10-Q 1 xq201mod.txt COMBINED 10 Q 6/30/01 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended JUNE 30, 2001 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Transition Period from to

AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company, Public Service Company of Oklahoma and West Texas Utilities Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No ------- ------ The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at July 31, 2001 was 322,201,830. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended June 30, 2001 CONTENTS

This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, Appalachian Power Company, Central Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

iii 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. iv AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 Net income increased by $241 million or 75 cents per share for the quarter and by $367 million or $1.13 per share year-to-date predominately due to strong performance from the wholesale business. Benefiting from an increased contribution from wholesale natural gas trading activities and the favorable impact of the return to service of the Cook Plant, the earnings from our wholesale business increased 116 percent over the same quarter last year. The effects of deregulation resulted in a $57 million unfavorable variance between periods from extraordinary items, and this factor partially offsets our improved wholesale business results. Income statement line items which changed significantly were:

The increase in revenues was due to a substantial increase in electric and gas trading volumes and wholesale energy sales. Wholesale natural gas trading volume for the quarter was 774 billion cubic feet, a 178 percent increase from second-quarter 2000 volume of 278 million cubic feet. Electric trading volume for the quarter increased 16 percent to 121 million MWH and the average price per KWH increased 35%. In the first half of 2001, the average price per KWH sold and purchased moved upward reflecting market conditions during a period of high volatility in prices, especially natural gas. The increase in electric trading volume is primarily from: o continued expansion of our trading team o increased liquidity in the markets where we trade 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 markets where we have not traded historically Our fuel and purchased power expense increased due to increased trading volume, particularly gas, and an increase in generation. Our generation increased 3% in 2001 due mainly to the return to service in June 2000 and December 2000 of Cook Plant's two generating units. Our maintenance and other operation expense increased largely as a result of additional traders' incentive compensation and costs associated with the development of gas-fired plants. This increase was offset, in part, by no longer incurring expenditures to prepare the Cook Plant units for restart following an extended outage. Revenues from project fees offset the charges for development costs thus not adversely affecting net income. The write-off of deferred merger costs in 2000 included transaction and transition costs not recoverable from ratepayers under regulatory commission approved settlement agreements. In March 2001, we completed the sale of Frontera, one of the generating plants required to be divested under FERC - approved merger settlement agreements. The sale resulted in a $73 million gain recorded in other income for the year-to-date period. Our interest and preferred dividends decreased primarily because of lower average outstanding short-term debt balances and a decrease in average short-term interest rates. Our income taxes increased due to an increase in pre-tax income. In the second quarter of 2001 we recorded an extraordinary loss for $48 million net of tax to write-off stranded prepaid Ohio excise taxes (See Note 2). We discontinued the application of regulatory accounting for generation in Virginia and West Virginia during the second quarter of 2000 which resulted in an after tax extraordinary gain of $9 million in 2000.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $342 million and $471 million and for income taxes was $107 million and $206 million in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $21 million and $50 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 SECOND QUARTER 2001 vs. SECOND 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 $0.4 million or 25% for the quarter resulted primarily from an adjustment to the power bills to reflect the resolution of a tax issue. Net income for the year-to-date period declined $0.1 million or 1% primarily as a result of a final true-up billing in January 2000 to an unaffiliated utility whose unit power purchase contract expired on December 31, 1999. Income statement line items which changed significantly were:

The decrease in operating revenues resulted primarily from a decrease in recoverable expenses especially fuel. The Rockport Plant underwent scheduled maintenance outages in the second quarter of 2001. In 2000, maintenance outages occurred in the first quarter. Fuel expense decreased due to a decline in generation reflecting the length of outages in the second quarter 2001 and lower average fuel cost. Other operation and maintenance expense increased due to more extensive outages during the second quarter 2001 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, produced the decrease in interest charges.

