net of tax, related to the inactivation of inefficient gas fired plants (see Note 10).

*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 electricity sales in the ERCOT region as of January 1, 2002, partially offset by the ICR adjustments (see Note 6). Also contributing to the decrease was a decline in wholesale power prices. In 2002 the wholesale energy sector has been under pressure from lower commodity prices and fewer market participants in contrast to last year when performance was stronger 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 decreased due to lower wholesale prices.

Fuel expense decreased both for the quarter and year-to-date due to a decrease in the average unit cost of fuel and decreased generation. The net decline in Purchased Power expense for both the quarter and year-to-date was mainly due to reduced prices caused by decreased electricity demand, partially offset by ICR adjustments (see Note 6). As a result of WTU's recent ability to purchase electricity at a significantly lower price than its current cost to generate electricity, WTU proposed in September 2002 to "inactivate" various, high-cost gas fired generating facilities. WTU recorded an impairment charge in the third quarter 2002 of approximately $34 million related to these plants which was recorded in Other Operation expense (see Note 10). Depreciation and Amortization expense decreased due to the elimination in 2002 of excess earnings expense under Texas Restructuring Legislation. The quarter and year-to-date decrease in Taxes Other Than Income Taxes is primarily a result of one-time third quarter 2001 assessments and a decrease in the gross receipts tax due to deregulation. The quarter and year-to-date decrease in Income Taxes is primarily a result of a decrease in pre-tax income resulting from the write-down of various generating facilities. Other Changes Nonoperating Income and Nonoperating Expenses increased significantly during the quarter and the year-to-date period as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. Nonoperating Income Taxes decreased year-to-date due to a decrease in pre-tax income.

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 $13,061,000 and $11,761,000 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. NEW ACCOUNTING PRONOUNCEMENTS During 2002, the EITF discussed Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17" (EITF 02-3) and reached consensus on certain issues. EITF 98-10, "Accounting for Contracts Involving Energy Trading and Risk Management Activities," requires that energy trading contracts be accounted for at fair value. EITF 02-3 rescinds Issue No. 98-10 effective for any new contracts entered into after October 25, 2002. For energy trading contracts entered into through October 25, 2002, such contracts will continue to be accounted for at fair value through December 31, 2002. Effective January 1, 2003, such contracts are required to be accounted for at historical cost and we will report this as a cumulative effect of an accounting change. Our energy contracts that qualify as derivatives will continue to be accounted for at fair value under SFAS 133. EITF 02-3 requires that energy trading contracts and derivatives, whether settled financially or physically, be reported in the income statement on a net basis effective January 1, 2003. Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, we reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10. The reclassification of such trading activity to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on our financial condition, results of operations or cash flows. The following table shows the amounts of revenue and Fuel and Purchased Energy expense that AEP would report if these amounts were presented on a "gross" basis: Three Months Ended Nine Months Ended September 30, September 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in millions) (in millions) Gross Revenues $21,999 $17,998 $49,844 $45,765 Gross Fuel and Purchased Energy Expense $19,882 $15,763 $43,709 $39,653 Net Revenues $3,911 $3,757 $10,818 $9,944 Net Fuel and Purchased Energy Expense $1,794 $1,522 $4,683 $3,832 The FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities. This statement supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that the liability should initially be measured and recorded at fair value. The timing of recognizing future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. We will adopt the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002. 3. GOODWILL AND OTHER INTANGIBLE ASSETS SFAS 142 was effective for AEP on January 1, 2002. The adoption of SFAS 142 required 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. The fair values of the UK and Australia retail electricity and supply operations were estimated using a combination of market values based on recent market transactions and cash flow projections. 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 a change in accounting principle. 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 nine months ended September 30, 2002 by operating segment are:

The transitional impairment loss related to SEEBOARD and CitiPower goodwill, which is reported as a cumulative effect of an accounting change, is excluded from the above schedule. Under SFAS 144, the assets of SEEBOARD and CitiPower, including goodwill and acquired intangible assets no longer subject to amortization, are reported as Assets of Discontinued Operations on one line in the balance sheet. See Note 4 related to the sale of SEEBOARD and CitiPower. In the first quarter of 2002, AEP recognized a goodwill impairment loss of $12 million ($8 million net of tax) as a result of management's decision to exit its Gas Power Systems business that was developing customized generators powered by surplus helicopter engines. Management elected to exit this business due to technical problems with the underlying technology and recognized an impairment loss for all goodwill related to the acquisition of Gas Power Systems. As required by SFAS 142 the following tables show the transitional disclosures to adjust reported net income and earnings per share to exclude amortization expense recognized in prior periods related to goodwill and intangible assets that are no longer being amortized.

Acquired Intangible Assets Acquired intangible assets subject to amortization are $35 million at September 30, 2002 and $33 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 nine months ended September 30, 2002. Estimated aggregate amortization expense is $4 million for each year 2003 through 2008. AEP's acquired intangible assets no longer subject to amortization were comprised of distribution licenses for CitiPower operating franchises. In accordance with SFAS 144, the assets of CitiPower, including acquired intangible assets no longer subject to amortization, are reported as Assets of Discontinued Operations on one line in the balance sheet. See Note 4 related to the sale of CitiPower. 4. 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 $941 million in net 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 loss of $345 million at June 30, 2002. 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 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 3) and has been reported as a cumulative effect of a change in accounting principle retroactive to January 1, 2002. A $46 million reduction of the net loss was recognized in the third quarter of 2002 to reflect changes in exchange rates to closing, settlement of working capital true-up and selling expenses. Proceeds from the sale of SEEBOARD were used to pay down bank facilities and short-term debt. The assets and liabilities of SEEBOARD were aggregated on the balance sheet as Assets of Discontinued Operations and Liabilities of Discontinued Operations. The major classes of SEEBOARD's assets and liabilities of discontinued operations are: December 31, 2001 (in millions) Assets Current Assets $ 324 Plant, Property and Equipment, Net 1,283 Goodwill 1,129 Other Assets 96 ------ Total Assets of Discontinued Operations $2,832 ====== Liabilities Current Liabilities $ 752 Long-term Debt 701 Deferred Income Taxes 268 Other Liabilities 77 ------ Total Liabilities of Discontinued Operations $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 completed the sale in August 2002 and received net cash of approximately $175 million and the buyer assumed CitiPower debt of approximately $674 million. AEP recorded a net charge totaling $125 million as of June 30, 2002. $98 million was recorded in the second quarter of 2002 relating to a loss on the distribution license intangible asset. The remaining $27 million of net loss was classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see Note 3) and was recorded as a cumulative effect of a change in accounting principle retroactive to January 1, 2002. The loss on the sale of CitiPower increased $8 million to $133 million in the third quarter of 2002 based on actual closing amounts and exchange rates. CitiPower's results of operation have been reclassified as discontinued operations in accordance with SFAS 144. The assets and liabilities of Citipower have been aggregated on the December 31, 2001, balance sheet as assets of discontinued operations and liabilities of