10-Q 1 xq301.txt COMBINED 10Q 09/30/01

AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company, Public Service Company of Oklahoma and West Texas Utilities Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at October 31, 2001 was 322,235,005.

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.

FORWARD-LOOKING INFORMATION This report made by AEP and certain of its subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: o Electric load and customer growth. o Abnormal weather conditions. o Available sources and costs of fuels. o Availability of generating capacity. o The speed and degree to which competition is introduced to our power generation business. o The structure and timing of a competitive market and its impact on energy prices or fixed rates. o The ability to recover stranded costs in connection with possible/proposed deregulation of generation. o New legislation and government regulations. o The ability of AEP to successfully control its costs. o The success of new business ventures. o International developments affecting AEP's foreign investments. o The economic climate and growth in AEP's service territory. o Inflationary trends. o Electricity and gas market prices. o Interest rates o Other risks and unforeseen events. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 Net income increased by $62 million or 20 cents per share for the quarter and by $430 million or $1.33 per share year-to-date. The results for the quarter reflect a favorable variance from an extraordinary loss from deregulation recorded in the third quarter of 2000 and an accounting change due to new accounting rules recorded in the third quarter of 2001. Income before extraordinary items and cumulative effect of the accounting change was unchanged for the quarter. In the year-to-date period income before extraordinary items and the cumulative effect of the accounting change increased by $425 million or $1.31 per share. The impact on comparative net income from the extraordinary items and the cumulative effect of the accounting change was $5 million favorable for the year-to-date period. Our wholesale business continued to perform well despite a slowing economy that reduced both wholesale energy margins and energy use by industrial customers. Our wholesale business, which includes generation, retail sales of power and wholesale power and gas marketing and trading and gas pipeline and storages services, continued to be a significant contributor to our earnings despite lower market prices and reduced volatility. Although our power marketing and trading operations had an adverse effect on the third quarter, our gas marketing and trading more than offset the decline in power trading. For the year-to-date period, earnings from both power and gas marketing and trading improved. Income statement line items which changed significantly were:

The increases in revenues were due to substantial increases in electric and gas trading volumes. Wholesale natural gas trading volume for the quarter was 1,337 billion cubic feet, a 265 percent increase from third-quarter 2000 volume of 366 billion cubic feet. Electric trading volume for the quarter increased 66 percent to 148 million MWH. The increase in gas trading volume is from: o continued expansion of our trading team o HPL acquisition on June 1, 2001 o expansion into new markets The increase in electric trading volume is primarily from: o continued expansion of our trading team o increased liquidity in markets While trading and marketing volumes rose, sales to industrial customers decreased and, in the third quarter, sales to wholesale customers also declined. We also experienced lower wholesale prices. The slowing economy has reduced demand and wholesale prices. Our fuel and purchased power expense increased due to increased trading volume, particularly gas, and an increase in nuclear generation. Cook Plant's two nuclear generating units were out of service in 2000 through June 2000 and December 2000. Maintenance and other operation expense declined in the third quarter due to the return to service of the Cook Nuclear units in 2000. Partially offsetting this decrease were accruals for severance related to corporate restructuring. In the year-to-date period, additional traders' incentive compensation, costs associated with the construction of gas-fired plants for non-affiliates and the accruals for severance costs caused maintenance and other operation expense to rise. The increase was offset, in part, by not incurring restart costs for the Cook Plant. Revenues from project fees more than offset the charges for third party construction. The write-off of deferred merger costs in 2000 included transaction and transition costs not recoverable from ratepayers under regulatory commission approved settlement agreements. The completion in March 2001 of the sale of Frontera, one of the generating plants required to be divested under FERC - approved merger settlement agreements, produced a $73 million gain recorded in other income for the year-to-date period. Lower average outstanding short-term debt balances and a decrease in average short-term interest rates accounted for the reduction in interest and preferred dividends. An increase in pre-tax income caused the increase in income taxes. In the second quarter of 2001 we recorded an extraordinary loss of $48 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation (see Note 2). The application of regulatory accounting for generation was discontinued in 2000 which resulted in after tax extraordinary items of: o a $9 million gain in June of 2000 for the Virginia and West Virginia jurisdictions and o $44 million loss in September of 2000 for the Ohio jurisdiction New accounting rules that became effective July 1, 2001 required us to mark to market certain fuel supply contracts that qualify as financial derivatives. The effect of initially adopting the new rules at July 1, 2001 was $18 million, net of tax, which is reported as a cumulative effect of accounting change on the income statement.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $469 million and $685 million and for income taxes was $208 million and $242 million in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $39 million and $79 million in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.

AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 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. The increase in net income of $0.1 million or 4% for the quarter resulted primarily from an increase in capital on which a return is earned. Net income for the year-to-date period was virtually unchanged. Income statement line items which changed significantly were:

The increase in operating revenues resulted primarily from an increase in recoverable expenses especially fuel and other operation expense. Recoverable expenses rose as Rockport Plant generation increased in 2001 compared with last year when the plant underwent scheduled maintenance outages in the third quarter of 2000. Fuel expense increased due to an increase in generation reflecting the length of outages in the third quarter 2000. The increase in other operation expense resulted from increased employee benefits, insurance and regulatory commission costs. Maintenance expense declined due to more extensive outages during the third quarter 2000 for boiler maintenance and repair. The decline in taxes other than federal income taxes for the quarter resulted from a decrease in an accrual for state taxes as a result of a revised taxable income estimate. Taxes other than federal income taxes for the year-to-date period increased due to the accrual of state income taxes based on an estimate of higher taxable income for 2001. Reductions in variable interest rates, reflecting market conditions, and lower average short-term borrowing balances outstanding produced the decrease in interest charges.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of the generation, regulated retail power sales and wholesale power marketing and trading; and energy delivery which consists of transmission and distribution services. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Net income decreased $5.8 million or 16% for the quarter due to a decline in wholesale business performance as a slowing economy reduced demand and lowered wholesale electricity prices. Net income increased $5.6 million or 5% for the year-to-date period primarily due to growth in and strong performance by the wholesale business during the first half of 2001. Income statement line items which changed significantly were:

The significant increase in revenues for the quarter is due to a 69% increase in trading volume partially offset by lower wholesale electricity prices of our wholesale business. The significant year-to-date period increase is due to a 44% increase in trading volume and an increase in wholesale electricity prices due to changes in market conditions. Expansion of the wholesale business' trading operation and greater liquidity in the market place resulted in an increase in the number of forward electricity purchase and sales contracts in AEP's traditional marketing area (up to two transmission systems from AEP's service territory). Fuel expense of the wholesale business increased for the quarter due to a decrease in deferred fuel expense as compared to the previous quarter. The decrease in deferred fuel expense is due to a lower average unit cost of fuel. Fuel expense decreased for the year-to-date period due to a decline in generation as a result of scheduled plant maintenance. For the quarter the increase in the wholesale business' purchased power expense is attributable to an increase in trading volume partly offset by a decrease in wholesale electricity prices. For the year-to-date period the increase is attributable to increases in trading volume and wholesale electricity prices. For the quarter other operation expense increased as a result of energy delivery severance accruals and power trading incentive compensation expense of the wholesale business. Year-to-date other operation expense increased due to wholesale power trading incentive compensation expense. The increase in maintenance expense is mainly attributable to increased generating plant boiler maintenance repairs to the wholesale business' Amos, Glen Lyn and Mountaineer Plants. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net generation-related regulatory assets were transferred to the energy delivery business' regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these assets through regulated rates. Depreciation and amortization expense increased due to the accelerated amortization beginning in July 2000 of the transition regulatory assets. Additional investments in the energy delivery business' distribution and transmission plant also contributed to the increase in depreciation and amortization expense. The decrease in federal income taxes for the quarter is due to a decrease in pre-tax operating income. Nonoperating income decreased for the quarter due to a net loss from the wholesale business' trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures, swaps). Due to significant net gains in the first six months of 2001 on these wholesale trading transactions, nonoperating income increased in the year-to-date period. The interest charge decrease is due to the retirement of first mortgage bonds in 2000.

CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, retail electricity sales, power marketing and trading of electricity; and energy delivery, which consists of transmission and distribution services. Since the merger of AEP and CSW in June 2000, we participate in the AEP System's power marketing and trading activities. Third quarter net income decreased $6 million or 7% while year-to-date net income increased $6 million or 3%. The lower third quarter net income was due to weak performance from marketing and trading. Year-to-date net income increased primarily from our participation in AEP's power marketing and trading operations during the first half of 2001 compared with 2000 when we did not share in AEP's power marketing and trading.

