8-K 1 form8k.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 8-K CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of Report (Date of earliest event reported) November 18, 2002

Item 5. Other Events This Current Report on Form 8-K (Report) is limited to the reclassification of financial statements of AEP Generating Company (AEGCo), Appalachian Power Company (APCo), Central Power and Light Company (CPL), Columbus Southern Power Company (CSPCo), Indiana Michigan Power Company (I&M), Kentucky Power Company (KPCo), Ohio Power Company (OPCo), Public Service Company of Oklahoma (PSO), Southwestern Electric Power Company (SWEPCo), and West Texas Utilities Company (WTU), to reflect certain reclassifications of revenue from forward trading activities to a net basis of reporting and its impacts upon management's discussion and analysis, the financial statements and the related notes, and the selected financial data as originally reported in our Annual Report on Form 10-K for the fiscal year ended December 31, 2001 (Form 10-K). NO ATTEMPT HAS BEEN MADE IN THIS REPORT TO MODIFY OR UPDATE OTHER DISCLOSURES EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THE RECLASSIFICATIONS DESCRIBED BELOW. As previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchased energy expenses. Effective July 1, 2002, we reclassified revenues such forward trading activity to a net basis of reporting which resulted in a substantial reduction in both revenues and purchased energy expense as well as nonoperating income and expense for APCo, CSPCo, OPCo, KPCo, and I&M but did not have any impact on the financial condition, results of operations or cash flows for such companies. Our third quarter Form 10-Q, previously filed with the Securities and Exchange Commission, reflects such reclassifications. This Report provides updated information to conform such filing to the presentation reported in our third quarter Form 10-Q. Accordingly, this report provides additional information previously reported in our Form 10-K in Item 6. Selected Financial Data, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Item 8. Financial Statements and Suplementary Data, and Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K to reflect the aforementioned reclassifications.

FORWARD LOOKING INFORMATION This discussion includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions, and involve a number of risks and uncertainties. Among the factors both foreign and domestic that could cause actual results to differ materially from forward looking statements are: electric load and customer growth; abnormal weather conditions; available sources of and prices for coal and gas; availability of generating capacity; risks related to energy trading and construction under contract; the speed and degree to which competition is introduced to our power generation business; the structure and timing of a competitive market for electricity and its impact on prices, the ability to recover net regulatory assets, other stranded costs and implementation costs in connection with deregulation of generation in certain states; the timing of the implementation of AEP's restructuring plan; new legislation and government regulations; the ability to successfully control costs; the success of new business ventures; the economic climate and growth in our service and trading territories; the ability to successfully challenge new environmental regulations and to successfully litigate claims that the Company violated the Clean Air Act; inflationary trends; litigation concerning AEP's merger with CSW; changes in electricity and gas market prices and interest rates; fluctuations in foreign currency exchange rates, and other risks and unforeseen events. AEP GENERATING COMPANY

(a) Including portion due within one year. AEP GENERATING COMPANY Management's Narrative Analysis of Results of Operations AEP Generating Company is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies, I&M and KPCo pursuant to FERC approved long-term unit power agreements. Under the terms of its unit power agreement, I&M is required to buy all of AEGCo's Rockport capacity when the unit power agreement with KPCo expires in 2004. 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. Under terms of the unit power agreements, AEGCo accumulates all expenses monthly and prepares the bills for its affiliates. In the month the expenses are incurred, AEGCo recognizes the billing revenues and establishes a receivable from the affiliated companies. Net income decreased $0.1 million or 1% as a result of a slight decrease in the return on other capital. Lower interest charges caused the return on other capital to decrease. Income statement items which changed significantly were: Increase (Decrease) (dollars in millions) From Previous Year Amount % Operating Revenues $(1.0) N.M. Other Operation Expense 0.7 7 Maintenance Expense (0.8) (8) Taxes Other Than Income Taxes 0.4 10 Interest Charges (1.3) (33) N.M. = Not Meaningful The decrease in operating revenues reflects a decrease in the return on other capital reflecting a decline in interest charges. Other operation expense increased due to the costs of an air quality test project and increased benefits and compensation costs. The decrease in maintenance expense can be attributed to a shorter duration of maintenance outages for boiler inspection and repair in 2001. Taxes other than income taxes increased due to an increase in Indiana real and personal property taxes reflecting an unfavorable accrual adjustment and a higher estimated liability accrued in 2001. The decrease in interest charges was primarily due to a decline in interest rates in 2001. The Federal Reserve reduced short-term interest rates eleven times in 2001. AEGCo benefited from the declining short-term interest rates since its short-term borrowings and through July 13, 2001 its long-term debt were based on short-term interest rates. AEGCo's long-term debt interest rates varied daily until July 2001 when we chose to fix the rate at 4.05% for five years.

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

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

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

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $1,509,000, $3,531,000 and $2,468,000 and for income taxes was $8,597,000, $6,820,000 and $6,565,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.

