ThZeal - The Zeal

10-Q 1 xq101mod.txt COMBINED 10Q

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.

iv 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. Inflationary trends. o Electricity and gas market prices. o Interest rates o Other risks and unforeseen events. A-6 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 2000 Net income increased by $126 million or 90% due predominately to a strong performance from the wholesale business inclusive of the favorable impact of the return to service of the Cook Nuclear Plant. The wholesale business, which consists of wholesale electric and gas sales in the United States, the generation component of domestic retail electricity sales, worldwide electric and gas trading and other related businesses, contributed $103 million to the increase. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % - Revenues $8,121 133 Fuel and Purchase Power Expense 7,755 178 Maintenance and Other Operation Expense 107 13 Income Taxes 93 121 Other Income, net (11) (26) Interest and Preferred Dividends 16 6 Other 13 3 --------- Net Income $ 126 90 ======= The increase in revenues is due to a substantial increase in electric and gas trading volumes and wholesale energy sales reflecting the return to service of the Cook Nuclear units. The major increase in fuel and purchased power expense was primarily attributable to the increase in trading volume and an increase in generation. Net generation increased 4% due mainly to the return to service in June and December of 2000 of Cook Nuclear Plant's two generating units. STP Nuclear plant increased its net generation by 4%. Maintenance and other operation expense increased largely as a result of material and labor costs associated with the development of Buckeye Power and Dow Chemical gas-fired plants plus additional traders' incentive compensation. These cost increases were partially offset by the cessation of restart expenditures for the Cook Nuclear Plant units following an extended Nuclear Regulatory Commission (NRC) monitored outage. Project fees received for the Buckeye Power and Dow Chemical projects are recognized in revenues using the percentage of completion method. Consequently, the charges to expense for material and labor costs did not adversely affect net income. The increase in income taxes is predominately due to an increase in pre-tax income. Other income decreased in the quarter primarily due to a reduction in equity earnings from investments. The increase in interest and preferred dividends was primarily due to an increase in average outstanding short-term debt balances and an increase in average short-term debt interest rates reflecting increased short-term cash demands and short-term market conditions. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in millions, except per-share amounts) (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- TOTAL REVENUES $14,238 $6,117 ------- ------ EXPENSES: Fuel and Purchased Power 12,102 4,347 Maintenance and Other Operation 958 851 Depreciation and Amortization 336 320 Taxes Other Than Income Taxes 168 171 --- --- TOTAL EXPENSES 13,564 5,689 ------ ----- OPERATING INCOME 674 428 OTHER INCOME, net 31 42 -- -- INCOME BEFORE INTEREST, PREFERRED DIVIDENDS AND INCOME TAXES 705 470 INTEREST AND PREFERRED DIVIDENDS 269 253 --- --- INCOME BEFORE INCOME TAXES 436 217 INCOME TAXES 170 77 --- -- NET INCOME $ 266 $ 140 ========= ======= AVERAGE NUMBER OF SHARES OUTSTANDING 322 322 === === EARNINGS PER SHARE (Basic and Dilutive): $0.83 $0.43 ===== ===== CASH DIVIDENDS PAID PER SHARE $0.60 $0.60 ===== ===== See Notes to Financial Statements beginning on page L-1.

B-5 AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 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 net of temporary cash investments. Net income declined $0.5 million or 19% for first quarter 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: Increase (Decrease) First Quarter (in millions) % ------------- - Operating Revenues $ 3.6 6 Fuel Expense 3.2 13 Maintenance Expense (0.6) (23) Taxes Other Than Federal Income Taxes 2.0 178 Federal Income Taxes (0.3) (46) Interest Charges (0.1) (16) The increase in operating revenues resulted primarily from an increase in recoverable expenses as generation increased due to an increase in Rockport Plant's availability. Shorter outages in 2001, reflecting management's policy to maximize generating capacity availability, allowed the Rockport Plant units to generate 19% more electricity than in 2000. Fuel expense increased due to the increase in generation. The reduction in the number of outages and the shorter length of planned outages also accounted for the decrease in maintenance expense. Taxes other than federal income taxes increased due to the accrual of state income taxes based on an estimate of higher taxable income for 2001. The decrease in federal income taxes attributable to operations is primarily due to a decrease in pre-tax income. Reductions in variable interest rates, reflecting market conditions, were the primary reason for the decline in interest charges. AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) OPERATING REVENUES $60,507 $56,866 ------- ------- OPERATING EXPENSES: Fuel 27,645 24,435 Rent - Rockport Plant Unit 2 17,071 17,071 Other Operation 2,958 3,098 Maintenance 1,926 2,515 Depreciation 5,586 5,505 Taxes Other Than Federal Income Taxes 3,128 1,126 Federal Income Taxes 386 721 --- --- TOTAL OPERATING EXPENSES 58,700 54,471 ------ ------ OPERATING INCOME 1,807 2,395 NONOPERATING INCOME 862 869 --- --- INCOME BEFORE INTEREST CHARGES 2,669 3,264 INTEREST CHARGES 689 819 --- --- NET INCOME $1,980 $2,445 ====== ====== STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $ 9,722 $ 3,673 NET INCOME 1,980 2,445 CASH DIVIDENDS DECLARED 959 1,935 --- ----- BALANCE AT END OF PERIOD $10,743 $4,183 ======= ====== The common stock of AEGCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2001 December 31, 2000 -------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $635,945 $635,215 General 2,973 2,795 Construction Work in Progress 3,676 4,292 ----- ----- Total Electric Utility Plant 642,594 642,302 Accumulated Depreciation 320,991 315,566 ------- ------- NET ELECTRIC UTILITY PLANT 321,603 326,736 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 4,768 2,757 Accounts Receivable: Affiliated Companies 21,105 21,374 Miscellaneous 2,110 2,341 Fuel - at average cost 10,375 11,006 Materials and Supplies - at average cost 3,949 3,979 Prepayments 105 145 --- --- TOTAL CURRENT ASSETS 42,412 41,602 ------ ------ REGULATORY ASSETS 5,444 5,504 ----- ----- DEFERRED CHARGES 3,379 760 ----- --- TOTAL ASSETS $372,838 $374,602 ======== ======== See Notes to Financial Statements beginning on page L-1.

C-7 APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 2000 Net income increased $14.1 million or 30% mainly due to growth in and strong performance by the trading operation. APCo, as a member of the AEP Power Pool, shares in the revenues and costs of wholesale marketing and trading activities conducted on its behalf by the AEP Power Pool. Income statement line items which changed significantly were: Increase (Decrease) First Quarter (in millions) % ------------- - Operating Revenues $952 93 Fuel Expense (3) (3) Purchased Power Expense 927 141 Other Operation Expense 5 9 Maintenance Expense 5 17 Depreciation and Amortization 5 14 Nonoperating Income 4 547 The significant increase in revenues is due to a 60% increase in electric trading volume. In the first quarter of 2001 the AEP Power Pool grew its trading business resulting in an increase in the number of forward electricity purchase and sales contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory). Fuel expense decreased due to a decline in generation as a result of scheduled plant maintenance. The increase in purchased power expense was primarily attributable to the increase in trading volume. Other operation expense increased as a result of the growth in AEP's electricity marketing and trading operations. The increase in maintenance expense is due to the effect of performing generating plant boiler maintenance repairs to the Amos, Mountaineer and Glen Lyn Plants. Depreciation and amortization expense increased due to the accelerated amortization beginning in July 2000 of transition regulatory assets in connection with the June 2000 discontinuance of SFAS 71 in the Company's Virginia and West Virginia jurisdictions whereby net generation-related regulatory assets were transferred to the distribution portion of the business commensurate with their recovery through regulated rates (see Note 5 for further discussion of the effects of restructuring). Additional investments in distribution and 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 AEP Power Pool trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures, swaps). The AEP Power Pool enters into power trading transactions for the forward purchase and sale of electricity and electricity options, futures and swaps. The Company's share of the AEP Power Pool's gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in nonoperating income.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) NET INCOME $61,787 $47,644 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (417) - ---- -- COMPREHENSIVE INCOME $61,370 $47,664 ======= ======= The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $120,584 $175,854 NET INCOME 61,787 47,664 DEDUCTIONS: Cash Dividends Declared: Common Stock 32,399 31,653 Cumulative Preferred Stock 361 525 Capital Stock Expense 142 108 --- --- BALANCE AT END OF PERIOD $149,469 $191,232 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2001 December 31, 2000 -------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $2,058,100 $2,058,952 Transmission 1,193,606 1,177,079 Distribution 1,836,856 1,816,925 General 256,265 254,371 Construction Work in Progress 100,046 110,951 ------- ------- Total Electric Utility Plant 5,444,873 5,418,278 Accumulated Depreciation and Amortization 2,218,992 2,188,796 --------- --------- NET ELECTRIC UTILITY PLANT 3,225,881 3,229,482 --------- --------- OTHER PROPERTY AND INVESTMENTS 51,879 56,967 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 572,406 322,688 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 7,571 5,847 Advances to Affiliates - 8,387 Accounts Receivable: Customers 166,360 243,298 Affiliated Companies 58,465 63,919 Miscellaneous 15,907 16,179 Allowance for Uncollectible Accounts (1,995) (2,588) Fuel - at average cost 32,994 39,076 Materials and Supplies - at average cost 60,506 57,515 Accrued Utility Revenues 15,207 66,499 Energy Trading Contracts 1,875,174 2,036,001 Prepayments 14,356 6,307 ------ ----- TOTAL CURRENT ASSETS 2,244,545 2,540,440 --------- --------- REGULATORY ASSETS 450,773 447,750 ------- ------- DEFERRED CHARGES 45,921 48,826 ------ ------ TOTAL ASSETS $6,591,405 $6,646,153 ========== ========== See Notes to Financial Statements beginning on page L-1.