The significant increase in revenues for the quarter resulted from increased trading volumes of the wholesale business. In the year-to-date period, the increase in revenues is also attributable to our participation in AEP's power marketing and trading operations and higher fuel related revenues due to increased costs of fuel and purchased power. Fuel expense decreased for the quarter primarily due to a significant decrease in the average unit cost of fuel as a result of lower spot market natural gas prices. Year-to-date fuel expense was up due primarily to an increase in the average unit cost of fuel as a result of higher spot market natural gas prices in the first and second quarters. The substantial rise in purchased power expense for both the quarter and year-to-date periods was attributable to our participation in AEP's power marketing and trading operation. Other operation expense for the quarter decreased due primarily to a decrease in transmission expenses. Additionally, production expenses were down due to decreased power trading incentive compensation expense. Maintenance for the quarter increased due to the preparatory expenses for an October STP Unit 1 nuclear refueling outage. A nuclear refueling outage for STP Unit 2 between March 7 and April 2, 2001 also contributed to the increase in year-to-date maintenance expense. STP Unit 1 completed its refueling outage and returned to service October 25, 2001. The decrease in depreciation and amortization expense for the quarter is due primarily to lower excess earnings provisions under Texas Restructuring Legislation. Year-to-date depreciation and amortization expense also decreased due to accelerated ECOM depreciation on STP ceasing in July 2000. Taxes other than federal income taxes increased due primarily to an increase in franchise related taxes, including a settlement of disputed franchise fees (see Note 8), and Texas assessment taxes, a new tax levied by the PUCT. Federal income taxes attributable to operations decreased for the quarter and increased for the year-to-date period due to a decrease and increase, respectively, in pre-tax operating income. Nonoperating income for the quarter increased due to interest income on underrecovered fuel costs and was partially offset by a decrease in interest income on the Decommissioning Trust Fund.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of the generation, marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Net income increased $25 million or 62% in the third quarter of 2001 due to the effect of a prior period $25 million extraordinary loss. Income before extraordinary item for the third quarter of 2001 was flat. Net income increased $21 million or 20% and income before extraordinary item increased $22 million or 17% for the year-to-date period, due to the strength and growth of the wholesale business during the first half of 2001. Income statement line items which changed significantly were:

The significant increase in revenues for the quarter is due to an 86% increase in trading volume partially offset by lower wholesale electricity prices. The significant year-to-date increase is due to a 41% increase in wholesale trading volume and an increase in wholesale electricity prices due to changes in market conditions. Expansion of the wholesale business' trading operation and greater liquidity in the market place resulted in an increase in the number of forward electricity purchase and sales contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory). Fuel expense of the wholesale business decreased due to a decrease in net generation partially offset by an increase in the average unit price of fuel and the discontinuance of deferred fuel accounting effective January 1, 2001 because of deregulation. In 2000 fuel expense included charges for the amortization of previously deferred fuel costs. The amortization was concurrent with recovery through fuel clause revenues. For the quarter the increase in the wholesale business' purchased power expense is attributable to an increase in trading volume offset by a decrease in wholesale electricity prices. For the year-to-date period the increase was attributable to increases in trading volume and wholesale electricity prices Other operation expense increased year-to-date due to increases in uncollectible accounts, factored customer accounts receivable expenses, the effect of gains in 2000 from the disposition of emission allowances, higher power trading expenses and trading incentive compensation and energy delivery severance accruals. For the quarter, maintenance expenses decreased due to boiler overhauls and maintenance of overhead energy delivery lines completed in the prior period. The commencement of the amortization of transition regulatory assets in connection with the transition to customer choice and market-based pricing of electricity under Ohio deregulation accounted for the increase in depreciation and amortization expense. The increase in taxes other than income taxes is due to a new state excise tax which produces a larger tax than the gross receipts tax it replaced. The increase in nonoperating income was due to an increase in net gains from the wholesale business' trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures and swaps). In the second quarter of 2001 we recorded an extraordinary loss of $26 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation (see Note 2). The application of regulatory accounting for generation was discontinued in September 2000 which resulted in an after tax extraordinary loss of $25 million.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, regulated retail power sales and wholesale power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Net income increased $10 million in the quarter and $145 million in the year-to-date period primarily due to the return to service of both of I&M's Cook Plant nuclear units in June and December 2000. Income statement line items which changed significantly were:

Operating revenues for the third quarter increased due to increased wholesale sales while average wholesale prices declined. The significant increase in operating revenues in the year-to-date period resulted from increased wholesale volumes and prices. I&M's share of the AEP System's sales to and forward trades with other utility systems and power marketers and sales to the AEP Power Pool rose in 2001. The number of forward electricity contracts made in AEP System's traditional marketing area (up to two transmission systems from the AEP System's service territory) grew due to the expansion of our trading operation and increased liquidity in the markets. Changes in wholesale prices reflect market conditions. With the return to service of the nuclear units in 2000, I&M's available generation increased resulting in additional wholesale power sales to the AEP Power Pool in 2001. Fuel expense increased primarily due to increased generation reflecting the return to service of the nuclear units following the extended outage. The increase in purchased power expense resulted mainly from increases in wholesale prices and sales and trading volume in the year-to-date period. During the third quarter, a decline in average prices, reflecting market conditions, partly offset the volume increase. Other operation and maintenance expenses decreased primarily due to the cessation of expenses related to work for the 2000 restart of the Cook Plant units. The increase in depreciation and amortization charges reflects increased generation and distribution plant investments and amortization of deferred merger costs. Taxes other than federal income taxes and federal income tax expense attributable to operations increased primarily due to increases in pre-tax operating income. The increase in nonoperating income reflects an increase in net gains from trading transactions outside the AEP System's traditional marketing area and speculative financial transactions (options, futures and swaps). Interest charges increased due to lower amounts of interest being capitalized as part of plant construction costs.

KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale, which consists of generation, regulated retail power sales and wholesale power marketing and trading of electricity; and energy delivery, which consists of transmission and distribution services. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Net income decreased $1.4 million or 21% for the quarter and $2.1 million or 12% year-to-date due to a decline in operating income. This decline was primarily attributable to a slowing economy and reduced wholesale energy margins. Income statement line items which changed significantly were:

Increases in operating revenues are a result of increases in power trading activity. Revenues from sales to and forward trades with other utility systems and power marketers rose by 50% and 69% for the quarter and year-to-date periods, respectively. The number of forward electricity contracts grew due to the expansion of trading operations and increased liquidity in the markets. A downward trend in wholesale prices reflected market conditions. Fuel expense decreased as a result of credits from profits on trading power. Under the Kentucky commission's fuel clause mechanism, a portion of the profits on wholesale transactions are shared with the customers. This sharing is recognized through credits to fuel expense thus reducing overall fuel expense. Purchased power expense for the wholesale business increased due to additional purchases to support the increased sales and trading volume. Increases in other operation expense for the quarter were a result of increased trading incentive compensation expense and charges related to severance pay for distribution employees. Increases in year-to-date other operation expense are primarily attributable to trader compensation expenses and decreases in AEP transmission equalization credits. Under the AEP East Region Transmission Agreement, KPCo and certain affiliates share the costs associated with the ownership of their transmission system based upon each company's peak demand and investment. An increase in KPCo's peak demand relative to its affiliates' peak demand was the main reason for the decline in the transmission equalization credits. Other changes contributing to increases in other operation expense include an increase in medical insurance rates, and increases in accounts receivable factoring costs stemming from nine months activity in 2001 versus three months in 2000 when the program was implemented. Lower maintenance expense is a result of significant planned maintenance outages incurred at the Big Sandy Plant in year 2000 for which there is no comparable activity in the current year. Depreciation and amortization expense increased as a result of additions to property, plant and equipment and the resultant increase in the depreciable basis. Federal income tax on operations decreased due to a decline in pre-tax income. The quarter to date decrease in nonoperating income was due to losses resulting from power trading activity. The quarterly decrease is mitigated by year-to-date net gains for trading activity and other non-regulated financial market investments. Interest charges declined due to lower outstanding debt balances and lower interest rates in 2001.

OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of the generation, marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Net income decreased $7 million or 12% for the third quarter of 2001 and $47 million or 29% for the year-to-date period. We recorded extraordinary losses in the second quarter of 2001 and third quarter of 2000 for the effects of deregulation. Income before extraordinary item decreased by $26 million or 33% for the quarter and $45 million or 25% in the year-to-date period. A decline in wholesale business performance and the implementation of customer choice account for the reduction in the quarter's earnings. In connection with the start of customer choice on January 1, 2001, the generation portion of residential rates was reduced by 5% and the amortization of transition regulatory assets began. Although performance of our wholesale business is up for the year-to-date period, the implementation of customer choice caused earnings to decline year-to-date. Income statement line items which changed significantly were:

The significant increase in revenues for the quarter is due to a 63% increase in trading volume partially offset by lower wholesale electricity prices. The significant year-to-date revenue increase is due to a 31% increase in trading volume and an increase in wholesale electricity prices due to changes in market conditions. Expansion of the wholesale business' trading operation and greater liquidity in the marketplace resulted in an increase in the number of forward electricity purchase and sales contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory). Fuel expense decreased during both periods due to decreased generation and a lower average unit cost of fuel. For the quarter the increase in purchased power expense was attributable to the increase in the wholesale business' electric trading volume offset in part by a decrease in wholesale electricity prices. For the year-to-date period the increase is attributable to increase in trading volume and wholesale electricity prices. Other operation expense increased due to increases in uncollectible accounts and factored customer accounts receivable expenses of both the wholesale business and energy delivery business, the effect of gains in 2000 from the disposition of emission allowances, increased trading incentive compensation of the wholesale business and energy delivery severance accruals. Maintenance expenses increased due to boiler overhauls at Kammer, Mitchell, Muskingum and Sporn plants and boiler inspections at Amos and Cardinal plants. The commencement of amortization of transition regulatory assets in connection with the transition to customer choice and market-based pricing of electricity under Ohio deregulation accounted for the increase in depreciation and amortization expense. The increase in taxes other than federal income taxes is due to a new State Excise Tax which produced a larger tax than the gross receipts tax it replaced. Federal income taxes attributable to operations decreased due to a decrease in pre-tax operating income. The increase in nonoperating income was due to an increase in net gains from the wholesale business' trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures and swaps). Interest expense increased due to increased long-term debt outstanding. In the second quarter of 2001 we recorded an extraordinary loss of $22 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation (see Note 2). The application of regulatory accounting for generation was discontinued in September 2000 which resulted in an after tax extraordinary loss of $19 million.

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, retail electricity sales, power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW in June 2000, we participate in the AEP System's power marketing and trading activities. Net income decreased $3.3 million or 6% in the third quarter and $8.8 million or 12% in the first nine months of 2001 due primarily from last year's inclusion of a gain on the sale of a minority interest in Scientech, Inc. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $355 64 $739 80 Fuel Expense (1) (1) 109 36 Purchased Power Expense 351 144 614 208 Other Operation Expense 1 2 17 21 Maintenance 3 36 4 12 Federal Income Taxes (3) (9) (7) (20) Nonoperating Income (7) (97) (7) (89) The significant increase in revenues for the quarter resulted from increased trading volumes of the wholesale business. In the year-to-date period, the increase in revenues is primarily attributable to our participation in AEP's power marketing and trading operations. Revenues for the year-to-date period also increased as a result of an adjustment in 2000 under a FERC-approved Transmission Coordination Agreement, which decreased revenues and other operation expenses in 2000. The Transmission Coordination Agreement provides the means by which the AEP West electric operating companies plan, operate and maintain their four separate transmission systems as a single unit. The agreement also established the method by which these companies allocate revenues and costs received under open access transmission tariffs. Fuel expense increased year-to-date due primarily to a rise in the average unit fuel cost reflecting an increase in natural gas prices. The increase in purchased power expense was primarily attributable to our participation in the AEP System's power marketing and trading activities. Year-to-date other operation expenses increased due mainly to a favorable adjustment in 2000 under the FERC-approved Transmission Coordination Agreement mentioned above, along with increased incentive compensation for power trading and transmission expenses. Maintenance expense increased year-to-date due to scheduled power plant maintenance and additional expenses related to a January ice storm. Maintenance for the quarter increased due to scheduled power plant maintenance. Federal income tax expense associated with operations decreased as a result of a decline in pre-tax book income. The decrease in nonoperating income primarily resulted from last year's inclusion of a gain on the sale of a minority interest in Scientech, Inc.

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, retail electricity sales, power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW in June 2000, we participate in the AEP System's power marketing and trading activities. Net income increased $10 million, or 14%, for the year-to-date period despite a decrease in the quarter of $1 million, or 2%. The increase for the year-to-date period resulted from the favorable impact of our participation in AEP's power marketing and trading operations. Income statement line items which changed significantly were:

The significant increase in operating revenues and purchased power expense for the quarter resulted from increased trading volumes of the wholesale business. In the year-to-date period, the increase in revenues and purchased power expense is also attributable to our participation in AEP's power marketing and trading operations. Fuel expense of the wholesale business decreased for the quarter due primarily to a decrease in the average unit cost of fuel as a result of lower spot market natural gas prices. Due to the acquisition of Dolet Hills mining operation in June 2001, other operation expense increased for the quarter and year-to-date periods. Although tree-trimming expenses increased in the third quarter of 2001, they were slightly lower for the year-to-date period. Repairs to overhead lines because of severe ice storms in the first quarter of 2001 made maintenance expense increase for the year-to-date period. Depreciation and amortization expense increased year-to-date due primarily to an increase in excess earnings accruals under the Texas restructuring legislation and the acquisition of Dolet Hills mining operation. Taxes other than federal income taxes increased during the quarter due to increased state income taxes reflecting higher state taxable income. Taxes other than federal income taxes increased year-to-date due to a favorable adjustment of ad valorem taxes recorded in 2000 and increased state taxable income. The increase in federal income tax expense attributable to operations was primarily due to an increase in pre-tax operating income.

WEST TEXAS UTILITIES COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 2001 vs. THIRD QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, retail electricity sales, power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW in June 2000, we participate in the AEP System's power marketing and trading activities. Net income for the third quarter increased $3.4 million, or 32%, due to increases in operating and nonoperating income. Year-to-date net income decreased $1.5 million, or 7%, as the result of a decrease in operating income offset by an increase in nonoperating income. Nonoperating income increased in both periods as the result of loss provisions that were recorded in the second and third quarters of 2000 for the termination of merchandise sales and the cost of phasing out of the merchandising sales programs. Income statement line item which changed significantly were:

The significant increase in revenues for the quarter resulted from increased trading volumes of the wholesale business. In the year-to-date period, the increase in revenues is primarily attributable to our participation in AEP's power marketing and trading operations and higher fuel related revenues due to increased fuel and purchased power expense of the wholesale business. Fuel expense decreased for the quarter and increased in the year-to-date period. The fluctuation in spot market natural gas prices resulted in a decrease for the quarter and an increase in the year-to-date period. The increase in purchased power expense was primarily attributable to our participation in AEP's power marketing and trading operation and the adverse impact of natural gas prices on wholesale purchased power prices. Other operation expense decreased for the quarter due primarily to decreased transmission expenses. Other operation expense increased year-to-date due to a favorable adjustment made in January 2000 related to a FERC-approved Transmission Coordination Agreement. Maintenance expense increased due to the overhaul in 2001 of the Oklaunion Power Plant of our wholesale business. Depreciation and amortization expense decreased due to the effect of recording additional accruals in the third quarter of 2000 for estimated excess earnings as required by Texas Restructuring Legislation. An increase in taxes other than federal income taxes resulted from an increase in Texas franchise tax assessments and an increase in the Texas PUCT benefit assessment tax, a new tax in the state of Texas. Federal income taxes attributable to operations increased in the quarter and decreased year-to-date, reflecting the fluctuations in pre-tax income in those periods. The increase in nonoperating income was due to a loss provision that was recorded in the second and third quarters of 2000 for the termination of merchandise sales and the cost of phasing out of the merchandising sales programs.