(a) In 2000 and 1999, AEGCo returned capital to AEP in the amounts of $5.8 million and $6 million, respectively. There were no other material transactions affecting common stock and paid-in capital in 2001, 2000 and 1999. (b) Installment purchase contracts were entered into in connection with the issuance of pollution control revenue bonds by the City of Rockport, Indiana. The terms of the installment purchase contracts require AEGCo to pay amounts sufficient to enable the payment of interest and principal on the related pollution control revenue bonds issued to refinance the construction costs of pollution control facilities at the Rockport Plant. (c) These series have an adjustable interest rate that can be a daily, weekly, commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001, AEGCo selected a daily rate which ranged from 0.9% to 5.6% during 2001 and from 1.65% to 6.1% during 2000 and averaged 2.8% in 2001 and 4.1% in 2000. Effective July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July 12, 2006. The interest rates were 5% for Series A and 4.9% for Series B at December 31, 2000. See Notes to Financial Statements beginning on page L-1. AEP GENERATING COMPANY Index to Notes to Financial Statements The notes to AEGCo's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to AEGCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Effects of Regulation Note 6 Commitments and Contingencies Note 8 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Related Party Transactions Note 20 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of AEP Generating Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Generating Company as of December 31, 2001 and 2000, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Deloitte & Touche LLP Columbus, Ohio February 22, 2002 APPALACHIAN POWER COMPANY AND SUBSIDIARIES

(a) Including portion due within one year. APPALACHIAN POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 917,000 retail customers in southwestern Virginia and southern West Virginia. APCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. APCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to APCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse the previously recorded unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on APCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing APCo to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net Income Net income increased $88 million or 119% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including APCo, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 APCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Also contributing to the increase in net income was growth in and strong performance by the wholesale marketing and trading business in the first half of 2001 offset in part by the effect of extremely mild November and December weather combined with weak economic conditions which reduced retail energy sales. The adverse court decision on COLI caused the $47 million decrease in 2000's net income. Income before extraordinary items decreased $56 million or 46% in 2000 primarily due to the COLI decision. An extraordinary gain from the discontinuance of SFAS 71 regulatory accounting of $9 million after tax was recorded in June 2000. (See Note 2, "Extraordinary Items and Cumulative Effect".) Operating Revenues Operating revenues increased 1% in 2001 due to increases in Energy Delivery and Sales to AEP affiliates. The increase in operating revenue of 11% in 2000 is mainly due to an increase in wholesale marketing and trading volume and sales to AEP affiliates. The changes in the components of revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 --------------------------- Amount % Amount % Retail* $ (38.9) (5) $ 2 N.M. Electricity Marketing and Trading (28.0) (11) 147.7 140 Unrealized MTM 46.3 272 (22.0) N.M. Other 8.9 14 (18.2) (22) -------- -------- Total Marketing and Trading (11.7) (1) 109.5 12 Energy Delivery* 20.1 3 9.3 2 Sales to AEP Affiliates 16.6 11 54.4 54 -------- -------- Total Revenues $ 25.0 1 $ 173.2 11 ======== ======== N.M. = Not Meaningful *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in wholesale marketing and trading revenues in 2001 is driven by decrease trading margins. Wholesale marketing and trading revenues increased in 2000 as a result of an increase in electric marketing and trading volume. The maturing of the Intercontinental Exchange, the development of proprietary tools, and increased staffing of energy traders have resulted in an increase in the number of forward electricity purchase and sale contracts in AEP's traditional marketing area. While wholesale marketing and trading volumes rose, kilowatthour sales to industrial customers decreased in 2001. This decrease was due to the economic recession. Also, in the fourth quarter, sales to residential and commercial customers declined. The recession reduced demand, especially, in the fourth quarter. The increase in sales to AEP affiliates in 2001 and 2000 is due to a significant increase in AEP Power Pool transactions. As the quantity of energy sold by the AEP Power Pool rose, APCo's contribution of energy to the Pool rose, accounting for the increase in APCo's revenues from sales to AEP affiliates. The AEP Power Pool was able to make additional sales to third parties in 2000 as a result of an affiliated company's major industrial customer's decision not to continue its purchased power agreement. Operating Expenses The decrease in operating expenses in 2001 of 3% is due to decreases in income taxes, other operation expense, fuel expense and taxes other than income taxes partially offset by increases in electricity marketing expense and depreciation and amortization expenses. Operating expenses increased 16% in 2000 due to an increase in purchases from AEP affiliates, other operation expense and income taxes offset in part by decreases in fuel expense and electricity marketing expense. Changes in the components of operating expenses are as follows: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ----------------------------- Amount % Amount % Fuel $ (17.6) (5) $ (75.6) (17) Marketing Purchases 17.4 70 (35.3) (59) AEP Affiliate Purchases (8.9) (3) 224.8 172 Other Operation (18.6) (7) 31.3 13 Maintenance 7.9 6 0.7 1 Depreciation and Amortization 17.3 11 14.2 10 Taxes Other Than Income Taxes (11.8)(11) (1.0) (1) Income Taxes (34.5)(27) 54.2 72 -------- -------- Total $ (48.8) (3) $ 213.3 16 ======== ======== The decrease in fuel expense in 2001 is due to a decline in generation as a result of scheduled plant maintenance. Fuel expense decreased in 2000 due to the combined effect of the discontinuance of deferral accounting for over or under recovery of fuel costs in the West Virginia jurisdiction effective January 1, 2000 under the terms of a rate settlement agreement and a decline in generation due to scheduled plant maintenance. Electricity marketing purchases increased in 2001 due to increases in purchases of replacement power due to scheduled plant maintenance. The decrease in power purchases in 2000 is due to increased purchases from AEP affiliates caused by an increase in available generation. Purchased power from AEP affiliates decreased in 2001 as the result of a decrease in AEP Power Pool capacity charges due to a reduction in APCo's MLR. The significant increase in purchased power from AEP affiliates in 2000 reflects additional purchases of power from the AEP Power Pool as a result of increased availability of generation. The AEP Power Pool was able to supply more power to APCo since an affiliate's nuclear unit returned to service in June 2000, a major industrial customer discontinued purchasing power from an affiliate in January 2000, and generating unit outage management improved. Other operation expense decreased in 2001 mainly due to the effect of AEPSC billings in 2000 for the disallowance of the COLI program interest deduction. Additionally, the decrease was the result of a gain recorded on the disposition of SO2 emission allowances offset in part by increased wholesale power trading incentive compensation expense. The increase in other operation expense in 2000 was due to increased wholesale marketing costs including increased accruals for incentive compensation, increased use of emission allowances due to stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments which became effective January 1, 2000 and AEPSC billings for the COLI disallowance. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net generation-related regulatory assets were transferred to the energy delivery business' regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these transition regulatory assets through regulated rates. Depreciation and amortization expense increased in 2001 and 2000 due to accelerated amortization, beginning in July 2000, of the transition regulatory assets. Additional investments in the energy delivery business' distribution and transmission plant also contributed to the increases in depreciation and amortization expense. The decrease in taxes other than income taxes in 2001 is due to the elimination of the Virginia gross receipts tax as a result of a tax law change due to deregulation in that state. Income taxes attributable to operations decreased in 2001 due to the effect of the disallowance of COLI interest deductions in 2000 offset in part by an increase in pre-tax operating income. The increase in income taxes attributable to operations in 2000 was due to the disallowance of COLI interest deductions. Nonoperating Income and Nonoperating Expenses The increase in nonoperating income for both 2001 and 2000 is due to increases in the wholesale business' trading transactions outside of the AEP System's traditional marketing area. Nonoperating expenses increased in 2001 due to trading overheads and traders' compensation. Interest Charges Interest charges decreased in 2001 primarily due to the effect of recognizing in 2000 previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies. Additionally, the decrease in 2001 is due to the retirement of first mortgage bonds in 2000. The increase in interest charges in 2000 was due to the recognition of deferred interest payments related to the COLI disallowances and interest on the resultant prior years state income taxes. Extraordinary Gain The extraordinary gain recorded in June 2000 was the result of the discontinuance of SFAS 71 for the generation portion of APCo's business.