D-5 CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 2000 Net income increased $27 million, or 330%, primarily from participation in AEP's power marketing and trading operations subsequent to the AEP CSW merger and a reduction in depreciation and amortization expense. CPL shares in the results of power marketing and trading activities conducted on its behalf by the AEP System. Income statement line items which changed significantly were: Increase (Decrease) ------------------- (in millions) % ------------- - Operating Revenues $287 91 Fuel Expense 62 70 Purchased Power Expense 194 N.M. Depreciation and Amortization (12) (22) Taxes Other Than Federal Income Taxes 2 11 Federal Income Taxes 14 322 N.M. = Not Meaningful The significant increase in operating revenues resulted from higher fuel related revenues due to increased fuel and purchased power expense, increased energy sales to residential and commercial customers and the post merger favorable impact of AEP's power marketing and trading operations, which added new wholesale revenues. 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 rise in purchased power expense was primarily attributable to participation in AEP's trading operation. The decrease in depreciation and amortization is due primarily to a decrease in depreciation associated with the cessation in July 2000 of accelerated ECOM depreciation on STP and reduced accruals for excess earnings. Taxes other than federal income taxes increased due to a favorable accrual adjustment in 2000 for ad valorem taxes. The increase in federal income tax expense attributable to operations in 2001 was primarily due to an increase in pre-tax operating income. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) OPERATING REVENUES $603,412 $316,328 -------- -------- OPERATING EXPENSES: Fuel 151,853 89,397 Purchased Power 214,566 20,420 Other Operation 75,071 75,301 Maintenance 17,287 16,422 Depreciation and Amortization 42,391 54,198 Taxes Other Than Federal Income Taxes 19,488 17,534 Federal Income Taxes 18,604 4,406 ------ ----- TOTAL OPERATING EXPENSES 539,260 277,678 ------- ------- OPERATING INCOME 64,152 38,650 NONOPERATING INCOME 1,639 547 ----- --- INCOME BEFORE INTEREST CHARGES 65,791 39,197 INTEREST CHARGES 30,760 31,058 ------ ------ NET INCOME 35,031 8,139 PREFERRED STOCK DIVIDEND REQUIREMENTS 60 60 -- -- EARNINGS APPLICABLE TO COMMON STOCK $ 34,971 $ 8,079 ======== ======= CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $792,219 $758,894 NET INCOME 35,031 8,139 DEDUCTIONS: Cash Dividends Declared: Common Stock 37,014 39,000 Preferred Stock 60 60 Other 1 2 --- ------ BALANCE AT END OF PERIOD $790,175 $727,971 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.

E-6 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 2000 Net income increased $10.2 million or 37% due to increased trading volume and improved performance of the wholesale marketing and trading operations. CSPCo, as a member of the AEP Power Pool, shares in the revenues and costs of wholesale marketing and trading activities conducted on its behalf by the AEP Power Pool Income statement line items which changed significantly were: Increase (in millions) % ------------- - Operating Revenues $492 78 Fuel Expense 6 15 Purchased Power Expense 457 110 Other Operation Expense 9 20 Maintenance Expense 4 28 Depreciation and Amortization 7 28 Federal Income Taxes 4 23 Nonoperating Income 6 N.M. N.M. = Not Meaningful The significant increase in revenues is due to a 47% increase in electric trading volume. In the first quarter of 2001 the AEP Power Pool was able to expand the number of forward electricity contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory) resulting in the increase in trading volume. Fuel expense increased in the first quarter of 2001 due to the discontinuance of deferred fuel accounting on January 1, 2001 as a result of the restructuring of the electric utility industry in Ohio to provide customers with choice of generation supplier. Under deferred fuel accounting, changes in fuel costs were deferred until they were reflected in rates. In the three months ended March 31, 2000, the Company amortized over collections of fuel costs thereby reducing fuel expense commensurate with refunds of the over-collection to customers. The substantial increase in purchased power expense is primarily attributable to the increase in trading volume. Other operation expense increased due to power trading expenses and incentives, factored customer accounts receivable expenses and the cessation of amortizing deferred gains from sales of emission allowances to income as a result of the discontinuations of SFAS 71. Maintenance expenses increased in the first quarter of 2001 due to planned outages at two plants for steam boiler overhaul 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 accounted for the increase in depreciation and amortization expense. An increase in pre-tax operating income caused the Federal income taxes attributable to operations to increase. The increase in nonoperating income was due to an increase in net gains from AEP Power Pool trading transactions outside of the AEP System's traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. The Company's share of the AEP Power Pool's gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in nonoperating income. The increase reflects growth in and improved performance of the trading operations. The decline in interest charges was due to a decrease in the outstanding balance of long-term debt.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2001 December 31, 2000 -------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 24,000,000 Shares Outstanding - 16,410,426 Shares $ 41,026 $ 41,026 Paid-in Capital 573,607 573,354 Retained Earnings 115,486 99,069 ------- ------ Total Common Shareowner's Equity 730,119 713,449 Cumulative Preferred Stock - Subject to Mandatory Redemption 15,000 15,000 Long-term Debt 899,745 899,615 ------- ------- TOTAL CAPITALIZATION 1,644,864 1,628,064 --------- --------- OTHER NONCURRENT LIABILITIES 44,061 47,584 ------ ------ CURRENT LIABILITIES: Advances from Affiliates 102,209 88,732 Accounts Payable - General 88,530 89,846 Accounts Payable - Affiliated Companies 91,414 72,493 Taxes Accrued 124,400 162,904 Interest Accrued 24,491 13,369 Energy Trading Contracts 1,032,236 1,115,967 Other 55,625 60,701 ------ ------ TOTAL CURRENT LIABILITIES 1,518,905 1,604,012 --------- --------- DEFERRED INCOME TAXES 427,368 422,759 ------- ------- DEFERRED INVESTMENT TAX CREDITS 40,398 41,234 ------ ------ DEFERRED CREDITS 14,170 12,861 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 268,561 138,420 ------- ------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $3,958,327 $3,894,934 ========== ========== See Notes to Financial Statements beginning on page L-1.

F-6 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 2000 Net income increased $69 million primarily due to the return to service of both of I&M's Cook Plant nuclear units which were on an extended outage throughout 1999 and for a significant portion of 2000 because of questions regarding the operability of certain safety systems. Unit 2 and Unit 1 returned to service in June and December 2000, respectively. Income statement line items which changed significantly were: Increase (Decrease) ------------------- (in millions) % ------------- - Operating Revenues $583 82 Fuel Expense 16 34 Purchased Power Expense 522 116 Other Operation Expense (36) (27) Maintenance Expense (27) (49) Federal Income Taxes 35 N.M. N.M. = Not Meaningful The significant increase in operating revenues resulted from increased wholesale sales as sales to the AEP Power Pool increased by a multiple of 13 and I&M's share of sales to and forward trades with other utility systems and power marketers by the AEP Power Pool increased 53%. As a member of the AEP Power Pool, I&M shares in the revenues and costs of the AEP Power Pool's wholesale sales and forward trades. In the first quarter of 2001 the AEP Power Pool grew its trading operations resulting in an increase in the number of forward electricity contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory) resulting in the increase in trading volume. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. 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 the increase in wholesale 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 a major increase in pre-tax operating income.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $ 3,443 $166,389 NET INCOME (LOSS) 32,363 (36,553) DEDUCTIONS: Cash Dividends Declared: Common Stock - 26,290 Cumulative Preferred Stock 1,122 1,125 Capital Stock Expense 33 57 -- -- BALANCE AT END OF PERIOD $34,651 $102,364 ======= ======== See Notes to Financial Statements beginning on page L-1.

G-6 KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 2000 Although revenues rose 98% for the quarter, net income declined by $1.0 million or 12%, as increases in operating expenses more than offset the revenue increase. Income statement line items which changed significantly were: Increase (Decrease) ------------------- (in millions) % ------------- - Operating Revenues $228 98 Fuel Expense 1 7 Purchased Power Expense 226 135 Other Operation Expense 4 42 Maintenance Expense (1) (15) Nonoperating Income 3 N.M. N.M. = Not Meaningful The significant increase in revenues is due to a 64% increase in electric trading volume. In the first quarter of 2001 the AEP Power Pool grew its electric trading business resulting in a significant increase in the number of forward electricity contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory). The Company, as a member of the AEP Power Pool, shares with other Pool members in the revenues and costs of the AEP Power Pool's wholesale sales to and forward trades with other utility systems and power marketers. Fuel expense increased in the quarter due to increased generation from the Company's generating facilities as planned outages were reduced in 2001 compared with 2000. The Big Sandy Plant Unit 2 began a planned outage on March 11, 2000 for boiler inspections and repairs and returned to service late in April in 2000. The increase in purchased power expense was primarily attributable to the increase in trading volume. Other operation expense increased due to an increase in trading overhead expense and the cost of factoring of accounts receivable. The effect of the costs of the outages at Big Sandy Plant in 2000 caused maintenance expense to decrease in the quarter. The increase in nonoperating income was due to an increase in net gains from non-regulated AEP Power Pool trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures, swaps). The AEP Power Pool enters into power trading transactions including the forward purchase and sale of electricity and electricity options, futures and swaps. The Company's share of the AEP Power Pool's gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in nonoperating income. KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2001 2000 (in thousands) OPERATING REVENUES: $459,157 $231,454 -------- -------- OPERATING EXPENSES: Fuel 17,956 16,802 Purchased Power 393,865 167,732 Other Operation 14,728 10,384 Maintenance 5,429 6,367 Depreciation and Amortization 8,027 7,603 Taxes Other Than Federal Income Taxes 3,734 2,834 Federal Income Taxes 4,149 4,175 ----- ----- TOTAL OPERATING EXPENSES 447,888 215,897 ------- ------- OPERATING INCOME 11,269 15,557 NONOPERATING INCOME (LOSS) net 2,810 (46) ----- ---- INCOME BEFORE INTEREST CHARGES 14,079 15,511 INTEREST CHARGES 7,004 7,459 ----- ----- NET INCOME $ 7,075 $ 8,052 ========== ======= STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) NET INCOME $ 7,075 $8,052 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge (1,354) - ------ -- COMPREHENSIVE INCOME $ 5,721 $8,052 ======= ====== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2001 2000 (in thousands) BALANCE AT BEGINNING OF PERIOD $57,513 $67,110 NET INCOME 7,075 8,052 CASH DIVIDENDS DECLARED: Common Stock 7,561 7,590 ----- ----- BALANCE AT END OF PERIOD $57,027 $67,572 ======= ======= See Notes to Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2001 December 31, 2000 -------------- ---------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $ 270,651 $ 271,107 Transmission 364,356 360,563 Distribution 391,261 387,499 General 67,857 67,476 Construction Work in Progress 12,481 16,419 ------ ------ Total Electric Utility Plant 1,106,606 1,103,064 Accumulated Depreciation and Amortization 365,951 360,648 ------- ------- NET ELECTRIC UTILITY PLANT 740,655 742,416 ------- ------- OTHER PROPERTY AND INVESTMENTS 6,300 6,559 ----- ----- LONG-TERM ENERGY TRADING CONTRACTS 141,170 76,657 ------- ------ CURRENT ASSETS: Cash and Cash Equivalents 1,291 2,270 Accounts Receivable: Customers 27,918 34,555 Affiliated Companies 20,181 22,119 Miscellaneous 4,763 6,419 Allowance for Uncollectible Accounts (278) (282) Fuel - at average cost 4,425 4,760 Materials and Supplies - at average cost 16,093 15,408 Accrued Utility Revenues 3,257 6,500 Energy Trading Contracts 465,526 483,537 Prepayments 901 766 --- --- TOTAL CURRENT ASSETS 544,077 576,052 ------- ------- REGULATORY ASSETS 99,474 98,515 ------ ------ DEFERRED CHARGES 9,835 11,817 ----- ------ TOTAL ASSETS $1,541,511 $1,512,016 ========== ========== See Notes to Financial Statements beginning on page L-1.

KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income $7,075 $8,052 Adjustments for Noncash Items: Depreciation and Amortization 8,029 7,605 Deferred Federal Income Taxes 4,194 1,961 Deferred Investment Tax Credits (297) (298) Deferred Fuel Costs (net) (1,271) (1,580) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 10,227 (105) Fuel, Materials and Supplies (350) (797) Accrued Utility Revenues 3,243 3,274 Accounts Payable 3,177 (2,334) Taxes Accrued (3,691) 713 Interest Accrued 2,366 2,356 Change in Energy Trading Contracts (net) (15,775) 5,041 Other 3,218 (5,950) ----- ------ Net Cash Flows From Operating Activities 20,145 17,938 ------ ------ INVESTING ACTIVITIES: Construction Expenditures (5,746) (7,573) Proceeds from Sales of Property 216 - --- ------ Net Cash Flow Used for Investing Activities (5,530) (7,573) ------ ------ FINANCING ACTIVITIES: Change in Short-term Debt (net) - (2,065) Change in Advances from Affiliates (net) (8,033) - Dividends Paid (7,561) (7,590) ------ ------ Net Cash Flows Used For Financing Activities (15,594) (9,655) ------- ------ Net Increase (Decrease) in Cash and Cash Equivalents (979) 710 Cash and Cash Equivalents at Beginning of Period 2,270 674 ----- --- Cash and Cash Equivalents at End of Period $1,291 $ 1,384 ====== ======= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $4,529,000 and $5,029,000 and for income taxes was $4,354,000 and $2,001,000 in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $661,000 and $374,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. H-7 OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 2000 Net income increased $7.2 million or 16% in the first quarter of 2001 mainly due to strong performance by the trading operation offset in part by the commencement of accelerated amortization of transition regulatory assets. OPCo, as a member of the AEP Power Pool, shares in the revenues and costs of wholesale marketing and trading activities conducted on its behalf by the AEP Power Pool. Income statement line items which changed significantly were: Increase (Decrease) ------------------- (in millions) % ------------- - Operating Revenues $652 62 Fuel Expense (15) (7) Purchased Power Expense 641 119 Maintenance Expense 7 26 Depreciation and Amortization 22 56 Taxes Other Than Federal Income taxes (3) (7) Federal Income Taxes 3 7 Nonoperating Income 15 N.M. N.M. = Not Meaningful The significant increase in revenues is due to a 41% increase in electric trading volume. In the first quarter of 2001 the AEP Power Pool grew its trading operations resulting in the expension of the number of forward electricity contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory). Fuel expense decreased in the first quarter of 2001 due mainly to a drop in the cost per ton of fuel and decreased shutdown costs for affiliated mining operations. The Company discontinued the practice of deferred fuel accounting due to the deregulation of the electric utility industry on January 1, 2001 as a result of the restructuring the electric utility industry in Ohio to provide customers with a choice of generation supplier. Under deferred fuel accounting, changes in fuel costs were deferred until they were reflected in rates. As a result of the cessation of deferred fuel cost accounting commensurate with the termination of the Ohio fuel clause, the Company is subject to the effect of changes in the price of fuel it uses to generate electricity. The increase in purchased power expense was primarily attributable to the increase in trading volume. Maintenance expenses increased due to steam boiler inspections and overhauls at various plants. The commencement of accelerated amortization of transition regulatory assets in connection with the transition to customer choice and market-based pricing of electricity accounted for the increase in depreciation and amortization expense. A decline in the gross receipts tax caused taxes other than federal income taxes to decrease. The gross receipts tax decreased due to an increase from $1 per ton to $3 per ton in a state tax credit for the use of Ohio coal. The increase in Federal income taxes attributable to operations was primarily due to changes in certain book/tax timing differences accounted for on a flow-through basis offset in part by a decrease in pre-tax operating book income. The increase in nonoperating income was due to an increase in net gains from AEP Power Pool trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures, swaps). The AEP Power Pool enters into power trading transactions including the forward purchase and sale of electricity and electricity options, futures and swaps. The Company's share of the AEP Power Pool's gains and losses from forward electricity trading transactions outside of the AEP System's traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in nonoperating income.

OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $398,086 $587,424 NET INCOME 53,397 46,216 CASH DIVIDENDS DECLARED: Common Stock 35,744 37,703 Cumulative Preferred Stock 314 317 --- --- BALANCE AT END OF PERIOD $415,425 $595,620 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.

I-5 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 2000 The Company had a loss of $1.6 million for the first quarter of 2001 compared with net income of $1.2 million for the first quarter of 2000. The loss was primarily a result of increased maintenance expense due to damage caused by a large winter ice storm and increased interest costs. Income statement line items which changed significantly were: Increase (Decrease) ------------------- (in millions) % ------------- - Operating Revenues $195 121 Fuel Expense 40 56 Purchased Power Expense 146 706 Other Operation Expense 11 45 Maintenance Expense 1 14 Federal Income Taxes (2) 542 Interest Charges 1 6 The significant increase in operating revenues was due to participation in power marketing and trading activities conducted on its behalf by the AEP System. Revenues were also impacted by the absence of a 2000 adjustment of the Company's portion of a FERC-approved Transmission Coordination Agreement, which had decreased revenues in 2000 and decreased 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 the increase in trading volume. Other operation expenses increased due mainly to the absence of a 2000 favorable adjustment for the FERC-approved Transmission Coordination Agreement mentioned above, along with increased power trading and transmission expenses. Maintenance expense increased for the quarter due primarily to increased expenses to repair damage to overhead lines caused by a winter storm. Income tax expense associated with utility operations decreased as a result of a decrease in pre-tax book income. Interest charges increased reflecting the issuance of one year floating rate notes in November 2000 and additional short-term borrowings.

J-5 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2001 vs. FIRST QUARTER 2000 Net income increased $12.2 million, or 159%, for the first quarter of 2001. The increase for the quarter resulted primarily from increased average wholesale prices and the favorable impact of AEP's power marketing and trading operations. SWEPCo participates in power marketing and trading activities conducted on its behalf by the AEP System. Income statement line items which changed significantly were: Increase (in millions) % ------------- - Operating Revenues $214 101 Fuel Expense 29 32 Purchased Power Expense 157 N.M. Other Operation Expense 5 13 Maintenance Expense 1 7 Taxes Other Than Federal Income Taxes 4 34 Federal Income Taxes 6 N.M. N.M. = Not Meaningful The increase in operating revenues resulted from higher fuel related revenues due to increased fuel and purchased power expense due to the fuel clause mechanism, increased retail energy sales due to increased usage and the post merger favorable impact of AEP's power marketing and trading operations, which added new wholesale revenues. 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 increase in purchased power expense was primarily caused by the participation in AEP's trading operation, an increase in economy energy purchases and increased firm energy contract purchases. Other operation expense increased for the quarter as a result of an unfavorable accounts receivable write-off, SWEPCo's share of power trading expenses that did not exist prior to the merger and increased transmission services expense. Maintenance expense for the first quarter of 2001 increased as a result of severe ice storms, offset in part by reduced overhead line maintenance and tree-trimmings. The increase in taxes other than federal income taxes was due to a favorable adjustment of ad valorem taxes recorded in the first quarter of 2000. The increase in federal income tax expense attributable to operations was primarily due to an increase in pre-tax operating income. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) OPERATING REVENUES $425,689 $212,156 -------- -------- OPERATING EXPENSES: Fuel 118,246 89,352 Purchased Power 168,857 11,698 Other Operation 39,268 34,698 Maintenance 15,236 14,306 Depreciation and Amortization 28,130 27,357 Taxes Other Than Federal Income Taxes 14,266 10,661 Federal Income Taxes 7,700 1,353 ----- ----- TOTAL OPERATING EXPENSES 391,703 189,425 ------- ------- OPERATING INCOME 33,986 22,731 NONOPERATING INCOME (LOSS) 247 (233) --- ---- INCOME BEFORE INTEREST CHARGES 34,233 22,498 INTEREST CHARGES 14,364 14,835 ------ ------ NET INCOME 19,869 7,663 PREFERRED STOCK DIVIDEND REQUIREMENTS 57 57 -- -- EARNINGS APPLICABLE TO COMMON STOCK $ 19,812 $ 7,606 ========= ======= CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $293,989 $283,546 NET INCOME 19,869 7,663 CASH DIVIDENDS DECLARED: Common Stock 18,553 15,501 Preferred Stock 57 57 -- -- BALANCE AT END OF PERIOD $295,248 $275,651 ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2001 December 31, 2000 -------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $1,425,061 $1,414,527 Transmission 523,948 519,317 Distribution 1,007,999 1,001,237 General 326,967 325,948 Construction Work in Progress 49,587 57,995 ------ ------ Total Electric Utility Plant 3,333,562 3,319,024 Accumulated Depreciation and Amortization 1,474,266 1,457,005 --------- --------- NET ELECTRIC UTILITY PLANT 1,859,296 1,862,019 --------- --------- OTHER PROPERTY AND INVESTMENTS 40,731 39,627 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 19,916 63,028 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 2,515 1,907 Accounts Receivable: Customers 10,507 41,399 Affiliated Companies 20,642 11,419 Fuel Inventory - at average cost 39,677 40,024 Under-recovered Fuel 42,106 35,469 Materials and Supplies - at average cost 26,146 25,137 Energy Trading Contracts 40,171 457,936 Prepayments 15,730 16,780 ------ ------ TOTAL CURRENT ASSETS 197,494 630,071 ------- ------- REGULATORY ASSETS 53,503 57,082 ------ ------ DEFERRED CHARGES 34,511 10,707 ------ ------ TOTAL ASSETS $2,205,451 $2,662,534 ========== ========== See Notes to Financial Statements beginning on page L-1.