1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 2000 Annual Report as incorporated in and filed with the Form 10-K. The AEP System operating companies have reclassified certain settled forward energy transactions of their trading operation from a net to a gross basis of presentation in order to better reflect the scope and nature of the AEP System's energy sales and purchases. All financially net settled trading transactions, such as swaps, futures, and unexercised options, continue to be reported on a net basis, reflecting the financial nature of these transactions. The following prior year amounts were reclassified from revenues to purchased power expense to present the prior period on a comparable basis: Three Months Ended Nine Months Ended September 30, 2000 September 30, 2000 Company (in thousands) ------- AEP $7,692,103 $15,756,630 APCo 1,063,249 2,660,105 CPL 194,425 194,425 CSPCo 574,254 1,506,671 I&M 637,437 1,651,035 KPCo 252,596 631,748 OPCo 901,960 2,300,395 PSO 196,527 196,527 SWEPCo 196,449 196,449 WTU 48,139 48,139 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. EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE OPCo and CSPCo Recognize Extraordinary Loss from the Stranding of Ohio Gross Receipts Tax OPCo and CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal credits during the quarter ended June 30, 2001. This loss resulted from regulatory decisions in connection with Ohio deregulation which stranded the recovery of the GRT. The components of the extraordinary loss by company were: CSPCo OPCo Total ----- ---- ----- (in thousands) Gross Receipts Tax $42,493 $50,461 $92,954 Less Coal Credits 7,733 17,361 25,094 ------- ------- ------- Net Liability for Ohio Gross Receipts Tax 34,760 33,100 67,860 Less Income Tax Benefit 8,353 11,585 19,938 ------- ------- ------- Extraordinary Loss $26,407 $21,515 $47,922 ======= ======= ======= As discussed in Note 7 of the 2000 Annual Report, CSPCo and OPCo appealed to the Ohio Supreme Court a PUCO order on Ohio restructuring that the companies believe failed to provide for recovery for the final year of the GRT. Effective May 1, 2001, the PUCO order reduced the companies' rates by the annual level of GRT. Effective with the liability affixing on May 1, 2001, the PUCO's decision to deny recovery in the final year of the GRT resulted, under SFAS 101, in an extraordinary impairment of the prepaid asset due to the deregulation of the companies' generation business. CSPCo and OPCo continue to seek recovery at the Ohio Supreme Court where a decision is expected in 2002. Cumulative Effect of Accounting Change - Affecting AEP Guidance for certain fuel supply contracts with volume optionality and electricity capacity contracts issued by the FASB's Derivative Implementation Group (DIG) regarding the implementation of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" became effective in the third quarter of 2001. The guidance concluded that fuel supply contracts with volumetric optionality cannot qualify for a normal purchase or sale exclusion from mark-to-market accounting and provided guidance for determining when electricity capacity contracts can qualify as a normal purchase or sale. Predominantly all of AEP's contracts for coal, gas and electricity, which are recorded on a settlement basis, do not meet the criteria of a financial derivative instrument, qualify as a normal purchase or sale, and are thereby exempt from the DIG guidance described above. Beginning July 1, 2001, the effective date of the DIG guidance, certain of AEP's fuel supply contracts with volumetric optionality that qualify as financial derivative instruments are marked to market with any gain or loss recognized in the income statement. The effect of initially adopting the DIG guidance at July 1, 2001, a favorable earnings mark-to-market effect of $18 million, net of tax, is reported as a cumulative effect of an accounting change on the income statement. 3. ACQUISITIONS AND SALES OF ASSETS Sale of Generating Assets - Affecting AEP As discussed in Note 3 of the 2000 Annual Report, the divestiture of 1,904 MW of generating capacity was required by the FERC and the PUCT as part of the approval of the merger. In March 2001 AEP completed the sale of Frontera, one of the generating plants required to be divested under the settlement agreements approved by the FERC. The sale proceeds were $265 million and resulted in an after tax gain of $46 million. Acquisition of Houston Pipe Line Company - Affecting AEP On June 1, 2001, AEP, through a wholly owned subsidiary, purchased Houston Pipe Line Company and Lodisco LLC for $727 million. The acquired assets include 4,200 miles of gas pipeline, a 30-year sublease of a gas storage facility and certain gas marketing contracts. The purchase method of accounting was used to record the acquisition. AEP recorded the assets acquired and liabilities assumed based upon their estimated fair values. The allocation of the purchase price may be adjusted based upon completion of the appraisal process. The purchase method results in the assets and earnings of the acquired operations being included in AEP's consolidated financial statements from the purchase date. Acquisition of Lignite Mining Operations - Affecting AEP and SWEPCo On June 1, 2001, SWEPCo assumed mining operations at its jointly owned lignite reserves in Louisiana. To settle litigation, which is discussed in Note 8, SWEPCo paid $86 million to purchase the mining assets and rights of the previous mine operator and assumed existing mine reclamation liabilities. The lignite from the mine will continue to supply SWEPCo's jointly owned power plant. Management expects the acquisition to have minimal impact on results of operations. Sale of Generating Assets - Affecting AEP In July 2001 AEP, through a wholly owned subsidiary, sold its 50% interest in a 120-megawatt generating plant located in Mexico. The sale resulted in a third quarter after tax gain of approximately $11 million. Sale of Coal Mines - Affecting AEP and OPCo In July 2001 AEP and OPCo sold coal mines in Ohio and West Virginia and agreed to purchase approximately 34 million tons of coal from the purchaser of the mines through 2008. The sale had a nominal impact on results of operations. Acquisition of Coal Assets - Affecting AEP In October 2001 AEP acquired substantially all the assets of Quaker Coal Company as part of a bankruptcy proceeding settlement. AEP paid $101 million to Quaker's creditors and assumed additional liabilities of approximately $45 million. The acquisition includes property, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. AEP will continue to operate the mines and facilities which employ over 800 individuals. The purchase method of accounting was used to record the acquisition. AEP recorded the assets acquired and liabilities assumed based upon their estimated fair values. The allocation of the purchase price may be adjusted based upon completion of an appraisal process. The purchase method results in the assets and earnings of the acquired operations being included in AEP's consolidated financial statements from the purchase date. Acquisition of Barge Line - Affecting AEP On November 1, 2001, AEP, through a wholly owned subsidiary, acquired MEMCO Barge Line. The $270 million acquisition adds 1200 hopper barges and 30 towboats to AEP's existing barging fleet. MEMCO's 450 employees will continue to operate the barge line. The purchase method of accounting was used to record the acquisition. AEP recorded the assets acquired and liabilities assumed based upon their estimated fair values. The allocation of the purchase price may be adjusted based upon completion of an appraisal process. The purchase method results in the assets and earnings of the acquired operations being included in AEP's consolidated financial statements from the purchase date. 4. RATE MATTERS Texas Fuel Costs - Affecting AEP, CPL, SWEPCo and WTU As discussed in Note 5 of the 2000 Annual Report, AEP's Texas electric operating companies experienced natural gas fuel price increases which resulted in under-recoveries of fuel costs. Fuel recovery for Texas utilities is a multi-step procedure. When fuel costs change, utilities file with the PUCT for authority to adjust fuel factors. If a utility's prior fuel factors result in an over- or under-recovery of fuel, the utility will also request a surcharge factor to refund or collect that amount. While fuel factors are intended to recover all fuel-related costs, final settlement of these accounts are subject to reconciliation and approval by the PUCT. Fuel reconciliation proceedings determine whether fuel costs incurred and collected during the reconciliation period were reasonable and necessary. All fuel costs incurred since the prior reconciliation date are subject to PUCT review and approval. If material amounts are determined to be unreasonable and ordered to be refunded to customers, results of operations and cash flows would be negatively impacted. According to Texas Restructuring Legislation, fuel cost in the Texas jurisdiction after 2001 will no longer be subject to PUCT review and reconciliation. During 2002 CPL will file a final fuel reconciliation with the PUCT to reconcile its fuel costs through the period ending December 31, 2001. The ultimate recovery of deferred fuel balances at December 31, 2001 will be decided as part of CPL's 2004 true-up proceeding. If the final under-recovered fuel balances or any amounts incurred but not yet reconciled are disallowed, it would have a negative impact on results of operations. In October 2001 the PUCT delayed the start of customer choice in the SPP area of Texas. Portions of SWEPCo's and WTU's service territories are in the SPP. The effect of the delay on fuel recovery is being reviewed by the PUCT and management. The PUCT has not announced how the delay will be applied to WTU whose customers are in SPP and ERCOT. The following table lists the status of Texas jurisdictional reconciliation, total fuel cost subject to reconciliation, under-recovered fuel balances and the remaining fuel surcharge by company:

Under Texas restructuring, newly organized retail electric providers will make sales to consumers beginning in January 1, 2002. These sales will be at fixed rates during a transition period from 2002 through 2006. However, the fuel cost component of a retail electric providers' fixed rates will be subject to prospective adjustment twice a year based upon changes in a natural gas price index. As part of the preparation for customer choice, CPL, SWEPCo and WTU filed their proposed fuel factors to be implemented as part of the fixed rates effective January 1, 2002. The filings are pending at the PUCT. Status of Rate Filings Central Power and Light In January 2001 CPL filed an application with the PUCT to implement a $175.9 million increase in fuel factors over the ten months March 2001 through December 2001. In addition, to collect its under-recovered fuel costs, CPL proposed to implement an interim fuel surcharge of $51.8 million, which includes accumulated interest on unrecovered amounts. The PUCT approved in April 2001 the implementation of a $170.5 million increase in fixed fuel factors. The PUCT voted to defer implementation of the requested fuel surcharge until the final fuel reconciliation, which occurs as part of the 2004 true-up proceeding. Southwestern Electric Power Company In November 2000 SWEPCo filed with the PUCT to increase its fuel factors effective January 2001 and to collect previously under-recovered fuel costs over a six-month period through a proposed interim fuel surcharge, which includes accumulated interest on previous unrecovered fuel costs. The PUCT approved an increase in SWEPCo's fuel factors of $12 million and the implementation of a fuel surcharge of $11.8 million from February to July 2001. In May 2001 SWEPCo filed an application to increase its fuel factors by $4.3 million. The application also proposed a fuel surcharge of $18.3 million, which includes accumulated interest on previous unrecovered fuel costs. The PUCT approved in August 2001 a unanimous stipulation, requiring SWEPCo to withdraw its fuel factors request and to implement a surcharge of $10.7 million for unrecovered fuel. The PUCT deferred the remaining $6.8 million balance of unrecovered fuel until a later proceeding. West Texas Utilities In April 2001 the PUCT approved new fuel factors for WTU to collect $43.4 million of increased fuel costs from March through December 2001. WTU implemented the increase in its fuel factors in March 2001 after an Administrative Law Judge approved a settlement of WTU's application. WTU's original application, in January 2001, had requested a $46.5 million increase in its fuel factors. In March 2001 WTU filed with the PUCT to implement a fuel surcharge for under-recovered fuel costs of $59.5 million including interest on previous unrecovered fuel costs. WTU requested that the surcharge be effective May 2001 through December 2001. In October 2001 the PUCT deferred consideration of WTU's fuel recovery until the 2004 true-up proceeding. Texas Transmission Rates - Affecting AEP, CPL and WTU On June 28, 2001, the Supreme Court of Texas ruled that the transmission pricing mechanism created by the PUCT in 1996 was invalid. The court upheld an appeal filed by unaffiliated Texas utilities that the PUCT exceeded its statutory authority to set such rates for the period January 1, 1997 through August 31, 1999. Effective September 1, 1999, the legislature granted this authority to the PUCT. CPL and WTU were not parties to the case. However, the companies' transmission sales and purchases were priced using the invalid rates. It is unclear what action the PUCT will take to respond to the court's ruling. If the PUCT changes rates retroactively, the result could have a material impact on results of operations and cash flows for CPL and WTU. 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. The companies are evaluating the order and its impact on results of operations and cash flows. Excess Earnings - Affecting AEP, CPL, SWEPCo and WTU In March 2001 CPL, SWEPCo and WTU filed their Annual Report of Excess Earnings for 2000 with the PUCT. In July 2001 the companies received notice that the Staff of the PUCT and the Office of Public Utility Counsel (OPC) disagreed with the reports as filed. The Staff and OPC took exception to certain adjustments made by the companies. OPC also took exception to the application of certain sections of the law as it pertains to the calculation of revenue within the report. The PUCT issued a final order in September 2001 and the companies recorded adjustments to match estimated provisions with final amounts. The companies requested a rehearing on the proper determination of excess earnings which the PUCT denied. In October 2001 the companies filed in district court seeking judicial review of the PUCT's determination of excess earnings. A decision from the court is not expected until 2002. 5. INDUSTRY RESTRUCTURING ---------------------- As discussed in the 2000 Annual Report, restructuring legislation has been enacted in seven of AEP's eleven state retail electric jurisdictions. The legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the generation of electricity. Ohio Restructuring - Affecting AEP, CSPCo and OPCo Effective January 1, 2001, customer choice of electricity supplier began under the Ohio Act. The PUCO approved alternative suppliers (many of whom remain inactive) to compete for CSPCo's and OPCo's customers. Virtually all customers continue to be served by CSPCo and OPCo. In accordance with the Ohio Act, CSPCo and OPCo implemented rate reductions of 5% for the generation portion of residential rates effective January 1, 2001. The generation portion of retail rates, including fuel, will remain frozen until December 31, 2005 or the PUCO determines that a competitive market exists. On January 16, 2001, Shell Energy Services Company filed a Notice of Appeal with the Ohio Supreme Court challenging PUCO's approval of our transition settlement agreement including recovery of regulatory assets. Shell withdrew as an alternative retail supplier for Ohio. The PUCO's motion to dismiss Shell's appeal is pending before the Ohio Supreme Court. Management is unable to predict the outcome of this litigation. The resolution of this matter could negatively impact future results of operations and cash flows. Virginia Restructuring - Affecting AEP and APCo In accordance with its restructuring law, the Virginia jurisdiction will begin a transition to choice of electricity supplier for retail customers on January 1, 2002. The Virginia restructuring law requires filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. APCo filed its separation plan and rate unbundling plan with the Virginia SCC. Hearings were held in October 2001. Settlement agreements that resolved most issues except the assignment of the generation - related regulatory assets among functionally separated generation and delivery organizations are pending before the Virginia SCC. Presently, capped rates are sufficient to recover generation - related regulatory assets. Management is unable to predict the outcome of the hearings. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999 Arkansas enacted legislation to restructure its electric utility industry. In February 2001 the Arkansas General Assembly passed legislation that was signed into law by the Governor to delay restructuring. The legislation extended the date for the start of retail electric competition to October 1, 2003 and provided the Arkansas Commission with the authority to delay that date for up to two additional years. Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU Texas Restructuring Legislation gives customers the opportunity to choose their electric provider and eliminates the fuel clause reconciliation process beginning January 1, 2002. A 2004 true-up proceeding will determine the amount of stranded costs including the final fuel recovery, net regulatory asset recovery, excess earnings offsets and other issues. As discussed in the 2000 Annual Report, the method used to determine initial stranded costs to be recovered beginning on January 1, 2002 is still subject to challenge. In March 2000 CPL submitted a $1.1 billion estimate of stranded costs. After hearings on the submission, the PUCT issued in February 2001 an interim decision determining an initial amount of stranded costs for CPL of negative $580 million. In April 2001 the PUCT ruled that its current estimate of CPL's stranded costs was negative $615 million. CPL disagrees with the ruling and has requested a rehearing. In April 2001 the PUCT issued an order requiring 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 reduce stranded costs. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. Currently the PUCT estimates that CPL will have no stranded costs and has ordered the rate reduction to return excess earnings. Management believes that CPL will have stranded costs in 2004, and that the current treatment of excess earnings will be amended at that time. Since CPL expensed excess earnings amounts in 1999, 2000 and 2001, the April order has no additional effect on reported net income. The amount to be refunded is recorded as a regulatory liability. As discussed in Note 7 of the 2000 Annual Report, the PUCT authorized the issuance of up to $797 million of bonds to securitize certain of CPL's regulatory assets. The PUCT's order that authorized the securization was appealed to the Supreme Court of Texas. On June 6, 2001, the Supreme Court upheld the PUCT's securitization order. The Court dismissed the plaintiffs' request for a rehearing. Management plans to issue the securitization bonds prior to January 1, 2002. On August 3, 2001, the Staff of the PUCT filed a Petition seeking a determination of whether electric operations in the SPP are ready for competition. This Petition affects parts of SWEPCo and WTU. Under the Texas Restructuring Legislation, the PUCT can delay the start of competition if the market and its participants are not prepared for competition. Under the law, certain situations indicate this lack of preparedness, and in Staff's opinion, those indicators are present for the SPP area. In October 2001 the PUCT ordered a delay in the start of retail competition in the SPP area of Texas and continued the pilot project in the SPP area. Management is evaluating the ramifications of this delay in the January 1, 2002 start date of competition for SWEPCo's and WTU's Texas operations in the SPP. A Texas settlement agreement in connection with the AEP and CSW merger permits CPL to apply up to $20 million of previously identified STP ECOM plant assets a year in 2000 and 2001 to reduce any excess earnings. STP ECOM plant assets will be depreciated in accordance with GAAP, on a systematic and rational basis. To the extent excess earnings exceed $20 million in 2001, CPL will establish a regulatory liability by a charge to earnings. In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding to recover their generation-related regulatory assets, unrecovered fuel balances, stranded costs and other restructuring related costs, it could result in an extraordinary loss which could have a material adverse effect on results of operations, cash flows and possibly financial condition. Michigan Restructuring - Affecting AEP and I&M As discussed in the 2000 Annual Report, the Michigan Legislation gave the MPSC broad powers to implement customer choice. In compliance with MPSC orders, on June 5, 2001, I&M filed its proposed unbundled rates, open access tariffs and terms of service. On October 11, 2001, the MPSC issued an "Order Approving Settlement Agreement" which generally approved I&M's June 5, 2001 filing except for agreed upon modifications. In accordance with the settlement agreement, I&M agreed that recovery of implementation costs and regulatory assets would be determined in future proceedings. The settlement agreement did not modify the procedure for review of decommissioning cost recoveries. Customer choice commences on January 1, 2002. Management does not expect that I&M will incur material tangible asset impairments or regulatory asset write-offs. If I&M is not permitted to recover all or a portion of its generation-related regulatory assets, unrecorded decommissioning obligation, stranded costs or other implementation costs in future proceedings, it could result in an extraordinary loss that could have a material adverse effect on results of operations, cash flows and possibly financial condition. Oklahoma Restructuring - Affecting AEP and PSO In June 2001 the Oklahoma Governor signed into law a bill that delayed retail electric competition indefinitely. Under previously approved legislation, the start date for Oklahoma customer choice had been July 1, 2002. 6. BUSINESS SEGMENTS AEP's three principal business segments and their respective activities are: o Wholesale o Generation of electricity for sale to retail and wholesale customers o Marketing and trading of electricity and gas worldwide, o Gas pipeline and storage services and other energy supply related businesses. o Energy Delivery o Domestic electric transmission, o Domestic electric distribution. o Other Investments o Foreign electricity generation investments, o Foreign electric distribution and supply investments, o Telecommunication services. Amounts reported below for the three business segments 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.