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

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

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

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $117,283,000, $124,579,000 and $125,900,000 and for income taxes was $56,981,000, $63,682,000 and $55,157,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases were $2,510,000, $14,116,000 and $13,868,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.

See Notes to Financial Statements Beginning on Page L-1.

(a) The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due date. APCo redeemed 84,500 shares of the 6.85% series of preferred stock subject to mandatory redemption in 2000. (b) The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is $100 per share. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance. (c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be reacquired in 2008. Shares previously redeemed may be applied to meet the sinking fund requirement. (d) Not callable until after 2002. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 6-3/8 2001 - March 1 $ - $100,000 7.38 2002 - August 15 50,000 50,000 7.40 2002 - December 1 30,000 30,000 6.65 2003 - May 1 40,000 40,000 6.85 2003 - June 1 30,000 30,000 6.00 2003 - November 1 30,000 30,000 7.70 2004 - September 1 21,000 21,000 7.85 2004 - November 1 50,000 50,000 8.00 2005 - May 1 50,000 50,000 6.89 2005 - June 22 30,000 30,000 6.80 2006 - March 1 100,000 100,000 8.50 2022 - December 1 70,000 70,000 7.80 2023 - May 1 30,237 30,237 7.15 2023 - November 1 20,000 20,000 7.125 2024 - May 1 45,000 45,000 8.00 2025 - June 1 45,000 45,000 Unamortized Discount (1,872) (2,222) -------- -------- Total $639,365 $739,015 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 (in thousands) % Rate Due Industrial Development Authority of Russell County, Virginia: 7.70 2007 - November 1 $ 17,500 $ 17,500 5.00 2021 - November 1 19,500 19,500 Putnam County, West Virginia: 5.45 2019 - June 1 40,000 40,000 6.60 2019 - July 1 30,000 30,000 Mason County, West Virginia: 7-7/8 2013 - November 1 10,000 10,000 6.85 2022 - June 1 40,000 40,000 6.60 2022 - October 1 50,000 50,000 6.05 2024 - December 1 30,000 30,000 Unamortized Discount (2,096) (2,218) Total $234,904 $234,782 ======== ======== Under the terms of the installment purchase contracts, APCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due (a) 2001 - June 27 $ - $ 75,000 (a) 2003 - August 20 125,000 - 7.45 2004 - November 1 50,000 50,000 6.60 2009 - May 1 150,000 150,000 7.20 2038 - March 31 100,000 100,000 7.30 2038 - June 30 100,000 100,000 Unamortized Discount (6,753) (6,887) Total $518,247 $468,113 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2001 and 2000 was 2.839% and 6.95%, respectively. Junior debentures outstanding were as follows: December 31, 2001 2000 (in thousands) 8-1/4% Series A due 2026 - September 30 $ 75,000 $ 75,000 8% Series B due 2027 - March 31 90,000 90,000 Unamortized Discount (3,493) (3,633) -------- -------- Total $161,507 $161,367 ======== ======== Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ 80,007 2003 225,007 2004 121,008 2005 80,010 2006 100,011 Later Years 964,730 ---------- Total Principal Amount 1,570,773 Unamortized Discount (14,214) Total $1,556,559 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to APCo's financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to APCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Supplementary Information Note 14 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Related Party Transactions Note 20 Subsequent Events Note 21 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Appalachian Power Company and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 (November 18, 2002 as to Note 21) CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES

(a) Including portion due within one year. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations CPL is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 689,000 retail customers in southern Texas. CPL also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on CPL's behalf by AEP. CPL shares in the revenues and costs of the AEP Power Pool's wholesale sales to and forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to CPL. Trading activities allocated to CPL involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues, with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing CPL to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Income before extraordinary item decreased $5 million or 3% in 2001. The decrease was primarily a result of a settlement of Texas municipal franchise fees (see Note 8) and increased maintenance expense. Income before extraordinary item increased $2 million or 1% in 2000 primarily as a result of increased retail energy sales, the post merger sharing of AEP's power marketing and trading operations which increased wholesale sales to neighboring utilities and power marketers and the effect of an unfavorable adjustment in 1999 as a result of FERC's approval of a transmission coordination agreement. These items were offset in part by a rise in interest expense. Operating Revenues Operating revenues decreased 2% in 2001 and increased 19% in 2000. The increase in 2000 is primarily due to an increase in wholesale marketing and trading activities. The following analyzes the changes in operating revenues: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % ------ - ------ - Retail* $4.2 - $193.6 23 Wholesale Marketing and Trading (79.1) (11) 72.3 95 Unrealized MTM 28.1 343 (8.2) - Other 16.9 27 (8.9) (12) Total Marketing and Trading (29.9) (2) 248.8 25 Energy Delivery* (5.6) (1) 29.1 6 Sales to AEP Affiliates 4.0 11 10.0 36 --- --- -- ---- Total Revenues $(31.5) (2) $287.9 19 ====== ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Retail operating revenues increased 23% in 2000 due to an increase in fuel and purchased power related revenues, reflecting rising prices for natural gas and purchased power, and an increase in weather-related demand for electricity. Through December 31, 2001 the Texas fuel and purchased power clause recovery mechanism provides for the accrual of revenues to recover fuel and purchased power cost increases until reviewed and approved for billing to customers by the PUCT. As a result increases in fuel and purchased power expenses and related accrued revenues do not adversely affect results of opertions. The decrease in wholesale marketing and trading revenues in 2001 is primarily attributable to unfavorable wholesale marketing and trading conditions. The increase in wholesale marketing and trading revenues in 2000 is primarily attributable to CPL's initial participation in AEP's power marketing and trading operations. Since becoming a subsidiary of AEP as a result of the merger in June 2000, CPL shares in AEP's power marketing and trading transactions with other non-affiliated entities. Operating Expenses Total operating expenses decreased 1% in 2001 and increased 23% in 2000. The 2001 decrease is due primarily to a decrease in fuel costs partially offset by purchased power, taxes and maintenance. The 2000 increase was primarily due to increased costs of fuel and purchased power and a rise in other operation expense. The changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % ------ - ------ - Fuel $(58.8) (11) $146.9 36 Marketing Purchases (16.2) (11) 92.5 180 AEP Affiliate Purchases 26.0 80 15.9 95 Other Operation 1.7 1 28.4 10 Maintenance 10.7 18 (9.6) (14) Depreciation And Amortization (10.4) (6) 1.1 1 Taxes Other Than Income Taxes 14.4 19 2.7 4 Income Taxes 12.4 12 (3.1) (3) -- ---- -- ---- Total $(20.2) (1) $274.8 23 ====== ====== N.M. = Not Meaningful The decrease in fuel expense in 2001 was primarily due to a reduction in the average cost of fuel primarily from a decline in natural gas prices. CPL uses natural gas as fuel for 71% of its generating capacity. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Changes in natural gas prices affect CPL's fuel expense, however, as explained above, they generally do not impact results of operations. Fuel expense increased in 2000 primarily due to a rise in the average cost of fuel reflecting large increases in natural gas prices. Overall Purchased Power increased in both years largely due to higher natural gas prices. Although gas prices declined in 2001, they were higher during the first half of 2001 when CPL was making most of its purchases. Throughout 2000 gas prices were increasing accounting for the rise in both AEP Affiliates and Electricity Marketing Purchased Power Expense in 2000. Other operation expense increased in 2000 due primarily to an increase in transmission expenses that resulted from new prices for the ERCOT transmission grid. Each year ERCOT establishes new rates to allocate the costs of the Texas transmission system to Texas electric utilities. In addition to higher transmission expenses, other operation expense increased due to higher administrative expenses resulting from the Company's share of STP voluntary severance expenses and Texas regulatory expenses. The principal cause of the increase in maintenance expense in 2001 was two refueling outages at the STP verses one in 2000. Also contributing to the increase in maintenance expense were scheduled major overhauls of four power plants. Maintenance expense decreased in 2000 as a result of a 10-year service inspection and refueling of STP Units 1 and 2 performed in 1999. Taxes other than income taxes increased in 2001 due primarily to an increase in franchise related taxes, including a settlement of disputed franchise fees (see Note 8), and a new tax levied by the PUCT, the Texas System Benefit Fund Assessment. The increase in income tax expense was primarily due to adjustments associated with prior year tax returns and an increase in pre-tax book income. Interest Charges The decrease in interest charges in 2001 was attributable to lower average interest rates associated with short-term and long-term debt. The increase in interest charges in 2000 can be attributed to higher average interest rates on debt. Extraordinary Loss The extraordinary loss on reacquired debt recorded in 2001 was the result of reacquisition of installment purchase contracts for Matagorda County, Navigation District, Texas. Preferred Stock Dividends Preferred stock dividends decreased in 2000 as a result of the redemption of preferred stock in the fourth quarter of 1999, which resulted in a loss on reacquired preferred stock recorded in 1999.