K-6 WEST TEXAS UTILITIES COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS -------------------------------------------------------- FIRST QUARTER 2001 vs. FIRST QUARTER 2000 Net income decreased $2.9 million or 77% for the quarter. This decrease was primarily due to the absence of an excess earnings adjustment made in 2000 which had increased net income by $2.1 million in 2000. This adjustment was made to true up the 1999 excess earnings accrual to the actual report filed in March 2000. No such adjustment was required in 2001. Income statement line items which changed significantly were: Increase (Decrease) ------------------- (in millions) % ------------- - Operating Revenues $98 102 Fuel Expense 31 110 Purchased Power Expense 67 449 Other Operation Expense 5 27 Taxes Other Than Federal Income Taxes 1 22 Federal Income Taxes (2) (106) Nonoperating Income 2 N.M. N.M. = Not Meaningful The significant increase in operating revenues was due mostly to the post merger favorable impact of AEP's power marketing and trading operations, which added new wholesale revenues. Revenues were also impacted by the absence of a 2000 adjustment of the Company's portion of a FERC-approved Transmission Coordination Agreement, which had decreased revenues in 2000 and decreased 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. The increase in fuel expense was due primarily to an increase in the average unit cost of fuel as a result of higher spot market natural gas prices. The significant rise in purchased power expense was primarily attributable to participation in AEP's trading operation and the impact of natural gas prices on wholesale purchased power prices. The increase in other operation expense was due mainly to the absence in 2001 of a favorable adjustment made in 2000 related to the FERC-approved Transmission Coordination Agreement. The increase in taxes other than federal income taxes for the quarter was primarily due to higher ad valorem taxes. Federal income taxes attributable to operations decreased due primarily to a decrease in pre-tax income. The increase in nonoperating income was due primarily from interest income on under-recovered fuel. WTU has been experiencing natural gas fuel price increases which have resulted in under-recoveries of fuel costs and the need to seek increases in fuel rates and surcharges including accumulated interest on under-recovered balances. On January 1, 2002 the fuel recovery mechanism will cease in Texas subjecting WTU to the risk of changes in the market price of gas used to generate electricity. WEST TEXAS UTILITIES COMPANY STATEMENTS OF INCOME (UNAUDITED) ree Months Ended March 31, 2001 2000 ---- ---- (in thousands) OPERATING REVENUES $195,006 $96,535 -------- ------- OPERATING EXPENSES: Fuel 59,905 28,580 Purchased Power 81,692 14,893 Other Operation 25,756 20,304 Maintenance 4,562 4,862 Depreciation and Amortization 11,771 11,241 Taxes Other Than Federal Income Taxes 6,038 4,963 Federal Income Taxes 1,911 ----- (110) TOTAL OPERATING EXPENSES 189,614 86,754 ------- ------ OPERATING INCOME 5,392 9,781 NONOPERATING INCOME (LOSS) 1,431 (91) ----- --- INCOME BEFORE INTEREST CHARGES 6,823 9,690 INTEREST CHARGES 5,932 5,857 ----- ----- NET INCOME 891 3,833 PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26 --- -- EARNINGS APPLICABLE TO COMMON STOCK $ 865 $ 3,807 ========= ======= STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2001 2000 ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $122,588 $113,242 NET INCOME 891 3,833 DEDUCTIONS: Cash Dividends Declared: Common Stock 7,206 4,500 Preferred Stock 26 26 --- -- BALANCE AT END OF PERIOD $116,247 $112,549 ======== ======== The common stock of the Company is wholly owned by AEP. 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 expense amounts were reclassified from revenues to purchased power expense to present the prior period on a comparable basis. Three Months Ended March 31, 2000 Company (in thousands) AEP $3,100,000 APCo 566,083 CSPCo 334,999 I&M 364,164 KPCo 134,250 OPCo 502,426 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. RISK MANAGEMENT AND RELATED ACCOUNTING Risk Management AEP and its registrant subsidiaries are subject to market risk as a result of changes in commodity prices, foreign currency exchange rates, and interest rates. AEP has wholesale electricity and gas trading and marketing operations that manage the exposure to commodity price movements while entering into physical forward purchase and sale contracts at fixed and variable prices, and financial derivative instruments including exchange traded futures and options, over-the-counter options, swaps and other financial derivative contracts at both fixed and variable prices to create shareholder value. Risks of foreign currency fluctuations arise from investments in foreign energy companies and projects and equipment purchases denominated in foreign currencies. AEP does not presently utilize derivatives to manage its exposures to foreign currency exchange rate movements for its investments in foreign energy companies and projects. For equipment purchases and energy trading transactions denominated in foreign currencies, forward contracts have been utilized to manage the exposure to fluctuations in foreign currency exchange rates. AEP, APCo, and OPCo have entered into foreign currency hedge contracts to manage the exposure to changes in foreign currency rates on assets purchased. Short and long-term borrowings used to fund business operations expose AEP and its registrant subsidiaries to risk from changes in interest rates. AEP, KPCo, and I&M have entered into cash flow hedge contracts to manage the exposure to changes in interest rates on variable interest rate debt and the changes in interest rates on fixed rate debt issuances. Certain of AEP's foreign subsidiaries employ hedging transactions in order to mitigate the risks of commodity market prices, foreign currency and interest rate fluctuations. CitiPower utilizes interest rate swaps and forward commodity contracts to hedge the risks of market price and interest rate fluctuations. Certain of CitiPower's commodity contracts are not designated as hedges and are marked-to-market. Currency swaps are used by CSW International to hedge debt transactions issued in foreign currencies. The majority of SEEBOARD's power and gas contracts are considered as normal purchases and sales. Accounting In the first quarter of 2001, AEP adopted Statement of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 137 and SFAS 138. SFAS 133 requires that entities recognize all derivatives as either assets or liabilities and measure such derivatives at fair value. Changes in the fair value of derivatives that are effective cash flow hedges are included in other comprehensive income. AEP recorded a favorable transition adjustment to accumulated other comprehensive income of $27 million at January 1, 2001 in connection with the adoption of SFAS 133. AEP and its registrant subsidiaries have significant domestic energy trading contracts that have been marked-to-market and accounted for under EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". Therefore, the adoption of SFAS 133 did not require transition adjustments for AEP and its registrant subsidiaries' open energy trading contracts. AEP contracts identified in the SFAS 133 transition adjustment, include interest rate swaps, foreign currency swaps, and commodity swaps, options and futures, the vast majority of which were designated as cash flow hedges and relate to foreign operations. Subsequent to recording the transition adjustment FASB approved guidance indicating that contracts with option features cannot qualify for the normal purchases and normal sales exception under SFAS 133, as amended. This guidance, which is effective in the third quarter of 2001, is expected to have a favorable effect on earnings assuming that market prices do not decline. The FASB recently issued tentative guidance on two issues with significant impacts on the electric industry. Such tentative guidance states that energy capacity contracts that include certain characteristics of purchased and written options and that derivative contracts which do not result in physical delivery of power because of transmission scheduling, referred to as bookouts, cannot meet the normal purchases and normal sales exception. While AEP believes that the majority of its electricity capacity contracts qualify as normal purchases and sales and that bookouts result in simultaneous delivery, passage of title, and settlement on a gross basis and are, therefore, physical normal purchase and sale transactions, the ultimate resolution of these electric industry issues could have a material effect on reported earnings. The electric industry and AEP are activity working with the FASB to resolve these issues. Contracts that qualify as derivatives under SFAS 133 are reported on the consolidated balance sheets at fair value. Open derivative contracts are fair valued with unrealized gains reported as assets and unrealized losses reported as liabilities. Cash flows from both derivative instruments and trading activities are included in net cash flows from operating activities. Certain derivatives may be designated for accounting purposes as a hedge of either the fair value of an asset, liability or firm commitment, or a hedge of the variability of cash flows related to a variable-priced asset, liability, commitment or forecasted transaction. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy for use of the hedge instrument. At the inception of the hedge and on an ongoing basis, the effectiveness of the hedge is assessed as to whether the hedge is highly effective in offsetting changes in fair value or cash flows. Changes in the fair value that result from ineffectiveness under SFAS 133 are recognized currently in earnings. Changes in the fair value of fair value hedges offset changes in the fair value of the hedged items to the extent the hedge is effective. Changes in the fair value of effective cash flows hedges are reported in accumulated other comprehensive income if documented at inception. Gains and losses from cash flow hedges in other comprehensive income are reclassified to earnings in periods in which the variability of cash flows of the hedged items affect earnings. The following chart represents the various cash flow hedge derivative positions of AEP and its registrant companies at March 31, 2001:

The following table represents the activity in Other Comprehensive Income related to the effect of adopting SFAS 133 for derivative contracts that qualify as cash flow hedges during the first quarter of 2001 (in thousands): AEP consolidated Transition Adjustment, January 1, 2001 $26,795 Effective portion of change in fair value 9,462 Reclass from OCI to net income (22,835) ------- Accumulated OCI derivative gain $13,422 ======= APCo Transition Adjustment, January 1, 2001 $ - Effective portion of change in fair value (417) Reclass from OCI to net income - ----- Accumulated OCI derivative loss $(417) ===== KPCo Transition Adjustment, January 1, 2001 $ (557) Effective portion of change in fair value (764) Reclass from OCI to net income (33) ------- Accumulated OCI derivative loss $(1,354) ======= I&M Transition Adjustment, January 1, 2001 $ (317) Effective portion of change in fair value (1,405) Reclass from OCI to net income (197) ------- Accumulated OCI derivative loss $(1,919) ======= OPCo Transition Adjustment, January 1, 2001 $ - Effective portion of change in fair value (220) Reclass from OCI to net income - ----- Accumulated OCI derivative loss $(220) ===== Approximately $2 million of net gains from hedge derivatives in accumulated other comprehensive income at March 31, 2001 is expected to be reclassified to net income in the next twelve months by AEP. KPCo and I&M estimate that approximately $0.6 million and $1.9 million, respectively, of net losses in accumulated other comprehensive income will be reclassified to net income in the next twelve months. The actual amounts reclassified from accumulated other comprehensive income to net income can differ as a result of market price changes. The maximum term for which the exposure to the variability of future cash flows is being hedged is up to 5 years for AEP and up to one year for APCo and OPCo. 3. SALES OF ASSETS Sale of Generating Assets - Affecting AEP As discussed in Note 3 of the Notes to Financial Statements in the 2000 Annual Report, the divestiture of 1,904 MW of generating capacity was required by the FERC and the PUCT as part of the approval of the merger. In March 2001, AEP completed the sale of Frontera, one of the generating plants required to be divested under the settlement agreements approved by the FERC. The sale proceeds were $265 million and resulted in an after tax gain of $46 million. Sale of Yorkshire Investment - Affecting AEP In December 2000 AEP entered into negotiations to sell its 50% investment in Yorkshire, a U.K. electricity supply and distribution company. On February 26, 2001, an agreement to sell AEP's interest in Yorkshire was signed and resulted in a $30 million after tax net loss from the expected sale being recorded in 2000. On April 2, 2001, following the approval of the buyer's shareholders, the sale was completed without further impact on AEP's consolidated earnings. Proposed Sale of Affiliated Coal Mines - Affecting AEP and OPCo On April 30, 2001, AEP announced that it had entered into a memorandum of understanding regarding a proposed sale of OPCo's affiliated coal mines in Ohio and West Virginia. In addition, OPCo would enter into coal supply agreements to purchase approximately 34 million tons of coal through 2008. The terms of the sale are being negotiated and management will continue to evaluate the transaction. Management is unable to estimate the impact of the proposed sale on results of operations. 4. RATE MATTERS As discussed in Note 5 of the Notes to Financial Statements in the 2000 Annual Report, AEP's Texas electric operating companies have been experiencing natural gas fuel price increases which have resulted in under-recoveries of fuel costs and the need to seek increases in fuel rates and surcharges to recover these amounts. In January 2001 CPL filed with the PUCT an application to implement an increase in fuel factors of $175.9 million, effective with the March 2001 billing month over the ten months March 2001 through December 2001. Additionally, CPL proposed to implement an interim fuel surcharge of $51.8 million, including accumulated interest, over a nine-month period beginning in April 2001 to collect its under-recovered fuel costs. In March 2001, pursuant to an interim order of an Administrative Law Judge adopting a settlement of the fixed fuel factor portion of the application, CPL implemented a $170.5 million increase in fixed fuel factors. In April 2001 the PUCT approved the settlement fixed fuel factors. In addition, in April 2001 the PUCT voted to defer implementation of the requested fuel surcharge until CPL's final fuel reconciliation as part of a 2004 true-up proceeding. CPL has requested a rehearing on the surcharge denial. In January 2001 WTU filed an application with the PUCT to implement an increase in fuel factors of $46.5 million effective with the March 2001 billing month. In March 2001 pursuant to an interim order of an Administrative Law Judge adopting a settlement of the fixed fuel factor portion of the application, WTU implemented the increase in fixed fuel factors. In April 2001, the PUCT approved the new WTU fixed fuel factors. In March 2001 WTU filed a request with the PUCT for authority to implement a surcharge of fuel cost under-recoveries totaling $59.5 million including interest. The under-recoveries were incurred during the period July 2000 through January 2001. The request is seeking to surcharge the under-recovered fuel costs during the period May 2001 through December 2001. A decision on the WTU fuel surcharge request is pending. Based upon the decision in the CPL fuel surcharge proceeding, management expects the PUCT may defer recovery of the WTU fuel surcharge until the 2004 true-up proceeding when WTU would have a final fuel reconciliation. In June 2000 SWEPCo had filed with the PUCT an application to reconcile fuel costs and to request authorization to carry the unrecovered balance forward into the next reconciliation period. As discussed in the 2000 Annual Report, a settlement was reached in December 2000 and approved by the PUCT in February 2001 which did not have a material effect on results of operations. In November 2000 SWEPCo filed an application with the PUCT for authority to implement an increase in fuel factor revenues effective with the January 2001 billing month. SWEPCo also proposed to implement an interim fuel surcharge to collect its under-recovered fuel costs including accumulated interest, over a six-month period beginning in January 2001. The PUCT approved SWEPCo's application in January 2001. The order allows an increase in fuel factors of $12 million on an annual basis beginning in January 2001 and a surcharge of $11.8 million including accumulated interest for the billing months of February through July 2001. In May 2001 SWEPCo filed to increase fixed fuel factors by $4.3 million and to surcharge fuel under-recoveries for the period October 2000 through March 2001 of $18.3 million, including interest. Based upon the decision in the CPL fuel surcharge proceeding, management expects the PUCT may defer recovery of the SWEPCo fuel surcharge until the 2004 true-up proceeding when SWEPCo would have a final fuel reconciliation. Beginning January 1, 2002, fuel costs will no longer be subject to PUCT fuel reconciliation proceedings under the Texas Restructuring Legislation. Consequently, 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. Fuel costs have been reconciled by CPL, SWEPCo and WTU through June 30, 1998, December 31, 1999 and June 30, 1997, respectively. WTU is currently reconciling its fuel through June 2000. At March 31, 2001, CPL's, SWEPCo's and WTU's Texas jurisdictional unrecovered deferred fuel balances were $125 million, $25.4 million and $66.8 million, respectively. As discussed above, the remaining balances on CPL, SWEPCo, and WTU current fuel surcharges at March 31, 2001 are $45 million, $6.5 million and $9.5 million, respectively. Final unrecovered deferred fuel balances at December 31, 2001 will be included in each company's 2004 true-up proceeding. If the final fuel balances or any amount incurred but not yet reconciled are not recovered, it would have a negative impact on results of operations. 5. INDUSTRY RESTRUCTURING As discussed in the 2000 Annual Report, restructuring legislation has been enacted in seven of the eleven state retail jurisdictions in which the AEP domestic electric utility companies operate. The legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the supply of electricity. The following paragraphs discuss significant events occurring in 2001 related to industry restructuring. Ohio Restructuring - Affecting AEP, CSPCo and OPCo Effective January 1, 2001, customer choice of electricity supplier began under the Ohio Act. In February 2001, one supplier announced its plan to offer service to CSPCo's residential customers. Currently for residential customers of OPCo, no alternative suppliers have registered with the PUCO under the Ohio Act. Alternative suppliers have been approved to compete for CSPCo's and OPCo's commercial and industrial customers. Presently, virtually all customers continue to be served by CSPCo and OPCo with a legislatively required residential rate reduction of 5% for the generation portion of rates and frozen transition generation rates including fuel rates from January 1, 2001 to December 31, 2005 for all classes of customers. As discussed in Note 7 of the Notes to Financial Statements in the 2000 Annual Report, CSPCo and OPCo filed an appeal with the Ohio Supreme Court related to a tax expense issue which would result in duplicate expense of $40 million and $50 million, respectively, for a twelve month period beginning on May 1, 2001. One of the items CSPCo and OPCo requested was a stay of the PUCO ordered implementation date (May 1, 2001) for an excise tax credit rider. On April 13, 2001, the Ohio Supreme Court denied the companies' stay request. Management does not expect the Ohio Supreme Court to hear arguments on the merits of this case until the fourth quarter of 2001. One of the intervenors at the hearings for approval of a transition settlement agreement (whose request for rehearing was denied by the PUCO) has filed with the Ohio Supreme Court for review of the settlement agreement including CSPCo's and OPCo's recovery of their transition generation-related regulatory assets. Management is unable to predict the outcome of litigation. The resolution of this matter could negatively impact future results of operation. Virginia Restructuring - Affecting AEP and APCo In connection with a Virginia law that provides for a transition to choice of electricity supplier for retail customers beginning on January 1, 2002 (which is described in Note 7 of the Notes to Financial Statements in the 2000 Annual Report), APCo was required to make a filing with the Virginia SCC to unbundle rates and separate generation from transmission and distribution. On January 3, 2001, APCo filed its corporate separation plan and rate unbundling plan with the Virginia SCC, which included a 1999 cost of service study required by the Virginia SCC's regulations. That filing indicated that additional information about APCo's proposed corporate separation plan would be filed at a later date. On April 11, 2001, the Virginia SCC directed APCo to file the additional information required to complete its corporate separation filing when that information becomes available. APCo was also directed to file, by May 15, 2001, all information necessary for the Virginia SCC to fully consider a functional separation of APCo, by divisions. If in connection with the transition process, the Virginia SCC were to reduce APCo's rates or deny recovery of generation-related regulatory assets, it would have an adverse effect on results of operations. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999 legislation was enacted in Arkansas that will ultimately restructure the electric utility industry. In February 2001 the Arkansas General Assembly passed legislation that was signed into law by the Governor that extended the date for electric retail 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 The Texas Restructuring Legislation gives Texas customers of investor-owned utilities 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, if any, including the final fuel recovery, net regulatory asset recovery, certain environmental costs, accumulated 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 has been controversial. During 2000 CPL submitted estimates of stranded costs and the PUCT held hearings. In February 2001 the PUCT issued 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 that it has a stranded benefit 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 would be used to reduce stranded cost. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. The PUCT currently estimates that CPL will have no stranded cost and has ordered the rate reduction to return excess earnings, pending the outcome of the 2004 true-up proceeding. 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 and 2000. Consequently, the April order has no effect on reported net income. A Texas settlement agreement in connection with the AEP and CSW merger permits CPL to apply for regulatory purposes up to $20 million of previously identified STP ECOM plant assets a year in 2000 and 2001 to reduce excess earnings, if any. For book purposes, STP ECOM plant assets will be depreciated in accordance with GAAP, on a systematic and rational basis unless impaired. 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. Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel reconciliation proceedings. Consequently, CPL, SWEPCo and WTU will file a final fuel reconciliation with the PUCT which reconciles their fuel costs through the period ending December 31, 2001. These final fuel balances will be included in each company's 2004 true-up proceeding. The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to the risk of fuel market price increases and could adversely affect future results of operations beginning in 2002. In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding to recover all or a portion of their generation-related regulatory assets, unrecovered fuel balances, stranded costs and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. 6. BUSINESS SEGMENTS AEP has three principal business segments: wholesale, energy delivery, and other investments. The wholesale segment is comprised of the generation component of electricity sales to domestic retail and wholesale customers, worldwide electric and gas trading and other energy supply related businesses. Energy delivery includes the electric transmission and distribution operations of the domestic electric operating companies. Investments in foreign electric distribution and supply companies, generation facilities outside of the United States and telecommunication services make up the other investments segment. All of the registrant subsidiaries except AEGCo have two business segments, wholesale and energy delivery. AEGCo has one segment, a wholesale generation business. The presentation of wholesale and energy delivery segments reflects management intention, announced in the fourth quarter of 2000, to functionally and structurally separate its operations into non-regulated and regulated businesses. Separation of AEP's regulated bundled generation, transmission and distribution operations into an unbundled non-regulated wholesale business and a regulated unbundled energy delivery business will not be completed until the required regulatory approvals are obtained. The electric operating subsidiaries operating in states that are deregulating the supply business will be structurally separated and the remaining subsidiaries will be functionally separated. The amounts reported for 2000 have been reclassified to conform to the current period's presentation. The amounts shown for the three business segments reported by AEP include certain estimates and allocations where necessary.