Management's intention is to structurally and functionally separate operations into regulated and non-regulated businesses. The vertically integrated generation-transmission-distribution operations of the utility companies in Ohio and Texas (CSPCo, OPCo, CPL and WTU) will be structurally separated into non-regulated wholesale and regulated energy delivery businesses. The remaining utility subsidiaries will to be grouped with AEP's regulated business. Management is currently in the process of obtaining the necessary regulatory approvals to implement this new business structure. 7. FINANCING ACTIVITIES AND MINORITY INTEREST Long-term debt and other securities issuances and retirements during the first nine months of 2001 were:

In addition to the transactions reported in the table above, the following table lists intercompany issuances of debt and retirements of debt due to AEP Co., Inc.

(a) In May 2001, AEP issued $1.25 billion of debt consisting of $1 billion of senior notes and $250 million of putable callable notes. The interest rate on senior notes (due May 2006) is 6.125%. Additionally, AEP entered into an interest rate swap for a portion of the proceeds, which effectively converts a portion of this interest rate into LIBOR based floating rate through 2006. The putable callable notes (Series B notes) have a fixed interest rate of 5.5% until May 2003. At that date the Series B notes may be subject to call by a third party for purchase and remarketing, in which case the maturity would extend until may 2013. If the Series B notes are not called for remarketing, they will be redeemed. (b) A floating interest rate is determined quarterly. The rate on September 30, 2001 was 3.29%. (c) A floating interest rate is determined quarterly. The rate on September 30, 2001 was 3.265%. Other Financing Activities On May 24, 2001, AEP renewed its existing $2.5 billion 364-day revolving credit facility. AEP renews this facility annually and uses it, together with an existing $1 billion 5-year revolving credit which matures May 30, 2005 as an alternative means of funding for AEP's commercial paper program. On May 30, 2001, AEP Credit ceased to issue commercial paper and allowed its $2 billion unsecured revolving credit facility to mature. A $1.5 billion 364-day note purchase agreement, which closed on May 30, 2001, replaced Credit's funding needs. Bank-sponsored financings are funding this facility. Minority Interest in Subsidiaries AEP's minority interests at September 30, 2001 and 2000 include the following: 2001 2000 ---- ---- (in millions) Funding Subsidiary $750 $ - Nanyang General Light Electric Co. 20 17 Other 3 3 ---- --- $773 $20 ==== === In August 2001 AEP formed a funding subsidiary as a limited liability company and sold a non-controlling, preferred interest in such limited liability company to a third party for $750 million. The preferred interest receives a preferred return equal to an adjusted floating reference rate. The $750 million received replaces interim funding used to acquire Houston Pipe Line Company in June 2001(see Note 3). The preferred interest is supported by pipeline assets and $325 million of a preferred stock interest in an AEP affiliate which is convertible, under certain circumstances, into $325 million of AEP common stock. AEP could elect not to have the transaction supported by the preferred stock of its affiliate if the preferred interest were reduced by $225 million. The results of operations, cash flows and financial position of the limited liability company are consolidated with AEP. The non-controlling preferred interest in the limited liability company is included on AEP's consolidated balance sheet line "Minority Interest in Subsidiaries." 8. CONTINGENCIES Litigation Shareholders' Litigation - Affecting AEP In 2000 five complaints were filed against AEP seeking unspecified compensatory damages for alleged violations of federal securities laws. A court order consolidated the cases. However, the court has not determined if the plaintiffs represent a class consisting of all persons and entities who acquired AEP common stock between July 25, 1997 and June 25, 1999. On March 5, 2001, AEP filed a motion to dismiss the cases. All parties presented oral arguments on AEP's motion to dismiss on June 7, 2001. Management believes these shareholder complaints are without merit and intends to continue to oppose them. The outcome of this litigation or its impact on results of operations, cash flows or financial condition cannot be predicted. Municipal Franchise Fee Litigation - Affecting AEP and CPL CPL has been involved in litigation regarding municipal franchise fees in Texas as a result of a class action suit filed by the City of San Juan, Texas in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and seeks damages of up to $300 million plus attorney's fees. CPL filed a counterclaim for overpayment of franchise fees. The litigation moved procedurally through the Texas Court System and was sent to mediation without resolution. CPL notified the other cities it serves of the pending class action suit. CPL has pledged to extend any final decision which determines an underpayment of franchise fees to cities who declined to participate in the suit. The court ruled that the class of plaintiffs would consist of approximately 30 cities and set a trial date. During the third quarter of 2001 the cities who declined to participate in the class action lawsuit reached an agreement with CPL to settle their claims. The agreement with approximately 95 cities requires CPL to pay a total of $8 million and releases CPL from any further liability. CPL recorded the liability in August 2001. In October 2001 CPL settled with the city of San Juan and the remaining class action cities for approximately $3 million. Management believes the court will approve the settlements and payments will be made before year-end. Texas Base Rate Litigation - Affecting AEP and CPL As discussed in the 2000 Annual Report, CPL has been involved in litigation concerning a 1997 PUCT base rate order. The primary issues were: o Classification of $800 million of invested capital at STP as excess cost over market (ECOM) earning a lower return than other generating property; and o Disallowance of $18 million of affiliated service billings. In October 2001 the Texas Supreme Court denied our request to review this case. At this time, management is reviewing its options which includes seeking a rehearing. Management is unable to predict the final resolution of this litigation or its impact on results of operations or cash flows. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo In May 2001 SWEPCo settled ongoing litigation concerning lignite mining in Louisiana. As discussed in Note 8 of the 2000 Annual Report, SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO are joint owners of Dolet Hills Power Station Unit 1 and own lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982 SWEPCo and CLECO entered into a lignite mining agreement with DHMV, a partnership for the mining and delivery of lignite from these reserves. Since 1997 SWEPCo and CLECO have been involved in litigation with DHMV and its partners. In 2000 the parties agreed to settle the litigation. As part of the settlement, SWEPCo purchased DHMV's interest in the mining assets and mining rights for $86 million and assumed the related obligations for mine reclamation (See Note 3). The settlement agreement gives CLECO the option to acquire up to a 50% interest in the mining assets. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo As discussed in the 2000 Annual Report, Federal EPA and a number of states alleged that AEP, APCo, CSPCo, I&M and OPCo modified certain generating units in violation of the Clean Air Act. The Federal EPA filed complaints against the companies in U.S. District Court for the Southern District of Ohio in 1999. 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 March 2001 the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief. In February 2001 the plaintiffs 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 Court denied the plaintiffs' 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. 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. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned with CSPCo, reached a tentative agreement to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing 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 rule (the NOx Rule) requiring substantial reductions in NOx emissions in a number of eastern states, including 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 requires states to submit plans to comply with its provisions. Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit approvable compliance plans. Those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. AEP and other utilities requested that the D.C. Circuit Court review this ruling. Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of AEP's coal-fired generating units. After review, the D.C. Circuit Court upheld the Section 126 Rule. The D.C. Circuit Court instructed Federal EPA to justify methods used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. On August 24, 2001, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. The Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including those owned by CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. In May 2001 selective catalytic reduction (SCR) technology to reduce NOx emissions on OPCo's Gavin Plant began operation. Construction of SCR technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant began in 2001. The Amos and Mountaineer projects (expected to be completed in 2002) are estimated to cost a total of $230 million ($145 million for APCo and $85 million for OPCo). Construction of SCR technology on KPCo's Big Sandy Plant Unit 2 is scheduled for completion in May 2003 at an estimated cost of $107 million. Preliminary estimates indicate that compliance for the AEP System with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures totaling approximately $1.6 billion. Estimated compliance costs by registrant subsidiaries are as follows: (in millions) AEGCo $125 APCo 365 CPL 57 CSPCo 106 I&M 202 KPCo 140 OPCo 606 SWEPCo 28 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the preliminary 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. Other AEP and its subsidiary registrants continue to be involved in certain other matters discussed in the 2000 Annual Report. REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS This is our combined presentation of management's discussion and analysis of financial condition, contingencies and other matters related to AEP and our subsidiary registrants. Management's discussion and analysis of results of operations for the three and nine month periods ended September 30, 2001 is presented with each registrants' financial statements elsewhere in this document. FINANCIAL CONDITION Cash from operations and short-term borrowings provide working capital and meet other short-term cash needs. We generally use short-term borrowings to fund property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include issuance of common stock, minority interest or long-term debt and sale-leaseback or leasing agreements. We operate a money pool and sell accounts receivables to provide liquidity for the domestic electric subsidiaries. Short-term borrowings are supported by a bank-sponsored note purchase agreement and two revolving credit agreements. At September 30, 2001, approximately $1.4 billion was available for short-term borrowings. To facilitate corporate separation, AEP issued $1.25 billion of global notes in May 2001 (with intermediate maturities). The proceeds may be loaned to certain subsidiaries, primarily in Ohio and Texas, to allow them to reacquire debt with covenants that limit asset transfer or sale. Corporate separation will require the transfer of assets between legal entities. During the first nine months of 2001 cash from operations of $1.2 billion, the proceeds of the $1.25 billion global notes issuance and proceeds from the sale of a UK distribution company and two generating plants provided cash to purchase HPL until permanent funding was arranged, fund construction, retire debt and pay dividends. Major construction expenditures included amounts for a wind generation plant and emission control technology on several coal-fired generating units (see discussion in Note 8). During the third quarter of 2001, HPL's permanent financing was completed by an issuance of a minority interest which provided $735 million net of expenses. HPL's permanent financing will increase funds available for other corporate purposes. During the fourth quarter, Quaker Coal Co. and MEMCO Barge Line, Inc. were acquired using short-term borrowings and available cash. In October 2001, we announced our intent to acquire two coal-fired generating plants in the UK. The transaction is expected to be completed by the end of the year. Long-term financing for these three acquisitions will be arranged and announced as completed. Long-term funding arrangements are often complex and can not be completed immediately. Total consolidated plant and property additions including capital leases for the year-to-date period were $1.3 billion. The following table shows the additions by certain subsidiary registrants: Company Amount ------- ------ (in millions) APCo $188 CPL 159 I&M 66 OPCo 244 SWEPCo 77 Corporate Separation On July 24, 2001, we filed an application with the FERC requesting approval of transactions necessary to complete a restructuring of our regulated and unregulated operations. These transactions will enable us to implement our plans for corporate separation and allow us to meet the requirements of Texas and Ohio restructuring legislation. As part of the filed plan, AEP intends to transfer the generation assets from the integrated electric operating companies in Ohio and Texas (CSPCo, OPCo, CPL and WTU) to unregulated generation companies. The filed plan also proposes amendments of the power pooling agreements for all operating companies. Only those operating companies that continue to exist as integrated utilities would be included in the amended power pooling agreements, which would govern energy exchanges among members and off system purchases and sales. In order to execute this separation, we may be required to retire various debt securities of CSPCo, OPCo, CPL and WTU. In September 2001 CSPCo reacquired $263 million first mortgage bonds and OPCo reacquired $97.5 million of first mortgage bonds in open market transactions. CSPCo and OPCo used funds borrowed from AEP to reacquire the bonds. First mortgage bond retirements will lower the