See Notes to Financial Statements Beginning on Page L-1.

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

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

Supplemental Disclosure: Cash paid for interest net of capitalized amounts (including distributions on Trust Preferred Securities) was $109,835,000, $110,010,000 and $125,222,000 and for income taxes was $161,529,000, $48,141,000 and $78,393,000 in 2001, 2000 and 1999,respectively. See Notes to Financial Statements beginning on page L-1.

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

See Notes to Financial Statements beginning on page L-1. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due 7.25 2004 - October 1 $100,000 $100,000 7.50 2002 - December 1 115,000 115,000 6-7/8 2003 - February 1 49,200 50,000 7-1/8 2008 - February 1 75,000 75,000 7.50 2023 - April 1 75,000 75,000 6-5/8 2005 - July 1 200,000 200,000 Unamortized Discount - - -------- ----- Total $614,200 $615,000 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due Matagorda County Navigation District, Texas: 6.00 2028 - July 1 $120,265 $120,265 6.10 2028 - July 1 - 100,635 6-1/8 2030 - May 1 60,000 60,000 4.90 2030 - May 1 - 111,700 4.95 2030 - May 1 - 50,000 3.75 2030(a) - May 1 111,700 - 4.00 2030(a) - May 1 50,000 - 4.55 2029(a) - Nov 1 100,635 - Guadalupe-Blanco River Authority District, Texas: (b) 2015 - November 1 40,890 40,890 Red River Authority District, Texas: 6.00 2020 - June 1 6,330 6,330 Unamortized Discount (252) (261) -------- -------- Total $489,568 $489,559 ======== ======== (a)Installment Purchase Contract provides for bonds to be tendered in 2003 for 3.75% and 4.00% series and in 2006 for 4.55% series. Therefore, these installment purchase contracts have been classified for payments in those years. (b) A floating interest rate is determined monthly. The rate on December 31, 2001 was 1.9%. Under the terms of the installment purchase contracts, CPL is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due 2001 - November 23 $ - $200,000 (c) 2002 - February 22 150,000 150,000 -------- -------- Total $150,000 $350,000 ======== ======== (c) A floating interest rate is determined monthly. The rate on December 31, 2001 and 2000 was 2.56% and 7.20%, respectively. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $265,000 2003 210,900 2004 100,000 2005 200,000 2006 100,635 Later Years 377,485 --- ------- Total Principal Amount 1,254,020 Unamortized Discount (252) ------ ---- Total $1,253,768 CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to CPL financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to CPL. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Trust Preferred Securities Note 18 Jointly Owned Electric Utility Plant Note 19 Related Party Transactions Note 20 Subsequent Events Note 21 Subsequent Events (Unaudited) Note 22 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Central Power and Light Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Central Power and Light Company and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of the Company for the year ended December 31, 1999, before the restatement described in Note 3 to the consolidated financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such 2001 and 2000 consolidated financial statements present fairly, in all material respects, the financial position of Central Power and Light Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 consolidated financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. Deloitte & Touche LLP Columbus, Ohio February 22, 2002 (November 18, 2002 as to Note 21) COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