discontinued operations. The major classes of CitiPower's assets and liabilities of discontinued operations are: December 31, 2001 (in millions) Assets Current Assets $ 138 Plant, Property and Equipment, Net 495 Goodwill/Intangibles 466 Other Assets 54 ------ Total Assets of Discontinued Operations $1,153 ====== Liabilities Current Liabilities $ 83 Long-term Debt 612 Deferred Income Taxes 86 Other Liabilities 34 ---- Total Liabilities of Discontinued Operations $815 ==== Total revenues and pretax profit (loss) of the discontinued operations of SEEBOARD and CitiPower were: SEEBOARD CitiPower -------- --------- (in millions) Revenues 3 months ended 9/30/01 $ 313 $ 83 3 months ended 9/30/02 - (2) 9 months ended 9/30/01 1,062 251 9 months ended 9/30/02 694 204 Pretax Profit 3 months ended 9/30/01 20 (10) 3 months ended 9/30/02 64 - 9 months ended 9/30/01 100 - 9 months ended 9/30/02 155 (175) 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, subject to regulatory approval, to transfer two of its Texas retail electric providers (REPs) to Centrica, a provider of retail energy and other consumer services. An independent appraiser established the fair market value for the transaction that was within the range of $133 million to $153 million specified in the agreement in order for the transaction to be completed. If the transaction is approved by the PUCT and others as agreed by the parties 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. Completion of the transaction is contingent upon the regulatory approval from the PUCT. 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. Under the Texas Legislation, REPs are subject to a clawback liability if customer change does not attain thresholds required by the legislation. AEP is responsible for a portion of such liability, if any, for the portion of the period it owned the REPs after January 1, 2002. AEP will also receive an up-front payment of approximately $39 million from Centrica associated with the back-office service agreement. If an acceptable regulatory approval is not obtained by December 31, 2002, either party has the right to terminate the transaction. 5. INDUSTRY RESTRUCTURING As discussed in the 2001 Annual Report, customer choice of electricity supplier has been implemented 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, pricing standard offer electric generation effective January 1, 2006 at the market price used by the companies to estimate transition costs 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 delayed in the implementation of their RTO participation plans. We continue to pursue integration of CSPCo, OPCo and other AEP East electric operating companies into PJM and anticipate completing that integration in 2003. Management is unable to predict the timing of FERC's final approval of RTOs, the timing of an RTO being operational or the outcome of this proceeding before the PUCO. In October 2002 the PUCO initiated an investigation of the financial condition of Ohio's regulated public utilities. The PUCO's goal is to identify measures available to the PUCO to ensure that the regulated operations of Ohio's public utilities are not impacted by adverse financial consequences of parent or affiliate company unregulated operations and take appropriate corrective action. The utilities and other interested parties were requested to provide comments and suggestions by November 12, 2002, with reply comments November 22, 2002, on the type of information necessary to accomplish the stated goals, the means to gather the required information from the public utilities and potential courses of action that the PUCO could take. Management is unable to predict the outcome of the PUCO's investigation or its impact on results of operations and business practices, if any. 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 all its previous customers under capped rates. 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 or 2003. However, the Virginia restructuring law allows rates to be adjusted in certain circumstances including changes in fuel prices. As discussed in Note 6, an APCo requested fuel factor increase was approved in November 2002 and will be effective on January 1, 2003. The restructuring law also allows for an adjustment of non-generation base rates once during the transition period but no earlier than January 1, 2004. 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 all appropriate regulatory approvals. In September 2002 the FERC approved our corporate separation plan. SEC approval remains pending. 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 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 excess cost over market (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. In order to obtain a market value of generating plant for purposes of determining stranded costs for the 2004 true-up proceeding, CPL anticipates filing a plan of divestiture with the PUCT in the fourth quarter of 2002 seeking approval of a sales process for all of its generating facilities. 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 Texas Restructuring Legislation provides for an earnings test each year 1999 through 2001. For CPL, any earnings in excess of the most recently approved cost of capital in its last rate case must be applied to reduce stranded costs. Companies without stranded costs, including SWEPCo and WTU, must pay any excess earnings to customers, invest them in improvements to transmission or distribution facilities or invest them to improve air quality at generating facilities. The Texas Restructuring Legislation required PUCT approval of the annual earnings test calculation. 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 be used to reduce stranded costs. 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. The PUCT staff issued its recommendation for the 2001 earnings test in September 2002. An estimate of 2001 excess earnings of $8 million for CPL, $2 million for SWEPCo and none for WTU were recorded in 2001. Adjustments to reflect the PUCT staff's estimate of excess earnings were recorded prior to September 30, 2002. When the PUCT issues its final order regarding 2001 excess earnings further adjustments may be necessary. The PUCT staff's report shows excess earnings of $2 million for SWEPCo, $0.7 million for WTU and none for CPL. 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 ended December 31, 2001. As discussed in Note 6 "Rate Matters", WTU filed its final fuel reconciliation for its ERCOT service territory with the PUCT in June 2002 and CPL intends to file its final fuel reconciliation by the end of 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 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 alternative electric suppliers are registered to compete in I&M's Michigan service territory. Management has concluded that as of September 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 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 subsequent 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 legislative activity, the Public Service Commission of West Virginia closed two proceedings related to electricity restructuring in the summer of 2002. The two closed West Virginia Commission proceedings related to 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 has reviewed these two proceedings and has concluded that at this time it is not clear that APCo meets the requirements to reapply SFAS 71. Management believes definitive action from the West Virginia Legislature or the Public Service Commission is required to reapply SFAS 71. 6. RATE MATTERS ICR Explanation - Affecting AEP, CPL, PSO, SWEPCo and WTU The AEP West electric operating companies' power is dispatched real time on an economic basis and is later allocated among the AEP West electric operating companies using the Interchange Cost Reconstruction (ICR) system based on dispatch information from internal and external sources. ICR is designed to allocate the cost of power under the terms and conditions of the AEP West Operating Agreement. 