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

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $1,143,000 and $1,619,000 and for income taxes was $1,350,000 and $3,129, 000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS ------------------------------------------------------------- SECOND QUARTER 2001 vs. SECOND 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 $2.8 million or 7% for the quarter due to the effect of an extraordinary gain recorded in 2000 for the discontinuance of regulatory accounting partially offset by favorable wholesale business performance. Net income increased $11.4 million or 13% for the year-to-date period primarily due to growth in and strong performance by the wholesale business. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $389 27 $1,341 54 Fuel Expense (8) (8) (11) (6) Purchased Power Expense 377 33 1,303 73 Other Operation Expense 6 10 12 10 Maintenance Expense 5 17 10 17 Depreciation and Amortization 5 13 11 14 Nonoperating Income 4 127 9 205 Extraordinary Gain (9) N.M. (9) N.M. N.M. = Not Meaningful The significant increase in revenues is due to increased wholesale electricity prices and trading volume of our wholesale business. 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). Wholesale trading volume increased 33% for the year-to-date period. The increase in wholesale prices is due to changes in market conditions during a period of high volatility in prices. Fuel expense of the wholesale business decreased due to a decline in generation as a result of scheduled plant maintenance. The increase in the wholesale business' purchased power expense is attributable to increases in wholesale electricity prices and trading volume. Other operation expense increased as a result of power trading incentive compensation expense of the wholesale business and a reduction in transmission equalization credits for the energy delivery business. APCo and certain affiliates share, through the Transmission Agreement, the costs associated with the ownership of the extra-high voltage transmission system and certain facilities at lower voltages based upon each company's peak demand and investment. An increase in APCo's peak demand relative to its affiliates' peak demand was the main reason for the decrease in transmission equalization credits. The increase in maintenance expense is mainly attributable to increased generating plant boiler maintenance repairs to the wholesale business' Amos, Mountaineer and Glen Lyn 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 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, swaps).

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $54,957,000 and $61,828,000 and for income taxes was $17,064,000 and $21,198,000 in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $1,684,000 and $7,451,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW, we participate in power marketing and trading activities conducted on our behalf by the AEP System. Second quarter net income decreased $15 million or 22% while the year-to-date net income increased $12 million or 16%. The lower second quarter net income was the result of increased transmission expenses. Year-to-date net income increased primarily from participation in the power marketing and trading operations. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $211 48 $498 66 Fuel Expense 6 5 69 30 Purchased Power Expense 186 532 380 686 Other Operation 22 40 22 17 Maintenance 3 16 3 11 Depreciation and Amortization 13 31 1 1 Taxes Other Than Federal Income Taxes 2 9 4 10 Federal Income Taxes (7) (20) 7 18 Nonoperating Income (3) (185) (2) (96) The significant increase in operating revenues resulted from participation in AEP's power marketing and trading operations, which added new wholesale revenues, and higher fuel related revenues due to increased fuel and purchased power expense. CPL began sharing in AEP's marketing and trading transactions as a result of the merger of AEP and CSW in June 2000. Fuel expense increased due primarily to an increase in the average unit cost of fuel as a result of higher spot market natural gas prices. The substantial rise in purchased power expense is attributable to post merger participation in the marketing and trading operation. Other operation expense increased due primarily to a favorable adjustment recorded in the second quarter of 2000 for the energy delivery business' transmission expenses that resulted from new transmission prices for Electric Reliability Council of Texas (ERCOT) transmission grid usage. Each year ERCOT establishes new rates to allocate the costs of the Texas transmission system to Texas electric utilities. Additionally, generation expenses were up due to power trading incentive compensation. Maintenance expense for the quarter increased primarily due to two non-nuclear plant outages. Year-to-date maintenance expense increased primarily due to the wholesale business' STP nuclear plant refueling outage between March 7 and April 2, 2001. The increase in depreciation and amortization expense for the quarter is due primarily to higher depreciation expense associated with excess earning provisions of the Texas deregulation legislation. Taxes other than federal income taxes increased due primarily to an increase in Texas Gross Receipts Tax and Ad Valorem taxes. Federal income taxes attributable to operations for the quarter decreased due to a decrease in pre-tax operating income. However, federal income taxes attributable to operations for the year-to-date period increased due to an increase in pre-tax operating income. Nonoperating income decreased due to a reduction in allocated tax savings resulting from the parent company loss tax benefit.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $46,083,000 and $46,981,000 and for income taxes was $11,307,000 and $48,141,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND 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 $14 million or 41% in the second quarter of 2001 and $4 million or 7% in the year-to-date period due to an extraordinary loss recorded in the second quarter to recognize a stranded asset resulting from deregulation. Income before extraordinary item increased by $12 million or 34% in the second quarter of 2001 and $22 million or 35% in the year-to-date period versus last year. Income increased due to growth in and strong performance by the wholesale business. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $181 19 $673 43 Fuel Expense (6) (13) - - Purchased Power Expense 160 23 618 56 Other Operation Expense 4 8 13 14 Maintenance Expense 2 8 6 17 Depreciation and Amortization 6 26 13 27 Extraordinary Item 26 N.M. 26 N.M. N.M. = Not Meaningful The significant increase in revenues is due to increases in electric wholesale prices and volume of our wholesale business. 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). Wholesale trading volume increased 24% for the year-to-date period. The increase in wholesale prices is due to changes in market conditions during a period of high volatility in prices. Fuel expense of the wholesale business decreased in the second quarter of 2001 due to a decrease in net generation partially offset by an increase in price and the discontinuance of deferred fuel accounting because of deregulation effective January 1, 2001. The increase in purchased power expense was attributable to increases in the wholesale business electric trading prices and volume. Other operation expense increased due to increases in uncollectible accounts, factored customer accounts receivable expenses, the effect of gains in 2000 from the disposition of emission allowances and higher power trading expenses and trading incentive compensation. Maintenance expenses increased due to planned outages at several of the wholesale business' plants for boiler overhauls and inspections. The commencement of the amortization of transition regulatory assets in connection with the transition to customer choice and market-based pricing of electricity under the deregulation of our retail supply business accounted for the increase in depreciation and amortization expense. The extraordinary loss was recorded in June 2001 to recognize stranded prepaid Ohio excise taxes (See Note 2).