7. FINANCING AND RELATED ACTIVITIES In the first quarter of 2001, the AEP System issued $40 million of notes payable due in 2004 with an interest rate of 6.73% and increased the level of borrowing under the SEEBOARD Revolving Credit Facility by $89 million. Retirements of debt were: first mortgage bonds totaling $120 million with interest rates ranging from 5.91% to 6-3/8% due in 2001 and $61 million notes payable with interest rates ranging from 6.20% to 7.5625% due in 2001. The following table lists long-term debt retirements during the first quarter of 2001 by the registrant subsidiaries: Principal Type Amount Interest Due Company of Debt Retired Rate Date ------- ------- ----------- -------- ---- (in millions) (%) APCo FMB $100 6-3/8 March 1, 2001 OPCo NP 30 6.20 January 31, 2001 PSO FMB 6 5.91 March 1, 2001 PSO FMB 5 6.02 March 1, 2001 PSO FMB 9 6.02 March 1, 2001 In March 2001 I&M paid $92.6 million to purchase leased nuclear fuel from an unaffiliated company reflecting management's decision to discontinue its policy of leasing all nuclear fuel for the Cook Plant. The purchase was financed with funds from operations. CPL redeemed $500,000 of its 8.00% trust preferred securities on February 1, 2001. 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 is 6.125% and they are due in May 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. In the event the Series B notes are not called for remarketing, AEP must redeem them. In January 2001 APCo became a participant in AEP's money pool and retired all outstanding short-term debt. The Money Pool coordinates short-term borrowings for certain AEP System subsidiaries, primarily the domestic electric utility operating companies. The operation of the Money Pool is designed to match on a daily basis the available cash and borrowing requirements of the participants, thereby minimizing the need for short-term borrowings from external sources and increasing the interest income for participants with available cash. Participants with excess cash loan funds to the Money Pool reducing the amount of external funds AEP needs to borrow to meet the short-term cash requirements of other participants whose short-term cash requirements are met through advances from the Money Pool. AEP borrows the funds on a daily basis, when necessary, to meet the net cash requirements of the Money Pool participants. A weighted average daily interest rate which is calculated based on the outstanding short-term debt borrowings made by AEP is applied to each Money Pool participant's daily outstanding investment or debt position to determine interest income or interest expense. Money Pool participants include interest income in nonoperating income and interest expense in interest charges. APCo reports its borrowings from the Money Pool as Advances from Affiliates. In March 2001 APCo commenced factoring customer accounts receivable and accrued utility revenue balances to an affiliate, AEP Credit, Inc. Under the factoring arrangement APCo sells without recourse certain of its customer accounts receivable and accrued utility revenue balances to AEP Credit, Inc. and is charged a fee based on AEP Credit, Inc.'s financing costs, uncollectible accounts experience for APCo's receivables and administrative costs. The cost of factoring is included in other operation expense. At March 31, 2001 the amount of APCo's factored accounts receivable and accrued utility revenues was $78 million. 8. CONTINGENCIES Litigation Shareholders' Litigation - Affecting AEP On June 23, 2000, a complaint was filed in the U.S. District Court for the Eastern District of New York seeking unspecified compensatory damages against AEP and four former or present officers. The individual plaintiff also seeks certification as the representative of a class consisting of all persons and entities who purchased or otherwise acquired AEP common stock between July 25, 1997, and June 25, 1999. The complaint alleges that the defendants knowingly violated federal securities laws by disseminating materially false and misleading statements concerning, among other things, the undisclosed materially impaired condition of the Cook Plant, AEP's inability to properly monitor, manage, repair, supervise and report on operations at the Cook Plant and the materially adverse conditions these problems were having, and would continue to have, on AEP's deteriorating financial condition, and ultimately on AEP's operations, liquidity and stock price. Four other similar class action complaints have been filed and the court has consolidated the five cases. The plaintiffs filed a consolidated complaint pursuant to this court order. This case has been transferred to the U.S. District Court for the Southern District of Ohio. On March 5, 2001, AEP and the individual defendants filed a comprehensive motion to dismiss all claims against all defendents in the consolidated cases. The Court has set oral arguments of the motion for June 7, 2001. Although management believes these shareholder actions are without merit and intends to continue to oppose them vigorously, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. 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. During 1997, 1998 and 1999 the litigation moved procedurally through the Texas Court System and was sent to mediation without resolution. In 1999 a class notice was mailed to each of the cities served by CPL. Over 90 of the 128 cities declined to participate in the lawsuit. However, CPL has pledged that if any final, non-appealable court decision in the litigation awards a judgement against CPL for a franchise underpayment, CPL will extend the principles of that decision, with regard to any franchise underpayment, to the cities that declined to participate in the litigation. In December 1999, the court ruled that the class of plaintiffs would consist of approximately 30 cities. A trial date for October 2001 has been set. Although management believes that it has substantial defenses to the cities' claims and intends to defend itself against the cities' claims and pursue its counterclaims vigorously, 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 In November 1995 CPL filed with the PUCT a request to increase its retail base rates by $71 million. In October 1997 the PUCT issued a final order which lowered CPL's annual retail base rates by $19 million from the rate level which existed prior to May 1996. The PUCT also included a "glide path" rate methodology in the final order pursuant to which annual rates were reduced by $13 million beginning May 1, 1998 with an additional annual reduction of $13 million commencing on May 1, 1999. CPL appealed the final order to the Travis District Court. The primary issues being appealed include: the classification of $800 million of invested capital in STP as ECOM and assigning it a lower return on equity than other generation property; the use of the "glide path" rate reduction methodology; and an $18 million disallowance of service billings from an affiliate, CSW Services. As part of the appeal, CPL sought a temporary injunction to prohibit the PUCT from implementing the "glide path" rate reduction methodology. The temporary injunction was denied and the "glide path" rate reduction was implemented. In February 1999 the Travis District Court affirmed the PUCT order in regard to the three major items discussed above. CPL appealed the Travis District Court's findings to the Texas Appeals Court which in July 2000, issued its opinion upholding the Travis District Court except for the disallowance of affiliated service company billings. Under Texas law, specific findings regarding affiliate transactions must be made by PUCT. In regards to the affiliate service billing issue, the findings were not complete in the opinion of the Texas Appeals Court who remanded the issue back to PUCT. CPL has sought a rehearing of the Texas Appeals Court's opinion. The Texas Appeals Court has requested briefs related to CPL's rehearing request from interested parties. Management is unable to predict the final resolution of its appeal. If the appeal is unsuccessful the PUCT's 1997 order will continue to adversely affect results of operations and cash flows. As part of the AEP/CSW merger approval process in Texas, a stipulation agreement was approved which resulted in the withdrawal of the appeal related to the "glide path" rate methodology. CPL will continue its appeal of the ECOM classification for STP property and the disallowed affiliated service billings. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo As discussed in Note 8 of the Notes to Financial Statements in the 2000 Annual Report, SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO are each a 50% owner 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 U.S. District Court for the Western District of Louisiana. In April 2000, the parties agreed to settle the litigation. As part of the settlement, a subsidiary of SWEPCo will purchase DHMV's interest in the mining assets and will assume the related obligations for mine reclamation. The settlement agreement would give CLECO the option, beginning July 1, 2002, to acquire up to a 50% interest in the mining assets. The litigation has been stayed to provide the parties a reasonable period of time to complete the settlement process. Management believes that the resolution of this matter will not have a material effect on results of operations, cash flows or financial condition. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo 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. AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. In 1999 Notices of Violation were issued and complaints were filed by Federal EPA in various U.S. District Courts alleging APCo, CSPCo, I&M, OPCo and a number of unaffiliated utilities made modifications to generating units at certain of their coal-fired generating plants over the course of the past 25 years that extended unit operating lives or increased unit generating capacity without a preconstruction permit in violation of the Clean Air Act. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional generating units previously named only in the Notices of Violation in the complaint. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the AEP System under the Clean Air Act. A lawsuit against power plants owned by certain AEP System operating companies alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and has been consolidated with the Federal EPA action. 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). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts Federal EPA's contentions, could be substantial. In May 2000 the AEP System companies filed motions to dismiss all or portions of the complaints. On March 28 and 30, 2001, the Court issued orders granting the motions in part and denying them in part. The Court ruled claims for civil penalties based on activities that occurred more than five years before the date the complaints were filed cannot be imposed. Claims for injunctive relief are not subject to a time limit. On February 23, 2001, the plaintiffs filed a motion for partial summary judgment seeking 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. On April 9, 2001, the AEP System companies filed a motion requesting the Court deny plaintiffs' motion as premature, and issue an order allowing discovery to continue. 