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 $27.5 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 $293.7 million of eligible fuel and fuel related expenses serving both ERCOT and SPP retail customers. In October 2002 the filing was split into two phases. The first phase examined all components of the filing except for AEP trading activities and the associated margins that flow back to customers as an offset to fuel costs. The intervenor groups filed testimony in the first phase recommending that up to $25 million of WTU's requested retail eligible fuel recovery be disallowed and hearings were held on October 23, 2002. WTU disputed the recommendations. On October 21, 2002, the PUCT Staff and Office of Public Utility Counsel (OPC) filed a joint Motion for Summary Decision related to the second phase issue and requested that approximately $18.5 million of WTU's retail eligible fuel recovery be disallowed without a hearing. On November 8, 2002, the administrative law judges (ALJs) in the case denied the motion for Summary Judgment. The PUCT Staff and OPC could appeal the ALJs' decision to the full PUCT. The intervenors filed testimony on October 29, 2002 in the second phase recommending that up to $34 million of WTU's requested retail eligible fuel recovery be disallowed. The intervenors recommended disallowance includes the amount sought in the October 21 Motion for Summary Decision. The total recommended retail disallowance is approximately $59 million. Hearings for the second phase will be held on November 13, 2002. The PUCT is not expected to issue a final order in this case until 2003. An adverse ruling from the PUCT could have a material impact on future results of operations, cash flows and financial condition. ERCOT Over-scheduling - Affecting AEP, CPL and WTU In late 2001, the PUCT initiated an investigation of the impact of scheduling of electric loads and resources by qualified scheduling entities (QSE) in ERCOT in August 2001. ERCOT began serving as a central control center for all of ERCOT at the end of July 2001. QSEs schedule loads and resources for ERCOT market participants including power generation companies and retail electric providers. In August 2001 ERCOT incurred substantial costs for managing transmission in its north zone. The costs incurred by ERCOT to manage congestion are shared by all ERCOT QSEs. The PUCT's investigation determined that a substantial amount of the congestion charges were the result of QSEs, including AEP's QSE, scheduling more resources than required to meet their actual load requirements in the ERCOT north zone. AEP's QSE over-scheduled resources due to an error in the allocation of estimated load requirements between ERCOT congestion zones. Pursuant to the PUCT's investigation, QSEs, including AEP's QSE, agreed to a settlement that provides for the refund of payments received for adjusting resource schedules for congestion. The settlement was approved by the PUCT in November 2002. The settlement recognizes that the scheduling errors were associated with the start up of the ERCOT competitive market. Settlement amounts will be refunded to QSEs in ERCOT. The AEP QSE will pay $3.2 million to ERCOT and expects to receive $1.9 million from ERCOT in congestion refunds for a net payment of $1.3 million. The ERCOT QSE will allocate these payments and refunds to WTU and CPL. WTU expects to incur a net cost of $2.7 million and CPL expects to receive a net refund of $1.4 million. It is expected that both the WTU payment and CPL refund will be reflected in the final fuel reconciliations for each company and as result these amounts are not expected to have any impact on net income. 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 natural gas and purchased power using NYMEX natural gas prices. 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. On August 26, 2002, the PUCT issued an order approving a 22% increase to the fuel portion of their "price-to-beat" rates effective immediately for both CPL REP and WTU REP. The PUCT order approving the 22% increase has been appealed. 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. In July 2002 FERC approved a revised open access transmission tariff. Refunds totaling $1.3 million including interest were issued in August 2002. The allocation of the refunds resulted in revenue increases of $2.5 million for PSO and $2.8 million for SWEPCo and revenue reductions of $2.8 million for CPL and $1.2 million for WTU. Texas Transmission Cost Recovery - Affecting AEP, CPL and WTU In July 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 received approval to increase their TCRF by $0.8 million and $0.2 million, respectively. The TCRF increase has been implemented. Fuel and Purchased Power Recovery - Affecting AEP, CPL, PSO, SWEPCo and WTU PSO has Under-Recovered Fuel Costs of $99.8 million at September 30, 2002, representing fuel and purchased power costs recorded but not yet collected from retail customers in Oklahoma and cost to be allocated among the AEP West electric operating companies. During the third quarter of 2002, PSO estimated that the under-recovered fuel cost due to natural gas price increases that were not expected when PSO set its quarterly factors during the year were approximately $25 million. The formation of the ERCOT single control zone increased the need for data estimation and true-up which has resulted in extended true-up periods associated with allocations performed on estimated data. During 2002, AEP reallocated purchased power costs among the four AEP West electric operating companies for the periods prior to January 1, 2002 (the ICR Adjustments). The effects of the reallocation on pretax income were insignificant to CPL and PSO and increased pretax income at SWEPCo and WTU by $2.4 million and $1.9 million, respectively. As updated or final data become known, AEP is reallocating purchase power costs among the four AEP West electric operating companies. To date, completed reallocations of purchased power costs among the AEP West electric operating companies increased PSO's under-recovered amount by $44.6 million. The reallocation currently in process is expected to reduce PSO's under-recovered fuel and purchased power costs and to increase the costs allocated to the other AEP West electric operating companies (SWEPCo, CPL and WTU). PSO's next opportunity to request a change to its fuel factors will be in November 2002, with new rates beginning December 2002, subject to review and approval by the Corporation Commission of the State of Oklahoma (OCC). To the extent the OCC and/or the AEP West Commissions regulating SWEPCo do not permit recovery of the revised fuel and purchased power costs, there could be an adverse effect on its results of operations and cash flows. Furthermore, if the currently pending reallocations result in additional costs being allocated to CPL and WTU, these additional costs may not be recoverable since there is no longer a fuel clause for these companies. As a result, any additional costs that may be reallocated to CPL and WTU could have an adverse effect on their future results of operations and cash flows. Louisiana Compliance Filing - Affecting AEP and SWEPCo On October 15, 2002, SWEPCo filed with the Louisiana Public Service Commission (LPSC) detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required as a result of the order by the LPSC approving the merger between AEP and CSW. The LPSC's merger order also provides that SWEPCo's base rates are capped at the present level through mid-year 2005. The filing indicates that SWEPCo's current rates should not be reduced because SWEPCo's current revenues are below the level of revenues that SWEPCo should be permitted to recover. This filing is under review by the LPSC staff. If the LPSC disagrees with our conclusion, they could order SWEPCo to file a full cost of service revenue requirement in order to determine whether SWEPCo's capped rates should be reduced. FERC Long-term Contracts - Affecting AEP and AEP East and AEP West electric operating companies In September 2002 the FERC voted to hold hearings to consider requests from certain wholesale customers located in western states to break long-term contracts which they allege are "high-priced". At issue are long-term contracts entered during the California energy price spike in 2000 and 2001. The complaints allege that AEP sold power at unjust and unreasonable prices. The FERC delayed hearings to allow the parties to hold settlement discussions. Management is unable to predict the outcome of these proceedings or their impact on results of operations 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. A public hearing was held on September 23, 2002 related to this filing. On November 8, 2002, a decision was issued in this proceeding approving an increase of approximately $24 million. Environmental Surcharge Filing - Affecting AEP and KPCo In September 2002 KPCo filed with the KPSC to revise its environmental surcharge tariff to recover the cost of emissions control equipment being installed at Big Sandy Plant. See NOx Reductions in Note 9. The surcharge request, estimated to increase annual revenues by approximately $21 million, must be approved by the KPSC before its inclusion in customers' bills. If the KPSC does not approve an increase in the environmental surcharge, results of operations and cash flows would be negatively impacted. 7. BUSINESS SEGMENTS AEP has three business segments: Wholesale,Energy Delivery and Other. The business activities of each of these segments are as follows: Wholesale oGeneration of electricity for sale to retail and wholesale customers oGas pipeline and storage services oMarketing and trading of electricity, gas, coal and other commodities oCoal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery oDomestic electricity transmission oDomestic electricity distribution Other oInvestments in foreign power and distribution projects oTelecommunication services Segment results of operations for the nine months ended September 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, and income taxes, and the effect of discontinued operations, extraordinary items and the cumulative effect of changes in accounting principles. 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. By excluding discontinued operations, extraordinary items and the cumulative effect of changes in accounting principles, EBIT gives more focused guidance on segment operating performance. 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.