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

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $32,812,000 and $34,547,000 and for income taxes was $17,579,000 and $35,539,000 in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $734,000 and $3,233,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND 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 $67 million in the quarter and $135 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 2000. Unit 2 and Unit 1 returned to service in June and December 2000, respectively. Income statement line items which changed significantly were: Increase (Decrease) ------------------- econd Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $248 25 $832 48 Fuel Expense 17 38 33 36 Purchased Power Expense 191 26 713 60 Other Operation Expense (41) (27) (77) (27) Maintenance Expense (24) (44) (52) (46) Federal Income Taxes 34 N.M. 69 N.M. N.M. = Not Meaningful The significant increase in operating revenues resulted from increased wholesale prices and volumes. 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. In 2001 both price and volume in the trading operation increased. The number of forward electricity contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory) grew due to the expansion of our trading operation and increased liquidity in the markets. Wholesale prices increased reflecting market conditions during a period of high volatility in prices. With the return to service of the nuclear units in 2000, I&M's available generation increased resulting in additional power being delivered 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. Other operation and maintenance expenses decreased primarily due to the cessation of expenses related to work to restart the Cook Plant units. The significant increase in federal income tax expense attributable to operations was primarily due to major increases in pre-tax operating income.

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

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

KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND 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 service. 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. Although revenues rose significantly, net income increased slightly in the quarter and declined by less than $1.0 million or 7% for the year-to-date period. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $96 28 $324 56 Purchased Power Expense 98 35 324 72 Other Operation Expense 2 20 7 29 Maintenance Expense (3) (39) (4) (28) Federal Income Taxes - N.M. (2) (31) Nonoperating Income 1 85 2 335 Interest Charges (1) (11) (1) (8) N.M. = Not Meaningful The significant increase in operating revenues resulted from increased wholesale prices and volumes. Our wholesale sales to and forward trades with other utility systems and power marketers rose by 15% in the quarter and 37% for the year-to-date period. The number of forward electricity contracts in AEP's traditional marketing area (up to two transmission systems from AEP's service territory) grew due to the expansion of our trading operation and increased liquidity in the markets. Wholesale prices increased reflecting market conditions during a period of high volatility in prices. Purchased power expense for the wholesale business increased due to higher wholesale prices and increased sales and trading volume. Other operation expense increased due to an increase in trading incentive compensation for the wholesale business, a decline in AEP transmission equalization credits for the energy delivery business and the cost of accounts receivable factoring for both businesses. 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 transmission equalization credits. The effect of the costs of outages at our wholesale business' Big Sandy Plant in 2000 caused maintenance expense to decrease. Federal income taxes attributable to operations decreased due to a decline in pre-tax income. The increase in nonoperating income was due to an increase in net gains from non-regulated trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures, swaps) for the wholesale business. Interest charges declined due to lower outstanding debt balances and lower interest rates in 2001.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $13,692,000 and $15,046,000 and for income taxes was $6,010,000 and $5,921,000 in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $760,000 and $1,836,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND 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 $48 million or 82% for the second quarter of 2001 and $40 million or 39% for the year-to-date period due to an extraordinary loss recorded in the second quarter to recognize a stranded asset resulting from deregulation. Income before extraordinary item decreased by $26 million or 45% in the second quarter of 2001 and $19 million or 18% in the year-to-date period because of implementation of customer choice. 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. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $191 13 $843 34 Purchased Power Expense 204 22 845 57 Other Operation 10 12 14 8 Maintenance Expense 3 8 10 17 Depreciation and Amortization 19 48 40 52 Taxes Other Than Federal Income taxes 5 13 2 3 Federal Income Taxes (20) (55) (24) (34) Nonoperating Income 7 N.M. 15 N.M. Extraordinary Item 22 N.M. 22 N.M. N.M. = Not Meaningful The significant increase in revenues is due to increases in electric trading wholesale prices and volume of our wholesale business. 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). Wholesale trading volume increased 19% for the year-to-date period. The increase in wholesale prices reflects market conditions during a period of high volatility in prices. The increase in purchased power expense was attributable to the increase in the wholesale business' electric trading volume and 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, and trading incentive compensation of the wholesale business. Maintenance expenses increased due to planned outages at several of the wholesale business' plants for boiler overhauls and inspections. 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. 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). An extraordinary loss was recorded in June 2001 to recognize stranded prepaid Ohio excise taxes (See Note 2).

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $40,580,000 and $40,791,000 and for income taxes was $54,694,000 and $64,597,000 in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $522,000 and $8,422,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW, we participate in power marketing and trading activities conducted on our behalf by the AEP System. Although revenues increased substantially, operating expenses increased by a greater amount causing net income to decrease by $2.8 million or 19% in the second quarter and $5.5 million or 35% in the first half of 2001. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $189 90 $384 104 Fuel Expense 70 92 110 75 Purchased Power Expense 118 373 264 505 Other Operation Expense 6 21 17 32 Federal Income Taxes (3) (40) (5) (61) The significant increase in operating revenues was due to participation in the AEP System's power marketing and trading activities subsequent to June 2000. Revenues for the year-to-date period also increased as a result of the absence of a 2000 adjustment due to 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 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 participation in the AEP System's power marketing and trading activities. Other operation expenses increased in the second quarter due to increased transmission expenses, public liability insurance premiums, and power trading incentive compensation. Expenses increased for the first half of 2001 due mainly to the absence of a 2000 favorable adjustment due to the FERC-approved Transmission Coordination Agreement mentioned above, along with increased incentive compensation for power trading and transmission expenses. Federal income tax expense associated with utility operations decreased as a result of a decline in pre-tax book income.