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 unless such costs can be recovered through regulated rates, and where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 which are 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 NOx rule that required substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. A number of utilities, including several AEP System companies, filed petitions seeking a review of the final rule in the D.C. Circuit Court. In March 2000, the D.C. Circuit Court issued a decision generally upholding the NOx rule. The D.C. Circuit Court issued an order in August 2000 which extended the final compliance date to May 31, 2004. In September 2000 following denial by the D.C. Circuit Court of a request for rehearing, the industry petitioners, including the AEP System companies, petitioned the U.S. Supreme Court for review, which was denied. In December 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit plans to comply with the mandates of the NOx rule. This determination means that those states could face stringent sanctions within the next 24 months 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. In January 2000 Federal EPA adopted a revised rule granting petitions filed by certain northeastern states under Section 126 of the Clean Air Act seeking significant reductions in nitrogen oxide emissions from utility and industrial sources. The rule imposes emissions reduction requirements comparable to the NOx rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Certain AEP operating companies and other utilities filed petitions for review in the D.C. Circuit Court. Briefing has been completed and oral argument was held in December 2000. In a related matter, on April 19, 2000, 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 rule's compliance date is May 2003 for CPL and May 2005 for SWEPCo. In June 2000 OPCo announced that it was beginning a $175 million installation of selective catalytic reduction (SCR) technology (expected to be operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW Gavin Plant. Construction of SCR technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant is scheduled to begin 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 with the NOx rule upheld by the D.C. Circuit Court as well as compliance with the Texas Natural Resource Conservation Commission rule and the Section 126 petitions could result in required capital expenditures of approximately $1.6 billion, including the amounts discussed in the previous paragraph, for AEP Consolidated. 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 through regulated rates and/or future market prices for electricity where generation is deregulated, 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. M-8 REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS The following is a combined presentation of management's discussion and analysis of financial condition, contingencies and other matters for AEP and certain of its subsidiary registrants. Management's discussion and analysis of results of operations for AEP and each of its subsidiary registrants for the first quarter March 31, 2001 is presented with their financial statements earlier in this document. FINANCIAL CONDITION Total plant and property additions including capital leases for the year-to-date period were $336 million for AEP Consolidated. The following table shows the additions by certain AEP subsidiary registrants. Company Amount ------- ------ (in millions) APCo $41 CPL 39 I&M 19 OPCo 65 SWEPCo 22 During the first three months of 2001, the AEP System issued $40 million of notes payable due in 2004 with an interest rate of 6.73% and increased the level of borrowing under the SEEBOARD Revolving Credit Facility by $89 million. Retirements of debt were: first mortgage bonds totaling $120 million with interest rates ranging from 5.91% to 6 3/8% due in 2001, $61 million of notes payable with interest rates ranging from 6.20% to 7.5625% due in 2001 and a decrease in short-term debt of $225 million. The following table shows the retirements by certain AEP subsidiary registrants: Principal Type Amount Interest Due Company of Debt Retired Rate Date ------- ------- ----------- -------- ---- (in millions) (%) APCo FMB $100 6-3/8 March 1, 2001 OPCo NP 30 6.20 January 31, 2001 PSO FMB 6 5.91 March 1, 2001 PSO FMB 5 6.02 March 1, 2001 PSO FMB 9 6.02 March 1, 2001 CPL redeemed $500,000 of its 8.00% trust preferred securities on February 1, 2001. 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 is 6.125% and they are due in May 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. In the event the Series B notes are not called for remarketing, AEP must redeem them. OTHER MATTERS Industry Restructuring As discussed in the 2000 Annual Report, restructuring legislation has been enacted in seven of the eleven state retail jurisdictions in which the AEP domestic electric utility companies operate. The legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the supply of electricity. The following paragraphs discuss significant events occurring in 2001 related to industry restructuring. Ohio Restructuring - Affecting AEP, CSPCo and OPCo Effective January 1, 2001, customer choice of electricity supplier began under the Ohio Act. In February 2001, one supplier announced its plan to offer service to CSPCo's residential customers. Currently for residential customers of OPCo, no alternative suppliers have registered with the PUCO under the Ohio Act. Alternative suppliers have been approved to compete for CSPCo's and OPCo's commercial and industrial customers. Presently, virtually all customers continue to be served by CSPCo and OPCo with a legislatively required residential rate reduction of 5% for the generation portion of rates and frozen transition generation rates including fuel rates from January 1, 2001 to December 31, 2005 for all classes of customers. As discussed in Note 7 of the Notes to Financial Statements in the 2000 Annual Report, CSPCo and OPCo filed an appeal with the Ohio Supreme Court related to a tax expense issue which would result in duplicate expense of $40 million and $50 million, respectively, for a twelve month period beginning on May 1, 2001. One of the items CSPCo and OPCo requested was a stay of the PUCO ordered implementation date (May 1, 2001) for an excise tax credit rider. On April 13, 2001, the Ohio Supreme Court denied the companies' stay request. Management does not expect the Ohio Supreme Court to hear arguments on the merits of this case until the fourth quarter of 2001. One of the intervenors at the hearings for approval of a transition settlement agreement (whose request for rehearing was denied by the PUCO) has filed with the Ohio Supreme Court for review of the settlement agreement including OPCo's and CSPCo's recovery of their transition generation-related regulatory assets. Management is unable to predict the outcome of litigation. The resolution of this matter could negatively impact future results of operations. Virginia Restructuring - Affecting AEP and APCo In connection with a Virginia law that provides for a transition to choice of electricity supplier for retail customers beginning on January 1, 2002 (which is described in Note 7 of the Notes to Financial Statements in the 2000 Annual Report), APCo was required to make a filing with the Virginia SCC to unbundle rates and separate generation from transmission and distribution. On January 3, 2001, APCo filed its corporate separation plan and rate unbundling plan with the Virginia SCC, which included a 1999 cost of service study required by the Virginia SCC's regulations. That filing indicated that additional information about APCo's proposed corporate separation plan would be filed at a later date. On April 11, 2001, the Virginia SCC directed APCo to file the additional information required to complete its corporate separation filing when that information becomes available. APCo was also directed to file, by May 15, 2001, all information necessary for the Virginia SCC to fully consider a functional separation of APCo, by divisions. If in connection with the transition process, the Virginia SCC were to reduce APCo's rates or deny recovery of generation related regulatory assets, it would have an adverse effect on results of operations. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999 legislation was enacted in Arkansas that will ultimately restructure the electric utility industry. In February 2001 the Arkansas General Assembly passed legislation that was signed into law by the Governor that extended the date for electric retail 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 The Texas Restructuring Legislation gives Texas customers of investor-owned utilities 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, if any, including the final fuel recovery, net regulatory asset recovery, certain environmental costs, accumulated 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 has been controversial. During 2000 CPL submitted estimates of stranded costs and the PUCT held hearings. In February 2001 the PUCT issued 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 that it has a stranded benefit 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 would be used to reduce stranded cost. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. The PUCT currently estimates that CPL will have no stranded cost and has ordered the rate reduction to return excess earnings, pending the outcome of the 2004 true-up proceeding. 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 and 2000. Consequently, the April order has no effect on reported net income. A Texas settlement agreement in connection with the AEP and CSW merger permits CPL to apply for regulatory purposes up to $20 million of previously identified STP ECOM plant assets a year in 2000 and 2001 to reduce excess earnings, if any. For book purposes, STP ECOM plant assets will be depreciated in accordance with GAAP, on a systematic and rational basis unless impaired. 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. Beginning January 1, 2002, fuel costs will no longer be subject to PUCT fuel reconciliation proceedings under the Texas Restructuring Legislation. Consequently, 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. These final fuel balances will be included in each company's 2004 true-up proceeding. Fuel costs have been reconciled by CPL, SWEPCo and WTU through June 30, 1998, December 31, 1999 and June 30, 1997, respectively. WTU is currently reconciling its fuel through June 2000. At March 31, 2001, CPL's, SWEPCo's and WTU's Texas jurisdictional unrecovered deferred fuel balances were $125 million, $25.4 million and $66.8 million, respectively. The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to the risk of fuel market price increases and could adversely affect future results of operations beginning in 2002. In response to CPL's request to implement an interim fuel surcharge to collect underrecovered fuel costs, the PUCT voted in April 2001 to defer implementation of the requested fuel surcharge until CPL's final fuel reconciliation as part of its 2004 true-up proceeding. CPL has requested a rehearing on the surcharge denial. Based upon the decision in the CPL fuel surcharge proceeding, management expects that the PUCT may also defer recovery of requested fuel surcharges for SWEPCo and WTU currently pending before PUCT until their 2004 true-up proceedings. Final unrecovered deferred fuel balances at December 31, 2001 will be included in each company's 2004 true-up proceeding. If the final fuel balances or any amount incurred but not yet reconciled are not recovered, it would have a negative impact on results of operations. In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding to recover all or a portion of their generation-related regulatory assets, unrecovered fuel balances, stranded costs and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Litigation ---------- Shareholders' Litigation - Affecting AEP On June 23, 2000, a complaint was filed in the U.S. District Court for the Eastern District of New York seeking unspecified compensatory damages against AEP and four former or present officers. The individual plaintiff also seeks certification as the representative of a class consisting of all persons and entities who purchased or otherwise acquired AEP common stock between July 25, 1997, and June 25, 1999. The complaint alleges that the defendants knowingly violated federal securities laws by disseminating materially false and misleading statements concerning, among other things, the undisclosed materially impaired condition of the Cook Plant, AEP's inability to properly monitor, manage, repair, supervise and report on operations at the Cook Plant and the materially adverse conditions these problems were having, and would continue to have, on AEP's deteriorating financial condition, and ultimately on AEP's operations, liquidity and stock price. Four other similar class action complaints have been filed and the court has consolidated the five cases. The plaintiffs filed a consolidated complaint pursuant to this court order. This case has been transferred to the U.S. District Court for the Southern District of Ohio. On March 5, 2001, AEP and the individual defendants filed a comprehensive motion to dismiss all claims against all defendents in the consolidated cases. The Court has set oral arguments of the motion for June 7, 2001. Although management believes these shareholder actions are without merit and intends to continue to oppose them vigorously, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. 