In October 2002, we announced our plans to reduce our exposure to speculative energy trading markets and to downsize our trading and wholesale marketing operations. It is expected that in the future our trading and marketing operations will be limited to risk management around our assets. 8. 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. AEP applies the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contract are used to repurchase outstanding shares. 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 5). The proceeds were used to reduce CPL's debt and retire 4.5 million shares of CPL's common stock. The notes were issued under the following classes: Principal Interest Scheduled Final Final Class Amount Rate Payment Date Maturity Date ----- --------- -------- --------------- ------------- (in millions) (%) A-1 129 3.54 2005 2007 A-2 154 5.01 2008 2010 A-3 107 5.56 2010 2012 A-4 215 5.96 2013 2015 A-5 192 6.25 2016 2017 Other issuances and retirements of long-term debt and other securities during the first nine 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 AEP Subs. Notes Payable 121 6.225-6.60 2017 Retirements AEP Senior Unsecured Notes $ 5 6.125 2006 APCo First Mortgage Bonds 40 6.65 2003 APCo First Mortgage Bonds 30 6.85 2003 APCo First Mortgage Bonds 50 7.38 2002 APCo Junior Debentures 75 8-1/4 2026 APCo Junior Debentures 90 8.00 2027 CPL Senior Unsecured Notes 150 Variable 2002 CPL First Mortgage Bonds 73 7-1/4 2004 CPL First Mortgage Bonds 59 7-1/2 2002 CPL First Mortgage Bonds 33 6-7/8 2003 CPL First Mortgage Bonds 56 7-1/8 2008 CPL First Mortgage Bonds 57 7-1/2 2023 CPL First Mortgage Bonds 128 6-5/8 2005 CSPCo Junior Debentures 73 8-3/8 2025 CSPCo Junior Debentures 40 7.92 2027 I&M Installment Purchase Contract 50 Variable 2014 I&M Senior Unsecured Notes 200 Variable 2002 KPCo First Mortgage Bonds 15 7.90 2023 KPCo First Mortgage Bonds 15 6.65 2003 KPCo First Mortgage Bonds 15 6.70 2003 KPCo First Mortgage Bonds 15 6.70 2003 KPCo Notes Payable 25 7.445 2002 OPCo First Mortgage Bonds 5 8.80 2022 OPCo Junior Debentures 85 8.16 2025 OPCo Junior Debentures 50 7.92 2027 SWEPCo Senior Unsecured Notes 150 Variable 2002 WTU First Mortgage Bonds 17 7-3/4 2007 WTU First Mortgage Bonds 22 7 2004 WTU First Mortgage Bonds 16 6-1/8 2004 WTU First Mortgage Bonds 34 6-3/8 2005 Non-Registrant AEP Subs. Notes Payable 12 Variable 2002-2007 AEP Subs. Revolving Credit Agreement 239 Variable 2003 In addition to the transactions reported in the table above, the following table lists intercompany issuances and retirements of debt due to AEP. Type of Principal Interest Company Debt Amount Rate Due Date ------- ------- --------- -------- -------- Issuances (in millions) (%) --------- CSPCo Notes Payable $160 6.501 2006 Retirements CSPCo Notes Payable $200 Variable 2002 Related Activities In the third quarter of 2002, all long term debt associated with SEEBOARD and CitiPower (approximately $1.8 billion) was assumed by the buyers. AEP Credit renewed its sale of receivables agreement during the second quarter of 2002. At September 30, 2002, the sale of receivables agreement provided commitments of $600 million to purchase receivables from AEP Credit, of which $528 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 (with a one year term option) 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. 9. COMMITMENTS AND 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, AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against 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 District 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 the Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future results of operations and cash flows. NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU 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 Commission on Environmental Quality (formerly 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 a variety of emission control technologies to reduce NOx emissions to comply with the applicable state and Federal NOx requirements. This includes selective catalytic reduction (SCR) technology on certain units and non-SCR technologies on a larger number of units. During 2001 SCR systems commenced operations on OPCo's Gavin Plant. 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. Non-SCR technologies have been installed and begun operation on a number of units across the AEP System and additional units will be equipped with these technologies. The AEP NOx compliance plan is a dynamic plan that is continually reviewed and revised as new information becomes available on the performance of installed technologies and the cost of planned technologies. Certain compliance steps may or may not be necessary dependent on this information. The result is that the plan has a range of possible outcomes. Our current estimate indicates that AEP's compliance with the NOx Rule, the Texas Commission on Environmental Quality rule and the Section 126 Rule could result in required capital expenditures in the range of $1.3 billion to $2 billion, including amounts spent through September 30, 2002. The range in the cost estimate reflects the uncertainty over the need for certain SCR projects. Estimated compliance cost ranges by registrant subsidiaries are as follows: Estimated Compliance Costs (in millions) AEGCo $30 - 198 APCo 445 CPL 5 CSPCo 93 I&M 42 - 210 KPCo 163 OPCo 535 - 864 PSO 1 SWEPCo 40 WTU 5 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo On October 15, 2002, certain subsidiaries of AEP filed claims against Enron Corp. and its subsidiaries in the bankruptcy proceeding filed by the Enron entities which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities remained unsettled at the date of Enron's bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court is not certain. In connection with the 2001 acquisition of HPL, we acquired exclusive rights to use and operate the underground Bammel gas storage facility pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage reservoir and the related compression, treating and delivery systems. We also entered into an agreement with BAM Lease Company which grants HPL the right to use approximately 65 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the Bammel gas storage facility. The Bammel Gas Trust, which purportedly owned approximately 55 billion cubic feet of the gas, had entered into a financing arrangement in 1997 with Enron and a group of banks. These banks purported to have certain rights to the gas in certain events of default. In connection with AEP's acquisition of HPL, the banks entered into an agreement granting HPL's use of the cushion gas and released HPL from liabilities and obligations under the financing arrangement. HPL was thereafter informed by the banks of a purported default by Enron under the terms of the referenced financing arrangement. In July 2002 the banks filed a lawsuit against HPL seeking a declaratory judgment that they have a valid and enforceable security interest in this cushion gas which would permit them to cause the withdrawal of this gas from the storage facility. In September 2002 HPL filed a general denial and certain counterclaims against the banks. Management is unable to predict the outcome of this lawsuit or its impact on results of operations and cash flows. In 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 developments in the bankruptcy proceeding or the lawsuit related to the cushion gas financing agreement our future results of operations, cash flows and possibly financial condition could be adversely impacted. Shareholder Lawsuits - Affecting AEP In October and November 2002 several lawsuits alleging securities law violations and seeking class action certification were filed in Federal District Court, Columbus, Ohio against AEP, certain AEP executives and in some of the lawsuits against certain investment banking firms. Some of the lawsuits claim that AEP failed to disclose that alleged "round trip" trades resulted in an overstatement of revenues and all of the lawsuits claim that AEP failed to disclose that AEP traders falsely reported energy prices to trade publications that publish gas price indices. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorney fees and costs. The time period within which others may file to attempt to become lead plaintiff will end in late December 2002. AEP cannot predict whether any additional lawsuits will be filed. AEP intends to vigorously defend against these actions. Arbitration of Williams Claim - Affecting AEP In November 2002 AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' failure to provide the monetary security required for natural gas deliveries by AEP. Consequently, both parties claimed default and terminated all outstanding natural gas and electric power trading deals among the various Williams and AEP affiliates. Williams claimed that AEP owes approximately $130 million in connection with the termination and liquidation of all trading deals. AEP believes it has valid claims arising from Williams actions and is seeking, in part, a determination that either no amount is due or that a lesser amount is due from AEP to Williams and the extent of any other damages and legal or equitable relief available. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. 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". In August 2002 we received an informal data request from the SEC asking us to voluntarily provide documents related to "round trip" or "wash" trades. We have provided the requested information to the SEC. In September 2002 we received a subpoena from FERC requesting information about our natural gas transactions and their potential impact on gas commodity prices in the New York City area. We responded to the subpoena in October 2002. On October 9, 2002, AEP dismissed several employees involved in natural gas marketing and trading after the company determined that they provided inaccurate price information for use in indexes compiled and published by trade publications. We have and will continue to provide to the FERC and the CFTC information relating to price data given to energy industry publications. FERC Proposed Security Standards - Affecting AEP System 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 required 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 - Affecting AEP System 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 September 30, 2002 is approximately $88 million and $105 million, respectively. The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 was approximately $71 million and $83 million, respectively. 