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW, we participate in power marketing and trading activities conducted on our behalf by the AEP System. Net income increased $11.2 million, or 42%, for the first half of 2001 despite a small decrease in the quarter of $1 million, or 5%. The increase for the first half of 2001 resulted from the favorable impact of our power marketing and trading operations. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $162 60 $376 78 Fuel Expense 10 9 39 19 Purchased Power Expense 149 776 307 991 Other Operation Expense (3) (9) 1 2 Depreciation and Amortization 6 21 7 12 Taxes Other Than Federal Income Taxes 2 11 5 21 Federal Income Taxes - - 6 73 The significant increase in operating revenues and purchased power expense for the quarter and first half of 2001 resulted from increased trading volumes of the wholesale business due to the post merger favorable impact of AEP's power marketing and trading operations. SWEPCo began sharing in AEP's marketing and trading transactions as a result of the merger of AEP and CSW in June 2000. Fuel expense for the wholesale business increased due primarily to an increase in the average unit cost of fuel as a result of higher spot market natural gas prices. Other operation expense decreased for the quarter due to the reversal of a $4 million environmental reserve originally recorded in the fourth quarter of 1999. The reserve was set up for expected remediation work at a site on which a manufactured gas plant previously resided. In June 2001, the site was donated to a city for use as a major civic complex. As part of the donation, the city agreed to hold us harmless from any future liability arising from the site. Other operation expense increased for the year-to-date period as a result of a bad debt write-off, our share of power trading incentive compensation incurred since the June 2000 merger and increased transmission services expense partially offset by the reversal of the $4 million environmental reserve. Depreciation and amortization expenses increased due to an increase in excess earnings accruals under the Texas restructuring legislation. Taxes other than federal income taxes increased during the second quarter due to increased state income taxes reflecting higher state taxable income. The increase for the first six months of 2001 is due to a favorable adjustment of ad valorem taxes recorded in 2000 and increased state income taxes due to 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.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $25,743,000 and $20,711,000 and for income taxes was $4,144,000 and $14,270,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. WEST TEXAS UTILITIES COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW, we participate in power marketing and trading activities conducted on our behalf by the AEP System. Net income decreased $1.9 million or 24% for the quarter and was $4.9 million, or 41%, lower for the six months ended June 30, 2001. The decreases were primarily due to increased operating expenses primarily higher transmission related expenses offset in part by trading related activities and nonoperating income. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $62 47 $161 71 Fuel Expense - - 31 41 Purchased Power Expense 58 258 125 334 Other Operation Expense 10 61 15 42 Maintenance Expense 2 40 2 17 Federal Income Taxes (3) (56) (5) (69) Nonoperating Income 3 82 4 127 The significant increase in operating revenues was primarily due to the participation in the AEP System's power marketing and trading activities subsequent to June 2000 and higher fuel related revenues due to increased fuel and purchased power expense of the wholesale business. WTU began sharing in AEP's marketing and trading transactions as a result of the merger of AEP and CSW in June 2000. Fuel expense increased due primarily to an increase in the average unit cost of fuel as a result of higher spot market natural gas prices. Purchased power expense's significant rise was primarily attributable to participation in AEP's trading operation and the impact of natural gas prices on wholesale purchased power prices. Other operation expense increase is due primarily to a 2000 reduction in energy delivery's transmission expenses that resulted from new prices for the Electric Reliability Council of Texas (ERCOT) transmission grid. Other operation expense also increased year-to-date due to a favorable adjustment made in January 2000 related to the FERC approved Transmission Coordination Agreement. Maintenance expense increased due to a scheduled overhaul in 2001 of Oklaunion Power Plant of our wholesale business. Federal income taxes attributable to operations decreased due primarily to a decrease in pre-tax income. The increase in nonoperating income was due primarily to a loss provision recorded in the second quarter of 2000 for the termination of merchandise sales and the cost of phasing out the merchandising sales program.

Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $10,139,000 and $9,053,000 and for income taxes was ($2,957,000) and $5,442,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.

1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 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:

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 OPCo and CSPCo Recognize 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. 3. ACQUISITIONS AND SALES OF ASSETS 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 may adjust the allocation of purchase price for changes in its preliminary evaluations and assumptions based on review of additional information. 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 Affiliated 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 is expected to have a nominal impact on results of operations and cash flows. 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. Fuel cost in the Texas jurisdiction after 2001 will no longer be subject to PUCT review and reconciliation. During 2002 CPL, SWEPCo, and WTU will file a final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. The unrecovered deferred fuel balances at December 31, 2001 will be included in each company'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. The following table lists the Texas jurisdictional reconciliation status, total fuel cost subject to reconciliation, under-recovered fuel balances and the remaining fuel surcharge for the companies:

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. A decision on the WTU fuel surcharge request is pending. Management expects the PUCT to defer WTU's 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. 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 official notice of certain disagreements with the reports as filed from the Staff of the PUCT and the Office of Public Utility Counsel (OPC). The Staff and OPC took exception to certain adjustments made by the companies, and 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 table below shows the amounts of excess earnings calculated by each company, the PUCT Staff and the OPC: 2000 Excess Earnings As filed As calculated As calculated by company by PUCT Staff by the OPC ---------- ------------- ---------- (in millions) CPL $12.6 $21.7 $42.4 SWEPCo (3.7) 1.4 1.2 WTU 10.2 16.6 15.3 The companies believe that the calculations in their reports are proper and believe the ultimate amount of excess earnings finally approved by the PUCT will not have a materially adverse effect on their results of operations or cash flows. A PUCT decision is due in late August 2001. 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. 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 are scheduled for October 2001. Presently, capped rates are sufficient to recover generation-related regulatory assets. Management is unable to predict if the outcome of the hearings will result in the ability to recover generation-related regulatory assets. 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 hearing 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 future distribution rates by $54.8 million over a five-year period 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. CPL expensed excess earnings amounts in 1999, 2000 and 2001. Consequently, the April order has no effect on reported net income. 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 plaintiffs have requested a rehearing. We expect the court to dismiss this request. 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 SWEPCo and part of 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. The Petition seeks an expedited process to achieve a final PUCT determination by November 1, 2001. Management is evaluating the ramifications of a potential 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 or reduce regulatory assets 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 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. MPSC action on the filing is expected in 2001 with competition commencing 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 and other implementation costs, it 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 Trading of electricity and gas worldwide. o 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. 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 unbundled into non-regulated wholesale and regulated energy delivery businesses. The remaining utility subsidiaries are expected to be grouped with AEP's regulated business. Management is currently in the process of obtaining the necessary regulatory approvals to support this new business structure. 7. FINANCING AND RELATED ACTIVITIES