(a) Including portion due within one year. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Management's Narrative Analysis of Results of Operations Columbus Southern Power Company is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 678,000 retail customers in central and southern Ohio. CSPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. CSPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to CSPCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse the previously recorded unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on CSPCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing CSPCo to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net Income Increases Income before extraordinary item increased by $72 million or 60% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including CSPCo, in a suit over the deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 CSPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Also contributing to the increase in net income in 2001 was growth in and strong performance by the wholesale business in the first half of 2001 offset in part by the effect of extremely mild weather in November and December combined with weak economic conditions which reduced retail energy sales. Operating Revenues Increase Operating revenues increased 4% in 2001 due to increased revenues to commercial customers and to AEP affiliates. Changes in the components of operating revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % Retail* $(65.1) (10) Wholesale Marketing and Trading (16.2) (11) Unrealized MTM 23.1 N.M. Other 0.8 2 ------ Total Marketing and Trading (57.4) (7) Energy Delivery* 85.2 21 Sales to AEP Affiliates 18.1 37 ------ Total Revenues $ 45.9 4 ====== N.M. = Not Meaningful *Reflects the allocation in 2000 of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Operating revenues increased due to increased kilowatt hour sales to commercial customers and increased sales to affiliated companies. Operating Expenses Operating expenses declined slightly in 2001 due to declines in fuel, maintenance expense, taxes other than income taxes and income taxes partially offset by an increase in depreciation expense. Changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) Amount % Fuel $(14.0) (7) Marketing Purchases 1.1 11 AEP Affiliate Purchases 4.4 2 Other Operation Expense (0.4) - Maintenance Expense (7.2) (10) Depreciation and Amortization 27.7 28 Taxes Other Than Income Taxes (11.7) (10) Income Taxes (10.3) (9) ------ Total $(10.4) (1) ====== Fuel costs decreased by $14 million due to a 12.5% decrease in generation partially offset by increased coal prices of 6.3% Reversal of a quality of service regulatory liability accrual and reduced maintenance of overhead distribution lines accounted for the decease in maintenance expense. Depreciation and amortization expense increased significantly due to amortization of transition regulatory assets which began in January 2001. With the implementation of customer choice in Ohio on January 1, 2001, the PUCO approved the Company's plan for recovery of generation-related regulatory assets through frozen transition rates. Concurrent with the start of the transition period, we began amortization of the transition regulatory assets. Depreciation expense also increased due to additional plant investment. The decrease in taxes other than income taxes in 2001 is due to a decrease in property tax rates on generation property partially offset by a new state excise tax. The decrease in income tax expense was primarily due to an unfavorable ruling in AEP's suit against the government over interest deductions claimed relating to AEP's COLI program which was recorded in 2000 offset in part by an increase in pre-tax income. Nonoperating Income Increase The increases in nonoperating income in 2001 and 2000 is primarily due to increased net gains on forward electricity trading transactions outside AEP's traditional marketing area. Net gains on power trading outside our traditional marketing area increased in 2001 and in 2000 reflecting favorable market conditions and increased trading activity. Interest Charges Decrease Interest charges for 2001 decreased as a result of the recognition in 2000 of deferred interest payments to the IRS related to the COLI disallowances as well as reduced debt in 2001. Extraordinary Loss In 2001 we recorded an extraordinary loss of $30 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation (see Note 2, "Extraordinary Items and Cumulative Effect").

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

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

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $68,596,000, $68,506,000 and $72,007,000 and for income taxes was $80,485,000, $81,109,000 and $71,809,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases were $1,019,000, $10,777,000 and $6,855,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.