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. During 2002, Vale and other participants in the electricity industry in Brazil have experienced reduced cash flows due to the effects of significant currency devaluation, electricity rationing, and lower than expected tariffs and demand. There is additional uncertainty related to the current political environment and the ability to obtain higher future tariffs from regulators. Vale has principal payments of $55 million due in November of 2002 and is currently attempting to refinance or restructure debt and sell assets in order to improve its cash flows. The ability of Vale to honor its responsibilities under the put obligation is dependent on its current and future cash flows and its ability to refinance or restructure debt and sell assets. Due to Vale's cash flow difficulties and the current industry and market conditions in Brazil, we are updating the previous reviews of the collectibility and value of the put option in order to determine if there is an other than temporary impairment of our $215 million investment. 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 the reorganization, divestiture or dissolution of AFN. Management is also considering a reorganization or divestiture of its other telecommunications operations in order to optimize the value of such assets. The review of the telecommunications business strategy, which was started in the third quarter of 2002, is expected to be completed in the fourth quarter of 2002. In connection with the completion of this assessment, management will review its investment in telecommunication companies for any impairment of value. Management is unable to determine the extent of any impairment until such evaluation is complete. At September 30, 2002, AEP's investment in telecommunications companies was approximately $252 million. Wind Project - Affecting WTU WTU is assessing recoverability of certain wind generating assets due to performance concerns. The net book value of these assets is approximately $5 million as of September 30, 2002. Other AEP and its subsidiary registrants continue to be involved in certain other matters discussed in the 2001 Annual Report. 10. PLANT CLOSING AND STAFF REDUCTIONS In September 2002 AEP proposed closing 16 gas-fired power plants in the ERCOT control area of Texas (8 WTU plants and 8 CPL plants). ERCOT indicated that it may designate some of those plants as "reliability must run" (RMR) status. In October ERCOT designated seven RMR plants (3 WTU plants and 4 CPL plants) and approved AEP's plan to inactivate nine other plants (5 WTU plants and 4 CPL plants). The process of moving the plants to inactive status will take up to two months. Employees of the plants to become inactive (approximately 183) will be eligible for severance and outplacement services. RMR plants are required to ensure the reliability of the power grid, even if electricity from those plants is not required to meet market needs. ERCOT and AEP negotiated interim contracts for the remainder of 2002 for the seven RMR plants. It is expected that 2003 RMR requirements will be announced before the end of 2002. As a result of the decision to inactivate WTU plants, a write-down of utility assets of approximately $34 million (pre-tax) was recorded in Other Operation expense during the third quarter. The decision to inactivate the CPL plants resulted in a write-down of utility assets of approximately $100 million which was deferred and recorded in Regulatory Assets. Inventory on hand to service the 16 plants is being evaluated for use at other plants within the AEP System as a part of the closing process. A write-down, if any, associated with inventory becoming obsolete as a result of the plant closings will be recorded as identified during the closing process. Severance benefit arrangements for employees at these plants are expected to be finalized in the fourth quarter of 2002. REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, ACCOUNTING POLICIES AND OTHER MATTERS This is our combined presentation of management's discussion and analysis of financial condition, accounting policies 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 September 30, 2002 is presented with their financial statements earlier in this document. FINANCIAL CONDITION Credit Ratings 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 and lowered First Mortgage Bond ratings of all the registrant subsidiaries to "BBB+" from "A". AEP's commercial paper programs' short-term ratings of A2 and P2 with stable outlook have been confirmed by Standard and Poor's and Moody's, respectively. In June 2002 Fitch Ratings Service downgraded SWEPCo from A to A- for senior unsecured notes, but had no further rating actions. Fitch has all companies on stable outlook and the commercial paper rating is stable at F-2. The review of the companies' debt position and credit rating is being completed at our request 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. At September 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 September 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. Liquidity Liquidity, or access to cash, has become a more critical factor in determining the financial integrity of a company, particularly because of the volatility of wholesale power markets and the potential limitations that credit rating downgrades place on a company's ability to raise capital. Management is committed to preserving an adequate liquidity position and is already addressing our financial needs for 2003. As of September 30, 2002, we had an available liquidity position of $3.3 billion as illustrated in the table below: Credit Facilities in $ Millions Maturity ----------------- ------------- -------- Commercial Paper Backup Lines of Credit $2,500* 5/03 Commercial Paper Backup Lines of Credit 1,000 5/05 Corporate Separation Revolving Credit 1,725 4/03 Other Revolving Credit Facilities 295 10/03 ------ Total $5,520 ====== Cash US Liquidity Fund 300** ------ Total Credit Facilities and Cash $5,820 ====== Less: Commercial Paper Outstanding 1,967 Corporate Separation Loans 600 ------ Total Available Liquidity $3,253 ====== * Contains one year term-out provision. ** Unrestricted and excludes $266 million of operational cash on hand. Our goal is to use cash from operations to fund our capital expenditures, dividends and working capital. Short-term debt is used as an interim vehicle to bridge timing differences in the needs for cash and to fund debt maturities until permanent financing is arranged. Short-term debt comes from a commercial paper program at the parent company. Proceeds are loaned to the subsidiaries through intercompany notes. We also operate a money pool and sell accounts receivable to provide liquidity for our domestic electric subsidiaries. The commercial paper program is backed by $3.5 billion in bank facilities of which $1 billion matures in May 2005. The remaining $2.5 billion matures in May 2003 and has a one-year term-out provision at the company's option. At September 30, 2002 approximately $1.97 billion of commercial paper was outstanding. A significant portion of the commercial paper balance is related to funding of debt maturities of the Ohio and Texas subsidiaries pending a permanent financing program as part of corporate separation. The Ohio and Texas subsidiaries plan to begin the permanent financing program in the near future and the commercial paper balance should therefore decrease substantially as early as in the fourth quarter of this year. AEP also has a $1.725 billion bank facility maturing in April 2003 that is available for debt refinancing in anticipation of corporate separation. At September 30, 2002, $600 million was outstanding under that facility. We anticipate refinancing that amount as part of the permanent financing as discussed above. If the permanent financing for corporate separation is completed as planned we do not anticipate needing this facility beyond its maturity in April 2003. We also have revolving credit facilities in place for 300 million Euros to support the wholesale business in Europe. As of September 30, 2002, none of these amounts were drawn. As noted in the table above, AEP also maintains a $300 million cash liquidity reserve fund to support its trading and marketing operations in the U.S. In total, we had approximately $5.8 billion in liquidity sources of which $3.3 billion were unused and available at September 30, 2002. During the first nine months of 2002 cash flow from operations was $755 million, including $702 million from Net Income from Continuing Operations and $973 million from depreciation, amortization, deferred taxes, and deferred investment tax credits offset by additional working capital requirements. These additional working capital requirements reflect the one time impact of the discontinuance of the sale of accounts receivable for Texas companies and billing delays related to the transition to customer choice in Texas, higher margin requirements for gas trading, seasonal fuel inventory growth, and other miscellaneous items. Capital expenditures including acquisitions were $1,147 million. Major construction expenditures included amounts for emission control technology on several coal-fired generating units (see discussion in Note 9). Dividends on common stock were $590 million. Cash from operations, proceeds from the sale of SEEBOARD and CitiPower, and the issuance of common stock, common equity units, 15-year notes for a wind generation project and transition funding bonds provided funds to reduce debt, fund construction and pay dividends. 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 a portion of available cash. Interim financing arrangements are being negotiated for the UK generating plants to replace a portion of the existing (pound)403 million bridge financing that is currently in place. Completion of this interim financing is anticipated prior to year-end. During 2003 long-term financing will be sought to replace the interim financing. 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 were $406 million and $89 million, respectively. In order to pay for a portion of these retired bonds, as well as previously retired bonds, we borrowed $600 million under the $1,725 million corporate separation revolving credit facility. 