amount of debt funded under mortgage indenture covenants. The lower mortgage debt should facilitate transfer of assets from one subsidiary to another. RTO Formation As discussed in Note 3 of the 2000 Annual Report, FERC Order No. 2000 and many of the settlement agreements with the state regulatory commissions to approve the AEP-CSW Merger required the transfer of control of our transmission system to an RTO. Certain AEP subsidiaries are participating in the formation of the Alliance RTO, other subsidiaries are member of ERCOT or the SPP. Subsidiaries who are members of the SPP are evaluating their options for RTO membership following the SPP's announcement of its intention to merge with the MISO. In 2001 the Alliance companies and MISO entered into a settlement addressing transmission pricing and other "seams" issues between the two RTOs. The FERC also has expressed its opinion that four large RTO regions serving the continental US will better support competition and reliability of electric service. FERC is re-evaluating the functions that should be exercised by RTOs, as expressed in Order No. 2000, and has formed federal/state panels to examine the issue. It has extended the December 15, 2001 deadline set forth in Order No. 2000 for RTOs to become operational, and has stated that it will substitute a new timeline. Certain state regulatory commissions have taken exception to the FERC's actions. Louisiana's commission ordered utilities it regulates, including SWEPCo, to file to show the advantage of large RTOs to their customers. Management is unable to predict the outcome of these activities and proceedings or their impact on the timing and operation of RTOs or our results of operations and cash flows. OTHER MATTERS Industry Restructuring As discussed in Note 5 and our 2000 Annual Report, seven of our eleven state retail jurisdictions enacted restructuring legislation. The legislation provides for a transition from cost-based regulation of bundled electric service to unbundled generation and energy delivery functions with customer choice and market pricing for the supply of electricity. Ohio Restructuring - Affecting AEP, CSPCo and OPCo Effective January 1, 2001, customer choice of electricity supplier began under the Ohio Act. The PUCO approved alternative suppliers (many of whom remain inactive) to compete for CSPCo's and OPCo's customers. CSPCo and OPCo continue to serve virtually all customers. In accordance with the Ohio Act, CSPCo and OPCo implemented rate reductions of 5% for the generation portion of residential rates effective January 1, 2001. Retail rates, including fuel, will remain frozen until December 31, 2005 or the PUCO determines that a competitive market exists. An alternative supplier (who has since withdrawn from Ohio competition) filed a Notice of Appeal with the Ohio Supreme Court challenging PUCO's approval of our transition settlement agreement including recovery of regulatory assets. A PUCO motion to dismiss this appeal is pending before the Ohio Supreme Court. Management is unable to predict the outcome of this litigation. The resolution of this matter could negatively impact our future results of operations and cash flows. Virginia Restructuring - Affecting AEP and APCo In accordance with its restructuring law, the Virginia jurisdiction will begin a transition to choice of electricity supplier for retail customers on January 1, 2002. The Virginia restructuring law requires filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. APCo filed its separation plan and rate unbundling plan with the Virginia SCC. Hearings were held in October 2001. Settlement agreements that resolved most issues except the assignment of the generation - related regulatory assets among functionally separated generation and delivery organizations are pending before the Virginia SCC. Presently, capped rates are sufficient to recover generation - related regulatory assets. We are unable to predict the outcome of the hearings. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999 Arkansas enacted legislation to restructure its electric utility industry. In 2001 legislation which extended the date for the start of retail electric competition to October 1, 2003 and provided the Arkansas Commission with the authority to delay that date for up to two additional years became law. Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU Texas Restructuring Legislation gives customers the opportunity to choose their electric provider and eliminates the fuel clause reconciliation process beginning January 1, 2002. A 2004 true-up proceeding will determine the amount of stranded costs including the final fuel recovery, net regulatory asset recovery, excess earnings offsets and other issues. As discussed in our 2000 Annual Report, the method used to determine initial stranded costs to be recovered beginning on January 1, 2002 is still subject to challenge. In March 2000 CPL submitted a $1.1 billion estimate of stranded costs. After hearings on the submission, the PUCT issued in February 2001 an interim decision determining an initial amount of stranded costs for CPL of negative $580 million. In April 2001 the PUCT ruled that its current estimate of CPL's stranded costs was negative $615 million. We disagree with the ruling and have requested a rehearing. In April 2001 the PUCT issued an order requiring CPL to reduce its distribution rates by $54.8 million for five-years beginning in January 2002 in order to return estimated excess earnings for 1999, 2000 and 2001. The Texas Restructuring Legislation intended that excess earnings reduce stranded costs. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. Currently the PUCT estimates that CPL will have no stranded costs and has ordered the rate reduction to return excess earnings. We believe that CPL will have stranded costs in 2004, and that the current treatment of excess earnings will be amended at that time. Since CPL expensed excess earnings amounts in 1999, 2000 and 2001, the April order had no additional effect on reported net income. The amount to be refunded is recorded as a regulatory liability. As discussed in Note 7 of our 2000 Annual Report, the PUCT authorized the issuance of up to $797 million of bonds to securitize certain of CPL's regulatory assets. The PUCT's order that authorized the securization was appealed to the Supreme Court of Texas. On June 6, 2001, the Supreme Court upheld the PUCT's securitization order. The Court dismissed the plaintiffs' request for a rehearing. We plan to issue the securitization bonds in the near term. In October 2001, the PUCT delayed the start of retail competition in the SPP area of Texas (see Note 5). We are evaluating the ramifications of this delay in the January 1, 2002 start date of competition for our SWEPCo and WTU Texas operations in the SPP. A Texas settlement agreement in connection with our merger with CSW permits CPL to apply up to $20 million of previously identified STP ECOM plant assets a year in 2000 and 2001 to reduce any excess earnings. STP ECOM plant assets will be depreciated in accordance with GAAP, on a systematic and rational basis. To the extent excess earnings exceed $20 million in 2001, CPL will establish a regulatory liability by a charge to earnings. In the event CPL, SWEPCo, and WTU are unable, after the 2004 true-up proceeding, to recover 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 The Michigan Legislation gave the MPSC broad powers to implement customer choice. We filed proposed unbundled rates, open access tariffs and terms of service in June 2001. In October 2001 the MPSC approved a settlement agreement related to our filing to implement customer choice on January 1, 2002. We agreed that recovery of implementation costs and regulatory assets would be determined in future proceedings and recovery of nuclear decommissioning costs would continue to be reviewed separately. We do not expect to incur material tangible asset impairments or regulatory asset write-offs. If we are not permitted to recover all or a portion of our generation-related regulatory assets, unrecorded decommissioning obligation, stranded costs or other implementation costs in future proceedings, it could have a material adverse effect on our results of operations, cash flows and possibly financial condition. Oklahoma Restructuring - Affecting AEP and PSO In June 2001 the Oklahoma Governor signed into law a bill that delayed retail electric competition indefinitely from its previously scheduled start date of July 1, 2002. Litigation ---------- Shareholders' Litigation - Affecting AEP In 2000 five complaints were filed against us seeking unspecified compensatory damages for alleged violations of federal securities laws (see Note 8). We believe these shareholder complaints are without merit and intend to continue to oppose them. The outcome of this litigation or its impact on our results of operations, cash flows or financial condition cannot be predicted. Municipal Franchise Fee Litigation - Affecting AEP and CPL In August and October 2001 CPL reached agreement to settle ongoing litigation related to municipal franchise fees with 125 cities in its service territory. The agreements require CPL to pay approximately $11 million. The agreements are subject to approval by the court which management expects to occur before year-end. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo In May 2001 SWEPCo settled ongoing litigation concerning the mining of lignite from reserves jointly owned with CLECO. As part of the settlement, SWEPCo purchased the mine operator's interest in mining assets and mining rights for $86 million and assumed the related obligations for mine reclamation (see Note 3). The settlement agreement gives CLECO the option to acquire up to a 50% interest in the mining assets. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, I&M, and OPCo As discussed in our 2000 Annual Report and Note 8, Federal EPA, a number of states and certain special interest groups alleged that AEP, APCo, CSPCo, I&M, and OPCo modified certain generating units over a 20 year period in violation of the Clean Air Act. 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. We believe our maintenance, repair and replacement activities were in conformity with the Clean Air Act and intend to vigorously pursue our defense. 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 March 2001 the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints, cannot be imposed. There is no time limit on claims for injunctive relief. If we do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition. An unaffiliated utility which operates certain plants jointly owned by CSPCo, reached a tentative agreement to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing and a final 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 future results of operations and cash flows. NOx Reductions - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo Federal EPA issued a rule (the NOx Rule) and granted petitions filed by certain northeastern states (the Section 126 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 (see Note 8). The compliance date for the NOx Rule is May 31, 2004. Federal EPA ruled that eleven states, including states in which APCo's, I&M's and OPCo's generating units are located, failed to submit approvable plans to comply with the NOx Rule. This ruling means that those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. A request for the D.C. Circuit to review this ruling is pending. The D.C. Circuit Court instructed Federal EPA to justify methods used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. In response to AEP and other utilities request for the D.C. Circuit Court to suspend the May 2003 compliance date of the Section 126 Rule, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. The Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including those owned by CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. In May 2001 selective catalytic reduction (SCR) technology to reduce NOx emissions on OPCo's Gavin Plant began operation. Construction of SCR technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant began in 2001. The Amos and Mountaineer projects (expected to be completed in 2002) are estimated to cost a total of $230 million ($145 million for APCo and $85 million for OPCo). Construction of SCR technology on KPCo's Big Sandy Plant Unit 2 is scheduled for completion in May 2003 at an estimated cost of $107 million. Preliminary estimates indicate that our compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures totaling approximately $1.6 billion. The following table shows the estimated compliance cost for certain of AEP's subsidiary registrants. Company Amount ------- ------ (in millions) APCo $365 CPL 57 I&M 202 OPCo 606 SWEPCo 28 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the preliminary 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. New Accounting Standards The FASB recently issued SFAS 141, "Business Combinations" and SFAS 142, "Goodwill And Other Intangible Assets." SFAS 141 requires that the purchase method of accounting be used to account for all business combinations entered into after June 30, 2001. SFAS 142 requires that goodwill and other intangible assets with indefinite lives be tested for impairment upon SFAS 142 implementation and annually thereafter. Amortization of goodwill and other intangible assets with indefinite lives will cease with our implementation of SFAS 142 beginning January 1, 2002. The amortization of goodwill reduced our net income $35 million for the nine months ended September 30, 2001. We have not determined the impact of adopting the other provision of these standards. SFAS 143, "Accounting for Asset Retirement Obligations," will become effective for us beginning January 1, 2003. SFAS 143 establishes accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. We are currently evaluating the provisions of the standard and determining its impact on results of operations, financial condition and cash flows. In August 2001 the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-lived Assets" which sets forth the accounting to recognize and measure an impairment loss. This standard replaces the previous standard, SFAS 121, "Accounting for the Long-lived Assets and for Long-lived Assets to be Disposed Of." SFAS 144 will apply to us in January 2002. We do not expect the implementation of SFAS 144 to materially affect results of operations or cash flows. QUALITATIVE AND QUANTITATIVE DISCLOSURES ON RISK RISK MANAGEMENT AEP and its registrant subsidiaries are subject to risks in their day to day operations. The risks and correlating strategies are:

AEP's strategies of trading, hedging and credit risk management to mitigate various risks have not materially changed since December 31, 2000. Commodity Price Risk We employ physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps, and other derivative contracts to offset market risk. AEP's internationally based electric distribution utilities hedge market risk through forward commodity contracts. Interest Rate Risk Fair value and cash flow hedge contracts mitigate changes in interest rates on short and long-term debt of AEP, KPCo, and I&M. CitiPower uses interest rate swaps for the same purpose. Foreign Exchange Risk AEP, KPCo, and OPCo employ cash flow forward hedge contracts to lock-in prices on purchased assets denominated in foreign currencies. International subsidiaries use currency swaps to hedge fluctuations in debt transactions. We do not hedge all foreign currency exposure. Credit Risk AEP limits credit risk by accepting primarily investment grade counter parties. We also require cash deposits, letters of credit and affiliate guarantees as collateral from certain counter parties in case of adverse market conditions. We trade electricity and gas contracts with numerous counter parties. Since our energy trading contracts are based on changes in market prices of the related commodities, our exposures can change. We believe that our credit and market exposures with any one counter party is not material. QUANTITATIVE MARKET RISK We employ policies and procedures to identify, assess and manage market risk exposure. One procedure is the risk measurement model Value at Risk (VaR). VaR is used daily to measure and monitor trading risk. VaR operates on the variance - covariance method using historical prices to estimate volatility and correlation and assumes a 95% confidence level and a one-day holding period. The following table represents the high, average and low VaRs for AEP's electric and gas trading activities and electric trading for its registrant subsidiaries. VaR for AEP and Registrant Subsidiaries: Nine Months Ended Year Ending September 30, December 31, 2001 2000 ---- ---- High Average Low High Average Low (in millions) (in millions) AEP $28 $14 $5 $32 $10 $1 APCo 2 1 1 6 2 - CPL 1 1 - 4 1 - CSPCo 1 1 - 3 1 - I&M 1 1 - 4 1 - KPCo - - - 1 - - OPCo 2 1 - 5 2 - PSO 1 1 - 3 1 - SWEPCo 1 1 - 4 1 - WTU - - - 1 - - Near term changes in commodity prices are not expected to materially affect our results of operations, cash flows and financial conditions. PART II. OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges. (b) Reports on Form 8-K: AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU No reports on Form 8-K were filed during the quarter ended September 30, 2001. Signature Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. 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 Treasurer Controller and Chief Accounting Officer Date: November 12, 2001

WEST TEXAS UTILITIES CO 10-Q