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

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 damage 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 cities it serves of the pending class action suit. If a final decision determines an underpayment of franchise fees, CPL has pledged to extend that final decision 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 for October 2001. Management believes that it has substantial defenses against the cities' claims and plans to pursue its counterclaims. However, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. Texas Base Rate Litigation - Affecting AEP and CPL As discussed in the 2000 Annual Report, CPL is involved in litigation concerning a 1997 PUCT base rate order. A request for review is pending before the Texas Supreme Court. The primary issues are: 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 An $18 million disallowance of affiliated service billings. Management is unable to predict the final resolution of this litigation or its impact on results of operations and 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 requested 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 AEP System companies' request to allow time for additional discovery before responding to the plaintiffs' action was granted. 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 earnings 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 was upheld by the D.C. Circuit Court. The U.S. Supreme Court denied a petition requesting its review of the lower court decision. The compliance date for the NOx Rule is May 31, 2004. The NOx Rule required states to submit plans to comply with its mandates. 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 compliance plans. 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. AEP and other utilities requested 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 for both the NOx Rule and the Section 126 Rule to justify methods used to allocate allowances and project growth. AEP and other utilities requested the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. They also asked the D.C. Circuit Court to retain jurisdiction until Federal EPA complied with the Court's instructions. 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 six month periods ended June 30, 2001 is presented with each registrants' financial statements elsewhere in this document. FINANCIAL CONDITION Financing Activity On May 10, 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 the 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. 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 a backstop 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 conduits are funding this facility. Acquisitions We continue to pursue a strategy of aligning assets with our wholesale business model. The strategy is to selectively purchase assets which enhance information flow from energy markets and support our trading and marketing activity. The June 2001 purchase of Houston Pipe Line Company (HPL) complements our existing Louisiana natural gas assets and will contribute to continued growth in natural gas marketing and trading. The HPL acquisition includes 4,200 miles of pipeline with capacity of approximately 2.4 billion cubic feet per day (Bcf/d), the operation of the Bammel Storage Facility, one of the largest storage facilities in North America with a capacity of approximately 118 billion cubic feet, and certain gas marketing contracts. We used short-term borrowings of $727 million for the interim financing of this acquisition. In the third quarter, we plan to replace this short-term borrowing with long-term financing through a limited liability company. The limited liability company expects to sell a non-controlling, preferred interest to a third party for $750 million. The preferred interest will receive a preferred return equal to an adjusted floating reference rate. The results of operations, cash flows and financial position of the limited liability company will be consolidated with AEP and treated as minority interests. We announced our plan to acquire the MEMCO Barge Line. This acquisition will continue our growth strategy to create value at various points along the energy chain. With the addition of MEMCO, we will triple the size of our barge fleet and become a full-service carrier throughout the U.S. inland waterways. We expect this acquisition to add to both earnings and meaningful operational insight into the fuel transportation portion of our business. Total consolidated plant and property additions including capital leases for the year-to-date period were $865 million. The following table shows the additions by certain subsidiary registrants: Company Amount ------- ------ (in millions) APCo $108 CPL 110 I&M 41 OPCo 151 SWEPCo 96 Corporate Separation On July 24, 2001, we filed an application with the FERC requesting approval of proposed 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 business for Ohio and Texas operating companies, which includes CSPCo, OPCo, CPL and WTU, to unregulated companies. The filed plan also proposes amendments of the power pooling agreements that affects 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 anticipate retiring first mortgage bonds at CSPCo, OPCo, CPL and WTU using various methods including: o call provisions for bonds that have an optional redemption o open market purchases o exchange offers o tender offers o defeasance To date, we have not made decisions relating to securities other than first mortgage bonds. OTHER MATTERS Industry Restructuring As discussed in 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 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. 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. 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. 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 are scheduled for October 2001. Presently, capped rates are sufficient to recover generation-related regulatory assets. We are unable to predict if the outcome of the hearings will result in the ability to recover generation-related regulatory assets. 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 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 hearing 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 future distribution rates by $54.8 million over a five-year period 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. CPL expensed excess earnings amounts in 1999, 2000 and 2001. Consequently, the April order has no effect on reported net income. 