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 our consolidated balance sheet. Total consolidated plant and property additions including capital leases for the nine months ended September 30, 2002 were $1,148 million. The following table shows the plant and property additions by certain registrant subsidiaries: Company Amount ------- ------ (in millions) APCo $175 CPL 99 I&M 95 OPCo 224 SWEPCo 73 Completed, 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 and 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 net cash of approximately $941 million which was used to reduce debt. The sale resulted in a loss of $299 million (see Note 4). 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 2002 we completed the sale of CitiPower, our energy delivery and retail supply businesses in Australia. AEP received approximately $175 million in net cash which we used to reduce debt. The sale resulted in a $133 million loss (see Note 4). AEP provides telecommunications services to businesses and telecommunication companies through a broadband fiber optic network. AEP conducts its telecommunication 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 the reorganization, divestiture or dissolution of AFN. Management is also considering a reorganization or divestiture of its other telecommunications operations in order to optimize the value of such assets. The review of the telecommunications business strategy, which was started in the third quarter of 2002, is expected to be completed in the fourth quarter of 2002. In connection with the completion of this assessment, management will review its investment in telecommunication companies for any impairment of value. Management is unable to determine the extent of any impairment until such evaluation is complete. At September 30, 2002, AEP's investment in telecommunications companies was approximately $252 million. In October 2002 the City Commission of Elk City, Oklahoma voted to hold a referendum seeking voter approval of a $20.4 million acquisition of PSO's distribution assets within the city limits. The vote is expected to occur in December 2002. If the referendum passes, Elk City, per the terms of their franchise with PSO, will buy the assets at their fair market value, estimated to be approximately $20 million. Estimated annual revenues from the customers served in Elk City is $7.5 million. Management is unable to predict the result of this vote. 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. In Texas, we intend to transfer the generation assets from the integrated electric operating companies (CPL and WTU) to unregulated generation companies. In Ohio, we intend to transfer transmission and distribution assets from the integrated companies to two new wires companies leaving CSPCo and OPCo as generating companies. We proposed amendments to the power pooling agreements to remove the four Ohio and Texas generating 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. Negotiated settlement agreements with the state regulatory commissions and other major intervenors were filed with the FERC in December 2001. In September 2002 the FERC conditionally approved our corporate separation plan including the settlement agreements. Terms in the settlement agreements, which would be effective upon implementation of corporation separation, include extension of the base rate freeze and fuel clause cap for Indiana through 2007 and extension of certain power supply contracts. In addition, SEC approval of our corporate separation plan is required for its implementation. The Arkansas Public Service Commission intervened at the SEC which may extend the length of time needed for the SEC's review. In order to execute this separation, we may be required to retire various debt securities and will need 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 the SPP. In December 2001 the FERC rejected the Alliance RTO's filing. Subsequently, in May 2002 AEP announced an agreement with the PJM Interconnection to pursue terms for certain subsidiaries to participate in PJM. Final agreements are currently being 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. In September 2002 AEP notified the FERC of a memorandum of understanding which would permit western transmission assets in SPP to participate in MISO. 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. ACCOUNTING POLICIES Critical Accounting Policies - Revenue Recognition Regulatory Accounting - The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (APCo, CPL, CSPCo, OPCo, SWEPCo, WTU, I&M, KPCo, PSO), 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 to be recovered in the future) and regulatory liabilities (deferred 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 and by matching income with its passage to customers through regulated revenues in the same accounting period. Regulatory liabilities are also recorded to provide currently for refunds to customers that have not yet been made. 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 - Revenues are recognized on the accrual or settlement basis for normal retail and wholesale 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 purchased electricity is received and when expenses are incurred. Domestic Gas Pipeline and Storage Activities - Revenues are recognized 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. Substantially all of the forward gas purchase and sale contracts, excluding wellhead purchases of natural gas, swaps and options for the domestic pipeline operations, qualify as derivative financial instruments as defined by SFAS 133. Accordingly, net gains and losses resulting from revaluation of these contacts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net of applicable credit and liquidity reserves. Energy Marketing and Trading Activities - AEP engages in non-regulated wholesale electricity and natural gas marketing and trading transactions (trading activities). A portion of the revenues and costs associated with AEP's wholesale electricity trading activities is allocated to CPL, SWEPCo, PSO and WTU and to members of the AEP Power Pool (APCo, CSPCo, I&M, KPCo, OPCo). AEP's 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 traded futures and options and over-the-counter options and swaps; however CPL, SWEPCo, PSO and WTU are only allocated a portion of the forward transactions. AEP recognizes 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 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. Unrealized mark-to-market gains and losses are included in the Balance Sheet as "Energy Trading and Derivative Contracts." Our cost-based rate-regulated electric public utility companies (I&M, KPCo, PSO, and a portion of SWEPCo) defer, as regulatory liabilities (unrealized gains) or regulatory assets (unrealized losses), changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. For contracts which are outside of AEP's traditional marketing area, the change in fair value is included in nonoperating income on a net basis. The majority of trading activities represent physical forward contracts that are typically settled by entering into offsetting contracts. An example of our energy trading activities is when, in January, we enter into a forward sales contract to deliver energy 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 for a sales contract and the realized cost for a purchase contract are included on a net basis in revenues with the prior change in unrealized fair value reversed out of revenues. For I&M, PSO, KPCo and a portion of SWEPCo, 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 for sales and the cost of purchased energy are included in revenues on a net basis. 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 contracts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds is recognized in the income statement as nonoperating income. 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. For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported in the income statement. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income 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 for AEP, APCo, OPCo, CPL, WTU, CSPCo and a portion of SWEPCo, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy energy 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. 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. 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. For AEP, the trading of energy 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. APCo, CSPCo, OPCo, I&M and KPCo also have financial transactions, but record the unrealized gains and losses, as well as the net proceeds upon settlement, in nonoperating income. The fair values of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based primarily on valuation models that 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 aforementioned valuation models. This is particularly true for long-term contracts. AEP applies MTM accounting to 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. Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing us 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 used to manage our exposure to market and other risks from trading activities. New Accounting Pronouncements During 2002, the EITF discussed Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17" (EITF 02-3) and reached consensus on certain issues. EITF 98-10, "Accounting for Contracts Involving Energy Trading and Risk Management Activities," requires that energy trading contracts be accounted for at fair value. EITF 02-3 rescinds Issue No. 98-10 effective for any new contracts entered into after October 25, 2002. For energy trading contracts entered into through October 25, 2002, such contracts will continue to be accounted for at fair value through December 31, 2002. Effective January 1, 2003, such contracts are required to be accounted for at historical cost and we will report this as a cumulative effect of an accounting change. Our energy contracts that qualify as derivatives will continue to be accounted for at fair value under SFAS 133. EITF 02-3 requires that energy trading contracts and derivatives, whether settled financially or physically, be reported in the income statement on a net basis effective January 1, 2003. Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, we reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10. The reclassification of such trading activity to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on our financial condition, results of operations or cash flows. The FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities. This statement supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that the liability should initially be measured and recorded at fair value. The timing of recognizing future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. We will adopt the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002. OTHER MATTERS Industry Restructuring As discussed in Note 5 and the 2001 Annual Report, restructuring and customer choice began in four of the eleven state retail jurisdictions in which the AEP electric utility companies operate. Restructuring legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the supply of electricity. Customer choice of electricity supplier began on January 1, 2001 for Ohio customers and on January 1, 2002, for Michigan, Texas and Virginia customers. In 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, pricing standard offer electric generation effective January 1, 2006 at the market price used by the companies to estimate transition costs 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 delayed in the implementation their RTO participation plans. We continue to pursue integration of CSPCo, OPCo and other AEP East electric operating companies into PJM and anticipate completing that integration in 2003. Management is unable to predict the timing of FERC's final approval of RTO participation. 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 be used to reduce stranded costs. 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 final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ended 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 to the risk of fuel market price increases and could adversely affect future results of operations. In order to obtain a market value of generating plant for purposes of determining stranded costs for the 2004 true-up proceeding, CPL anticipates filing a plan of divestiture with the PUCT in the fourth quarter of 2002 seeking approval of a sales process for all of its generating facilities. 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 for recovery through distribution rates pending the 2004 true-up proceeding's determination of stranded cost recovery. 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 plant costs and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Reduction of Trading Exposure In October 2002, we announced our plans to reduce our exposure to speculative energy trading markets and to downsize our trading and wholesale marketing operations. It is expected that in the future our trading and marketing operations will be limited to risk management around our assets. Litigation Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo As discussed in the 2001 Annual Report, AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against 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 District 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 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 Commission on Environmental Quality (formerly 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 a variety of emission control technologies to reduce NOx emissions to comply with the applicable state and Federal NOx requirements. This includes selective catalytic reduction (SCR) technology on certain units and non-SCR technologies on a larger number of units. During 2001 SCR systems commenced operations on OPCo's Gavin Plant. 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. Non-SCR technologies have been installed and begun operation on a number of units across the AEP System and additional units will be equipped with these technologies. The AEP NOx compliance plan is a dynamic plan that is continually reviewed and revised as new information becomes available on the performance of installed technologies and the cost of planned technologies. Certain compliance steps may or may not be necessary dependent on this information. The result is that the plan has a range of possible outcomes. Our current estimate indicates that AEP's compliance with the NOx Rule, the Texas Commission on Environmental Quality rule and the Section 126 Rule could result in required capital expenditures in the range of $1.3 billion to $2 billion, including amounts spent through September 30, 2002. The range in the cost estimate reflects the uncertainty over the need for certain SCR projects. The following table shows the estimated range of compliance costs for certain of AEP's registrant subsidiaries. Company Amount ------- ------ (in millions) APCo $445 CPL 5 I&M 42-210 OPCo 535-864 SWEPCo 40 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 On October 15, 2002, certain subsidiaries of AEP filed claims against Enron Corp. and its subsidiaries in the bankruptcy proceeding filed by the Enron entities which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on May 31, 2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities remained unsettled at the date of Enron's bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court is not certain. In connection with the 2001 acquisition of HPL, we acquired exclusive rights to use and operate the underground Bammel gas storage facility pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage reservoir and the related compression, treating and delivery systems. We also entered into an agreement with BAM Lease Company which grants the right to use approximately 65 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the Bammel gas storage facility. The Bammel Gas Trust, which purportedly owned approximately 55 billion cubic feet of the gas, had entered into a financing arrangement in 1997 with Enron and a group of banks. These banks purported to have certain rights to the gas in certain events of default. In connection with AEP's acquisition of HPL, the banks entered into an agreement granting HPL's use of the cushion gas and released HPL from liabilities and obligations under the financing arrangement. HPL was thereafter informed by the banks of a purported default under the terms of the referenced financing arrangement. In July 2002 the banks filed a lawsuit against HPL seeking a declaratory judgment that they have a valid and enforceable security interest in this cushion gas which would permit them to cause the withdrawal of this gas from the storage facility. In September 2002 HPL filed a general denial and certain counterclaims against the banks. Management is unable to predict the outcome of this lawsuit or its impact on results of operations and cash flows. In 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 developments in the bankruptcy proceeding or the lawsuit related to the cushion gas financing agreement our future results of operations, cash flows and possibly financial condition could be adversely impacted. Shareholder Lawsuits - Affecting AEP In October and November 2002 several lawsuits alleging securities law violations and seeking class action certification were filed in Federal District Court, Columbus, Ohio against AEP, certain AEP executives and in some of the lawsuits against certain investment banking firms. Some of the lawsuits claim that AEP failed to disclose that alleged "round trip" trades resulted in an overstatement of revenues and all of the lawsuits claim that AEP failed to disclose that AEP traders falsely reported energy prices to trade publications that publish gas price indices. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorney fees and costs. The time period within which others may file to attempt to become lead plaintiff will end in late December 2002. AEP cannot predict whether any additional lawsuits will be filed. AEP intends to vigorously defend against these actions. Spent Nuclear Fuel Disposal Fund Litigation - Affecting AEP, CPL and I&M As discussed in the 2001 Annual Report, I&M and STPNOC, on behalf of STP's joint owners, joined a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related to DOE's nuclear waste fund cost recovery settlement with PECO Energy Company (now Exelon Generation Company, LLC). The settlement adjusted the fees Exelon was required to pay to DOE for disposal of SNF. The fee adjustment allowed Exelon to skip payments to the DOE to make up for Exelon's damages from DOE's breach of its contract obligation to dispose of SNF from commercial nuclear power plants. The companies believed the settlement was unlawful as it would have forced other utilities (rather than DOE) to compensate Exelon for the damages it had incurred from DOE's breach of contract. In September 2002 the U.S. Court of Appeals for the Eleventh Circuit found that DOE acted improperly by adopting the fee adjustment provision of this settlement, that the fee adjustment provisions of the settlement harmed other utilities who pay into the fund and violated the federal nuclear waste management laws and that the fee adjustment provisions of the settlement were null and void. Arbitration of Williams Claim - Affecting AEP In October 2002 AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' failure to provide the monetary security required for natural gas deliveries by AEP. Consequently, both parties claimed default and terminated all outstanding natural gas and electric power trading deals among the various Williams and AEP affiliates. Williams claimed that AEP owes approximately $130 million in connection with the termination and liquidation of all trading deals. AEP believes it has valid claims arising from Williams actions and is seeking, in part, a determination that either no amount is due or that a lesser amount is due from AEP to Williams and the extent of any other damages and legal or equitable relief available. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. 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". In August 2002 we received an informal data request from the SEC asking us to voluntarily provide documents related to "round trip" or "wash" trades. We have provided the requested information to the SEC. In September 2002 we received a subpoena from FERC requesting information about our natural gas transactions and their potential impact on gas commodity prices in the New York City area. We responded to the subpoena in October 2002. On October 9, 2002, AEP dismissed several employees involved in natural gas marketing and trading after the company determined that they provided inaccurate price information for use in indexes compiled and published by trade publications. We have and will continue to provide to the FERC and the CFTC information relating to price data given to energy industry publications. 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 September 30, 2002 is approximately $88 million and $105 million, respectively. The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 was approximately $71 million and $83 million, respectively. 