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. During 1997, 1998 and 1999 the litigation moved procedurally through the Texas Court System and was sent to mediation without resolution. In 1999 a class notice was mailed to each of the cities served by CPL. Over 90 of the 128 cities declined to participate in the lawsuit. However, CPL has pledged that if any final, non-appealable court decision in the litigation awards a judgement against CPL for a franchise underpayment, CPL will extend the principles of that decision, with regard to the franchise underpayment, to the cities that declined to participate in the litigation. In December 1999, the court ruled that the class of plaintiffs would consist of approximately 30 cities. A trial date for October 2001 has been set. Although management believes that it has substantial defenses to the cities' claims and intends to defend itself against the cities' claims and pursue its counterclaims vigorously, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo As discussed in Note 8 of the Notes to Financial Statements in the 2000 Annual Report, SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lingite reserves. SWEPCo and CLECO are each a 50% owner 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 U.S. District Court for the Western District of Louisiana. In April 2000, the parties agreed to settle the litigation. As part of the settlement, a subsidiary of SWEPCo will purchase DHMV's interest in the mining assets and will assume the related obligations for mine reclamation. The settlement agreement would give CLECO the option, beginning July 1, 2002, to acquire up to a 50% interest in the mining assets. The litigation has been stayed to provide the parties a reasonable period of time to complete the settlement process. Management believes that the resolution of this matter will not have a material effect on results of operations, cash flows or financial condition. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, I&M, and OPCo 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. AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. In 1999 Notices of Violation were issued and complaints were filed by Federal EPA in various U.S. District Courts alleging APCo, CSPCo, I&M, OPCo and a number of unaffiliated utilities made modifications to generating units at certain of their coal-fired generating plants over the course of the past 25 years that extended unit operating lives or increased unit generating capacity without a preconstruction permit in violation of the Clean Air Act. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional generating units previously named only in the Notices of Violation in the complaint. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the AEP System under the Clean Air Act. A lawsuit against power plants owned by certain AEP System operating companies alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and has been consolidated with the Federal EPA action. 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). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts Federal EPA's contentions, could be substantial. In May 2000 the AEP System companies filed motions to dismiss all or portions of the complaints. On March 28 and 30, 2001, the Court issued orders granting the motions in part and denying them in part. The Court ruled claims for civil penalties based on activities that occurred more than five years before the date the complaints were filed cannot be imposed. Claims for injunctive relief are not subject to a time limit. On February 23, 2001, the plaintiffs filed a motion for partial summary judgment seeking 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. On April 9, 2001, the AEP System companies filed a motion requesting the Court deny plaintiffs' motion as premature, and issue an order allowing discovery to continue. 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 unless such costs can be recovered through regulated rates, and where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 which are 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 NOx rule that required substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. A number of utilities, including several AEP System companies, filed petitions seeking a review of the final rule in the D.C. Circuit Court. In March 2000, the D.C. Circuit Court issued a decision generally upholding the NOx rule. The D.C. Circuit Court issued an order in August 2000 which extended the final compliance date to May 31, 2004. In September 2000 following denial by the D.C. Circuit Court of a request for rehearing, the industry petitioners, including the AEP System companies, petitioned the U.S. Supreme Court for review, which was denied. In December 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit plans to comply with the mandates of the NOx rule. This determination means that those states could face stringent sanctions within the next 24 months 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. In January 2000 Federal EPA adopted a revised rule granting petitions filed by certain northeastern states under Section 126 of the Clean Air Act seeking significant reductions in nitrogen oxide emissions from utility and industrial sources. The rule imposes emissions reduction requirements comparable to the NOx rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Certain AEP operating companies and other utilities filed petitions for review in the D.C. Circuit Court. Briefing has been completed and oral argument was held in December 2000. In a related matter, on April 19, 2000, 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 rule's compliance date is May 2003 for CPL and May 2005 for SWEPCo. In June 2000 OPCo announced that it was beginning a $175 million installation of selective catalytic reduction (SCR) technology (expected to be operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW Gavin Plant. Construction of SCR technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant is scheduled to begin 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 with the NOx rule upheld by the D.C. Circuit Court as well as compliance with the Texas Natural Resource Conservation Commission rule and the Section 126 petitions could result in required capital expenditures of approximately $1.6 billion, including the amounts discussed in the previous paragraph, for AEP Consolidated. 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 through regulated rates and/or future market prices for electricity where generation is deregulated, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. N-1 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market Risks - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU AEP as a major power producer and a trader of wholesale electricity and natural gas has certain market risks inherent in its business activities. The trading of electricity and natural gas and related financial derivative instruments exposes AEP to market risk. Market risk represents the risk of loss that may occur due to changes in commodity market prices and rates. Policies and procedures have been established to identify, assess, and manage market risk exposures including the use of a risk measurement model which calculates Value at Risk (VaR). The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assuming a 95% confidence level and a one-day holding period. Throughout the year ending December 31, 2000 the average, high, and low VaRs in the wholesale electricity and gas trading portfolio were $10 million, $32 million, and $1 million, respectively. The average, high, and low VaRs for the quarter ending March 31, 2001 were $14 million, $25 million, and $6 million, respectively. Based on this VaR analysis, at March 31, 2001 a near term typical change in commodity prices is not expected to have a material effect on AEP's results of operations, cash flows or financial condition. The following table shows the high and average U.S. electricity market risk as measured by VaR allocated to the AEP registrant subsidiaries based upon the AEP System's trading activities in the U.S. Low VaR is excluded for December 31, 2000 because all companies are under $1 million. VaR for Registrant Subsidiaries: March 31 December 31, 2001 2000 ---- ---- Low High Average High Average (in millions) (in millions) APCo $1 $6 $3 $2 $6 CPL - 1 - 1 4 CSPCo 1 3 2 1 3 I&M 1 4 2 1 4 KPCo - 1 1 - 1 OPCo 1 5 2 2 5 PSO - 1 - 1 3 SWEPCo - 1 - 1 4 WTU - - - - 1 Investments in foreign ventures expose AEP to risk of foreign currency fluctuations. AEP's exposure to changes in foreign currency exchange rates related to these foreign ventures and investments is not expected to be significant for the foreseeable future. AEP is exposed to changes in interest rates primarily due to short-and long-term borrowings to fund its business operations. The potential loss in fair value as of March 31, 2001 has not materially changed since year end. O-1 PART II. OTHER INFORMATION Item 1. Legal Proceedings. AEP and WTU On April 12, 2001, the Texas Natural Resource Conservation Commission ("TNRCC") issued a Notice of Enforcement Action to WTU's Oak Creek Power Station alleging violations of limits contained in the water discharge permit applicable to the plant. The notice references the potential for corrective action, administrative penalties, or both. A meeting has been scheduled with the TNRCC to explore resolution of this matter. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Ehibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges. (b) Reports on Form 8-K: AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo OPCo, PSO, SWEPCo and WTU No reports on Form 8-K were filed during the quarter ended March 31, 2001. P-1 Signature Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto ---------------------- ------------------------ Armando A. Pena Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer AEP GENERATING COMPANY APPALACHIAN POWER COMPANY CENTRAL POWER AND LIGHT COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY WEST TEXAS UTILITIES COMPANY By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto ---------------------- ------------------------ Armando A. Pena Joseph M. Buonaiuto Vice President and Controller and Chief Accounting Officer Treasurer Date: May 11, 2001