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 plantiffs have requested a rehearing. We expect the court to dismiss this request. We plan 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 SWEPCo and part of 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. The Petition seeks an expedited process to achieve a final PUCT determination by November 1, 2001. We are evaluating the ramifications of a potential 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 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 or reduce regulatory assets 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 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. MPSC action on the filing is expected in 2001 with competition commencing on January 1, 2002. 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 and other implementation costs, 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. Under previously approved legislation, the start date for Oklahoma customer choice had been 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 We have 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 damage 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 cities it serves of the pending class action suit. If a final decision determines an underpayment of franchise fees, CPL has pledged to extend that final decision 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 for October 2001. We believe that we have substantial defenses against the cities' claims and plan to pursue our counterclaims. However, we cannot predict the outcome of this litigation or its impact on our results of operations, cash flows or financial condition. 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, I&M, and OPCo As discussed in our 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 requested 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. Our request to allow time for additional discovery before responding to the plaintiffs' action was granted. We believe our maintenance, repair and replacement activities were in conformity with the Clean Air Act and intend to vigorously pursue our defense. 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. In December 2000 Cinergy Corp., 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 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 earnings and cash flows. NOx Reductions - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo Federal EPA issued a rule (the NOx Rule) requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The NOx Rule was upheld by the D.C. Circuit Court. The U.S. Supreme Court denied a petition requesting its review of the lower court decision. The compliance date for the NOx Rule is May 31, 2004. The NOx Rule required states to submit plans to comply with its mandates. 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 compliance plans. 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. AEP and other utilities requested 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 our coal-fired generating units. After review, the D.C. Circuit Court upheld the Section 126 Rule. The D.C. Circuit Court instructed Federal EPA for both the NOx Rule and the Section 126 Rule to justify methods used to allocate allowances and project growth. AEP and other utilities requested the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. They also asked the D.C. Circuit Court to retain jurisdiction until Federal EPA complied with the Court's instructions. 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 FASB's Derivative Implementation Group (DIG) Guidance for SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" DIG guidance for fuel supply (for example, coal and gas) and electricity contracts becomes effective in the third quarter. DIG guidance concluded that fuel supply contracts with volumetric optionality cannot qualify as a normal purchase or sale and provided guidance for determining when electricity 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 and are thereby exempt from DIG guidance described above. The few contracts that qualify as financial derivative instruments are not expected to materially affect AEP's results of operations, cash flows or financial condition. SFAS 141 and SFAS 142 In July 2001 the FASB 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 annually and not be subjected to amortization. The provisions of SFAS 142 will apply to us beginning January 1, 2002. The amortization of goodwill reduced our net income by $23 million for the six months ended June 30, 2001. We have not quantified the impact of adopting other provisions of these standards. 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. 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: Six Months Ended Year Ending June 30, December 31, 2001 2000 ---- ---- High Average Low High Average Low (in millions) (in millions) AEP $25 $14 $6 $32 $10 $1 APCo 6 2 1 6 2 - CPL 1 - - 4 1 - CSPCo 3 1 - 3 1 - I&M 4 1 - 4 1 - KPCo 1 1 - 1 - - OPCo 5 2 1 5 2 - PSO 1 - - 3 1 - SWEPCo 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 1. Legal Proceedings. AEP On May 15, 2001, the Louisiana Department of Environmental Quality issued a Compliance Order and Notice of Potential Penalty to LIG's Plaquemine Gas Processing Plant alleging violations of regulations and finding certain deficiencies with respect to the Risk Management Plan developed for the plant. Reference is made to pages 28 and 29 of the Annual Report on Form 10-K for the year ended December 31, 2000 for a discussion of hazardous air pollutants. On July 26, 2001, upon motion by Federal EPA, the U.S. Court of Appeals for the District of Columbia Circuit dismissed the petition for review filed by utility industry groups in February 2001 relating to Federal EPA's action classifying coal-fired electric generating units as "major sources" of hazardous air pollutants. AEP and SWEPCo On May 22, 2001, Federal EPA, Region 6, issued Findings of Violation and an Order for Compliance to SWEPCo's Wilkes Power Plant alleging violations of waste water discharge permit limits and directing SWEPCo to undertake corrective action. Item 4. Submission of Matters to a Vote of Security Holders. --------------------------------------------------- AEP The annual meeting of shareholders was held in Corpus Christi, Texas on April 25, 2001. The holders of shares entitled to vote at the meeting or their proxies cast votes at the meeting with respect to the following two matters, as indicated below: 1. Election of fourteen directors to hold office until the next annual meeting and until their successors are duly elected. Each nominee for director received the votes of shareholders as follows:

*A non-vote occurs when a nominee holding shares for a beneficial owner votes on one proposal, but does not vote on another proposal because the nominee does not have discretionary voting power and has not received instructions from the beneficial owner. APCo The annual meeting of stockholders was held on April 24, 2001 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR each of the following seven persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley, III Henry W. Fayne Susan Tomasky William J. Lhota J. H. Vipperman Armando A. Pena No other business was transacted at the meeting. CPL Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 12, 2001, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley III Henry W. Fayne Susan Tomasky William J. Lhota J. H. Vipperman Armando A. Pena I&M Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 24, 2001, the following thirteen persons were elected directors to hold office for one year or until their successors are elected and qualify: Karl G. Boyd Thomas V. Shockley, III E. Linn Draper, Jr. Jackie S. Siefker Henry W. Fayne David B. Synowiec Marc E. Lewis Susan Tomasky William J. Lhota J. H. Vipperman Susanne M. Moorman W. E. Walters John R. Sampson OPCo The annual meeting of shareholders was held on May 1, 2001 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 27,952,473 votes were cast FOR each of the following seven persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley, III Henry W. Fayne Susan Tomasky William J. Lhota J. H. Vipperman Armando A. Pena No other business was transacted at the meeting. SWEPCo Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 11, 2001, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley III Henry W. Fayne Susan Tomasky William J. Lhota J. H. Vipperman Armando A. Pena Item 5. Other Information. AEP and APCo Reference is made to pages 17 and 18 of the Annual Report on Form 10-K for the year ended December 31, 2000 for a discussion of APCo's proposed transmission facilities. On May 31, 2001, the Virginia SCC issued an order approving the Wyoming-Jacksons Ferry Project. On August 6, 2001, the U.S. Forest Service published in the Federal Register a Notice of Intent to prepare a Supplemental Draft Environmental Impact Statement (SDEIS). The Forest Service has scheduled three public meetings in August 2001 in the Virginia area to be crossed by the route to Jacksons Ferry. The Forest Service expects to file the SDEIS with Federal EPA for public review by April 2002. Following public comment, the Forest Service expects to file the final EIS with Federal EPA in October 2002 and then issue a Record of Decision. 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: Companies Reporting Date of Report Item Reported AEP April 24, 2001 Item 7. Financial Statements and Exhibits AEP May 3, 2001 Item 7. Financial Statements and Exhibits AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU No reports on Form 8-K were filed during the quarter ended June 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. By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto --------------------------- ----------------------------------- Armando A. Pena Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer AEP GENERATING COMPANY APPALACHIAN POWER COMPANY CENTRAL POWER AND LIGHT COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY WEST TEXAS UTILITIES COMPANY By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto --------------------------- ----------------------------------- Armando A. Pena Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer Date: August 10, 2001

AEP GENERATING CO /OH/ 10-Q