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. During 2002, Vale and other participants in the electricity industry in Brazil have experienced reduced cash flows due to the effects of significant currency devaluation, electricity rationing, and lower than expected tariffs and demand. There is additional uncertainty related to the current political environment and the ability to obtain higher future tariffs from regulators. Vale has principal payments of $55 million due in November of 2002 and is currently attempting to refinance or restructure debt and sell assets in order to improve its cash flows. The ability of Vale to honor its responsibilities under the put obligation is dependent on its current and future cash flows and its ability to refinance or restructure debt and sell assets. Due to Vale's cash flow difficulties and the current industry and market conditions in Brazil, we are updating the previous reviews of the collectibility and value of the put option in order to determine if there is an other than temporary impairment of our $215 million investment. FERC Proposed Security Standards - Affecting AEP System 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 - Affecting AEP System 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. Pension Plan Funded Status AEP sponsors two qualified pension plans and two nonqualified pension plans in the U.S. Substantially all employees are covered by one or both of the pension plans. AEP no longer sponsors foreign pension plans for SEEBOARD in the U.K. and CitiPower in Australia since the divestiture of these investments in 2002 (see Note 4). During the first three quarters of 2002, the market value of the assets in AEP's qualified pension plans declined by approximately $690 million, or 20 percent, to $2.75 billion due to plan benefit payments and the poor performance of the financial markets. The actuarially estimated accumulated benefit obligation (ABO) for the year ended December 31, 2002 is approximately $3.5 billion. There have been no contributions to these plans in 2002 to date. AEP is in full compliance with all regulations governing such plans including all Employee Retirement Income Security Act of 1974 (ERISA) laws. Management is currently evaluating the appropriateness of making contributions to the plans to improve their funded status. If the ABO of these plans continues to exceed the market value of plan assets at December 31, 2002, AEP would be required to record an unfavorable adjustment to the accumulated other comprehensive income (AOCI) component of shareholders' equity (net of tax) and a pension liability in its consolidated balance sheet. AEP cannot currently estimate either the magnitude of this potential adjustment or any additional required contributions to the plans due to uncertainty about the factors impacting these computations, including the performance of plan investments over the remainder of the year and the impact of any changes in actuarial assumptions used to determine the ABO. However, AEP estimates that if using the current market value of pension plan assets and updated actuarial assumptions, including the effect of the current discount assumption, an unfavorable after-tax adjustment of approximately $600 million would be required to the AOCI component of shareholders' equity at December 31, 2002. Continued poor performance of the financial markets could significantly increase the future cost of pension and other post-employment benefits and increase funding requirements beyond 2002. 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 Executive Committee and administered by a Chief Risk Officer. The Risk Executive Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers. We use a risk measurement model which calculates Value at Risk (VaR) to measure our commodity price risk in the trading portfolio. 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 September 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: Nine Months Ended Year Ended September 30, December 31, 2002 2001 ---- ---- High Average Low High Average Low (in millions) (in millions) AEP $21 $12 $7 $28 $14 $5 APCo 2 1 1 4 1 - CPL - - - 3 1 - CSPCo 2 1 - 2 1 - I&M 2 1 - 3 1 - KPCo 1 - - 1 - - OPCo 2 1 - 3 1 - PSO - - - 2 1 - SWEPCo - - - 3 1 - WTU - - - 1 1 - We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one year holding period. The volatilities and correlations were based on three years of weekly prices. The risk of potential loss in fair value attributable to AEP's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $481 million at September 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), frozen by settlement agreements in Michigan and West Virginia and capped in Indiana. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. 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, weather, freight, euro dollars, 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 those limits unless specifically approved by the Risk Executive 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 our financial condition at September 30, 2002. At September 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 Counterparty and Swap Credit Quality: Contracts Options Total September 30, 2002 (in millions) AAA/Exchanges $ 3 $ - $ 3 AA 156 6 162 A 329 8 337 BBB 759 163 922 Below Investment Grade 97 21 118 ------ ---- ----- Total $1,344 $198 $1,542 ====== ==== ====== 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 September 30, 2002 and December 31, 2001 were $317 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 third quarter of 2002 resulted in an unrealized increase in revenues of $139 million and unrealized increase in revenues of $202 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 liquid portions of these curves are validated on a regular basis by the mid-office through the use of independent broker quotes and market data. Illiquid portions of the curves are validated through a review of the underlying market assumptions and variables for consistency and reasonableness. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid price if we have a long position and the price curve 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, specifically I&M, KPCo, PSO and a portion of SWEPCo, is deferred as regulatory assets (losses) or liabilities (gains) 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). Nine Months Ended September 30, 2002 (in millions) Revenues (including mark-to-market adjustment) $10,818 Fuel and Purchased Energy Expense 4,683 ------- Net Revenues $ 6,135 ======= Mark-to-Market Revenues on Open Trading Positions $202 ==== Percentage of Net Revenues Represented by Mark-to-Market on Open Trading Positions 3% == The following tables analyze the changes in fair values of trading assets and liabilities. The first table "Net Fair Value of Energy Trading and Derivative Contracts" 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 and Derivative Contracts" 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 September 30, 2002 of $228 million. Contracts realized/settled during the period include both sales and purchase contracts. The third table "Energy Trading and Derivative Contract Maturities" shows exposures to changes in fair values and realization periods over time for each method used to determine fair value.

The above net fair value of energy trading and derivative contracts includes $202 million at September 30, 2002, in unrealized mark-to-market gains that are recognized in the income statement at September 30, 2002.

(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. (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) Net Option Premiums Paid/(Received) reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2002. (d) 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. (e) "Change in Market Value of Contracts allocated to Regulated Jurisdictions" relates to the net gains of those contracts that are not reflected in the income statement. These net gains are recorded as regulatory liabilities for those subsidiaries that operate in regulated jurisdictions. (f) "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.

(a) "Prices Actively Quoted" represents the Company's exchange traded futures positions. (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. CONTROLS AND PROCEDURES (a) Evaluation of disclosure controls and procedures. Our chief executive officer and our chief financial officer, after evaluating the effectiveness of the Company's "disclosure controls and procedures" (as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 15d-14(c)) as of a date (the "Evaluation Date") within 90 days before the filing date of this quarterly report, have concluded that as of the Evaluation Date, our disclosure controls and procedures were adequate and designed to ensure that material information relating to us and our consolidated subsidiaries would be made known to them by others within those entities. (b) Changes in internal controls. There were no significant changes in our internal controls or to our knowledge, in other factors that could significantly affect our disclosure controls and procedures subsequent to the Evaluation Date. PART II. OTHER INFORMATION 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 and page O-3 of the Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 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. On September 19, 2002, the D.C. Circuit Court denied Federal EPA's petition seeking rehearing as well as petitions filed by several other parties. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits: AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges. 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 August 13, 2002 Item 7. Financial Statements and Exhibits Item 9. Regulation FD Disclosure AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU No reports on Form 8-K were filed during the quarter ended September 30, 2002. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/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: November 13, 2002 CERTIFICATIONS I, E. Linn Draper, Jr., certify that: 1. I have reviewed this quarterly report on Form 10-Q of: 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 West Texas Utilities Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Dated: November 13, 2002 By: /s/ E. Linn Draper, Jr. ------------------------ E. Linn Draper, Jr. Chief Executive Officer I, Susan Tomasky, certify that: 1. I have reviewed this quarterly report on Form 10-Q of: 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 West Texas Utilities Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Dated: November 13, 2002 By: /s/ Susan Tomasky ------------------------ Susan Tomasky Chief Financial Officer

KENTUCKY POWER CO 10-Q