(a) A sinking fund requires the redemption of 50,000 shares at $100 a share on or before August 1 of each year. The Company has the right, on each sinking fund date, to redeem an additional 50,000 shares which the Company did in August 2000. The sinking fund provisions of the 7% series aggregate $5,000,000 in 2002 and 2003. See Notes to Financial Statements beginning on page L-1. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 7.25 2002 - October 1 $ 14,000 $ 56,500 7.15 2002 - November 1 6,500 20,000 6.80 2003 - May 1 13,000 45,000 6.60 2003 - August 1 25,000 40,000 6.10 2003 - November 1 5,000 20,000 6.55 2004 - March 1 26,500 50,000 6.75 2004 - May 1 26,000 50,000 8.70 2022 - July 1 2,000 35,000 8.40 2022 - August 1 - 15,000 8.55 2022 - August 1 15,000 15,000 8.40 2022 - August 15 14,000 25,500 8.40 2022 - October 15 13,000 13,000 7.90 2023 - May 1 40,000 50,000 7.75 2023 - August 1 33,000 33,000 7.45 2024 - March 1 - 30,000 7.60 2024 - May 1 11,000 41,000 Unamortized Discount (803) (1,881) -------- -------- Total $243,197 $537,119 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: December 31, 2001 2000 (in thousands) % Rate Due 6-3/8 2020 - December 1 $48,550 $48,550 6-1/4 2020 - December 1 43,695 43,695 Unamortized Discount (1,025) (1,079) Total $91,220 $91,166 ======= ======= Under the terms of the installment purchase contracts, CSPCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at the Zimmer Plant. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due ------ ------------------ 6.85 2005 - October 3 $ 36,000 $ 48,000 6.51 2008 - February 1 52,000 52,000 6.55 2008 - June 26 60,000 60,000 Unamortized Discount (542) (682) -------- -------- Total $147,458 $159,318 ======== ======== Notes payable to parent company were as follows: December 31, 2001 2000 (in thousands) % Rate Due Variable 2002 - Sept 25 $200,000 $ - Junior debentures outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due ------ ------------------ 8-3/8 2025 - Sept 30 $ 72,843 $ 75,000 7.92 2027 - March 31 40,000 40,000 Unamortized Discount (2,870) (2,988) -------- -------- Total $109,973 $112,012 ======== ======== Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $220,500 2003 43,000 2004 52,500 2005 36,000 2006 - Later Years 445,088 Total Principal Amount 797,088 Unamortized Discount (5,240) Total $791,848 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to CSPCo's financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to CSPCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Supplementary Information Note 14 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Jointly Owned Electric Utility Plant Note 19 Related Party Transactions Note 20 Subsequent Events Note 21 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Columbus Southern Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Columbus Southern Power Company and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Deloitte & Touche LLP Columbus, Ohio February 22, 2002 (November 18, 2002 as to Note 21) INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 567,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers including power trading transactions. I&M also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs. Under the terms of unit power agreements, I&M purchases AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. A long-term unit power agreement with an unaffiliated utility expired at the end of 1999 for the sale of 455 MW of AEGCo's Rockport Plant capacity. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to KPCo through 2004. Therefore, effective January 1, 2000, I&M began purchasing 910 MW of AEGCo's 50% share of Rockport Plant capacity. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, I&M's consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to I&M as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. The majority of trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting physical contracts. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contacts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since I&M is a cost-based rate-regulated entity, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). The deferral reflects the fact that power sales and purchases are included in regulated rates on a settlement basis. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. The change in the fair value of physical forward sale and purchase contracts outside AEP's traditional marketing area is included in nonoperating income on a net basis. Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred for contracts with delivery points in AEP's traditional marketing area and for contracts with delivery points outside of AEP's traditional marketing area the unrealized gain or loss is recognized as nonoperating income. When the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash is recognized in the income statement. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contacts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized in the income statement. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in non-operating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in non-operating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing I&M to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations During 2000 both of the Cook Plant nuclear units were successfully restarted after being shutdown in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection. See discussion in Note 4 of the Notes to Financial Statements. A reduction in other operation and maintenance expense in 2001 reflects the completion of restart work on the Cook Plant and was the primary reason for a $208 million increase in net income. As a result of the costs incurred in 2000 to restart the Cook Plant nuclear units and a disallowance of interest deductions for a corporate owned life insurance (COLI) program, net income declined $165 million in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including I&M, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 I&M paid the disputed taxes and interest attributable to the COLI interest deductions for the taxable years 1991-98 and deferred them. Operating Revenues Increase Operating revenues increased 3% in 2001 and 10% in 2000 due to increased sales to AEP affiliates through the AEP Power Pool. The following analyzes the changes in operating revenues: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ------------------------------ Amount % Amount % Retail* $ (2.3) N.M. $(88.6) (12) Marketing and Trading (12.0) (4) 78.6 37 Other 5.0 13 (13.0) (26) -------- ------ (9.3) (1) (23.0) (3) Energy Delivery* 3.4 1 0.1 N.M. Sales to AEP Affiliates 44.7 21 159.4 313 -------- ------ Total $ 38.8 3 $136.5 10 ======== ====== N.M. = Not Meaningful *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The increases in operating revenues in 2001 and 2000 are primarily due to increased sale to AEP affiliates reflecting increased availability of Cook Plant and a 91% increase in volume of power purchased from AEGCo in 2000. I&M increased its sales to AEP affiliates in 2000 when additional electricity became available. The return to service of the Cook Plant units in June and December 2000 and purchasing more power from AEGCo due to the expiration of AEGCo's contract to sell power to an unaffiliated entity, increased the amount of power I&M could sell to its affiliates in the AEP Power Pool. Retail revenues decreased in 2000 when the accrual of power supply recovery revenues ceased at the end of 1999 pursuant to Cook Plant settlement agreements. The accrued power supply recovery revenues are being amortized over a five-year period ending December 31, 2003. The decline in retail revenues was partially offset by an increase in wholesale marketing and trading revenues. In 2000 staffing increases in energy trading resulted in an increase in the number of forward electricity purchase and sale contracts in AEP's traditional marketing area. Operating Expenses Total operating expenses decreased 10% in 2001 and increased 23% in 2000 primarily due to the expiration of an AEGCo unit power agreement to sell part of its Rockport Plant generation to an unaffiliated utility and the increase in operating expenses in 2000 for the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts. The changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ----------------------------- Amount % Amount % Fuel $ 39.2 19 $ 25.5 14 Marketing Purchases 4.9 36 (21.5) (61) AEP Affiliate Purchases (27.2) (10) 65.1 32 Other Operation (147.7) (25) 136.5 30 Maintenance (92.6) (42) 84.5 62 Depreciation and Amortization 9.3 6 4.9 3 Taxes Other Than Income Taxes 4.9 8 (5.2) (8) Income Taxes 53.6 N.M. (9.9) (95) ------- ------ Total $ (155.6) (10) $279.9 23 ======== ====== N.M. = Not Meaningful The increase in fuel expense in 2001 and 2000 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage. Electricity marketing purchases increased in 2001 due to increased purchases from third parties for sales for resale. The decrease in electricity marketing purchases in 2000 is primarily due to a decrease in volume of power purchased as our generation became available. The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool. Purchases from the AEP Power Pool declined 21% in 2001. As a result of the expiration of AEGCo's power sale contract with an unaffiliated utility on December 31, 1999, I&M purchased more of AEGCo's share of Rockport Plant power. Purchases from AEGCo increased 91% in 2000. The decrease in other operation and maintenance expenses in 2001 was primarily due to the cessation of expenditures to prepare the Cook Plant nuclear units for restart with their return to service in 2000. Other operation and maintenance expenses increased in 2000 primarily due to expenditures to prepare the Cook Plant units for restart. In 1999 the IURC and MPSC approved settlement agreements which allowed the deferral of $200 million of Cook Plant restart costs in 1999 for amortization over five years from 1999 through 2003. As a result, other operation and maintenance expense in 1999 reflected a net deferral of $160 million. See discussion in Note 4 of the Notes to Financial Statements. The increase in depreciation and amortization charges in 2001 reflects increased generation and distribution plant investments and amortization of I&M's share of deferred merger costs. Taxes other than income taxes increased in 2001 due to higher real and personal property tax expense from the effect of a favorable accrual adjustment recorded in December 2000 to match estimated amounts with actual expenses. The decrease in taxes other than income tax in 2000 is primarily attributable to decreases in real and personal property taxes reflecting the favorable accrual adjustment and Indiana gross receipts taxes reflecting an unfavorable accrual adjustment related to the 1998 tax year recorded in 1999 for gross receipts tax. The significant increase in income taxes attributable to operations in 2001 is due to an increase in pre-tax operating income. Income taxes attributable to operations decreased in 2000 due to a decrease in pre-tax operating income. Nonoperating Income, Expenses and Income Taxes Increase The increases in nonoperating income in 2001 and 2000 is primarily due to increased net gains on forward electricity trading transactions outside AEP's traditional marketing area. Net gains on power trading outside our traditional marketing area increased in 2001 and 2000 reflecting favorable market conditions and increased trading activity. Nonoperating expenses increased in 2001 due to increased trading overheads and traders' compensation. The increases in nonoperating income taxes in 2001 and 2000 reflects the increase in nonoperating pre-tax income. Interest Charges The decrease in 2001 interest charges reflects the recognition in 2000 of deferred interest payments to the IRS on disputed income taxes from the disallowance of tax deductions for COLI interest for the years 1991-1998. Interest charges increased in 2000 due to increased borrowings to support expenditures for the Cook Plant restart effort and the recognition of deferred interest payments to the IRS on the disputed taxes.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 7.63 2001 - June 1 $ - $ 40,000 7.60 2002 - November 1 50,000 50,000 7.70 2002 - December 15 40,000 40,000 6.10 2003 - November 1 30,000 30,000 8.50 2022 - December 15 75,000 75,000 7.35 2023 - October 1 15,000 20,000 7.20 2024 - February 1 30,000 30,000 7.50 2024 - March 1 25,000 25,000 Unamortized Discount (859) (1,024) -------- -------- $264,141 $308,976 First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 (in thousands) % Rate Due City of Lawrenceburg, Indiana: 7.00 2015 - April 1 $ 25,000 $ 25,000 5.90 2019 - November 1 52,000 52,000 City of Rockport, Indiana: (a) 2014 - August 1 50,000 50,000 7.60 2016 - March 1 40,000 40,000 6.55 2025 - June 1 50,000 50,000 (b) 2025 - June 1 50,000 50,000 City of Sullivan, Indiana: 5.95 2009 - May 1 45,000 45,000 Unamortized Discount (1,761) (2,283) $310,239 $309,717 (a) A variable interest rate is determined weekly. The average weighted interest rate was 2.4% for 2001 and 4.5% for 2000. (b) In June 2001 an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate for June through December 2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate was a daily, weekly, commercial paper or term rate as designated by I&M. A weekly rate was selected which ranged from 1.9% to 4.9% in 2001 and from 2.9% to 5.9% in 2000 and averaged 3.3% during 2001 and 4.2% during 2000. The terms of the installment purchase contracts require I&M to pay amounts sufficient for the cities to pay interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. On the variable rate series the principal is payable at the stated maturities or on the demand of the bondholders at periodic interest adjustment dates which occur weekly. The variable rate bonds due in 2014 are supported by a bank letter of credit which expires in 2002. Accordingly, the variable rate installment purchase contracts have been classified for repayment purposes based on the expiration date of the letter of credit. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due ------ ------------------ (a) 2002 - September 3 $200,000 $200,000 6-7/8 2004 - July 1 150,000 150,000 6.125 2006 - December 15 300,000 - 6.45 2008 - November 10 50,000 50,000 Unamortized Discount (3,856) (2,565) $696,144 $397,435 (a) A floating interest rate is determined quarterly. The rate on December 31, 2001 and 2000 was 2.71% and 7.31%, respectively. The average interest rate was 5.1% in 2001 and 7.3% in 2000. Junior debentures outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due ------ ----------------- 8.00 2026 - March 31 $ 40,000 $ 40,000 7.60 2038 - June 30 125,000 125,000 Unamortized Discount (3,389) (3,496) -------- -------- Total $161,611 $161,504 ======== ======== Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of I&M. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ 340,000 2003 30,000 2004 150,000 2005 - 2006 300,000 Later Years 841,947 ---------- Total Principal Amount 1,661,947 Unamortized Discount (9,865) ---------- Total $1,652,082 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to Notes to Financial Statements The notes to I&M's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to I&M. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 3 Nuclear Plant Restart Note 4 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Supplementary Information Note 14 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Related Party Transactions Note 20 Subsequent Events Note 21 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 (November 18, 2002 as to Note 21) KENTUCKY POWER COMPANY

KENTUCKY POWER COMPANY Management's Narrative Analysis of Results of Operations KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 172,000 retail customers in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. KPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, KPCo's financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to KPCO as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. The majority of trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting physical contracts. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contacts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since KPCO is a cost-based rate-regulated entity, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). AEP's traditional marketing area is up to two transmission systems from the AEP Service territory. The change in the fair value of physical forward sale and purchase contracts outside AEP's traditional marketing area is included in nonoperating income on a net basis. Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred for contracts with delivery points in AEP's traditional marketing area and for contracts with delivery points outside of AEP's traditional marketing area the unrealized gain or loss is recognized as nonoperating income. When the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash is recognized in the income statement. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contacts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized in the income statement. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading assets or liabilities as appropriate. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing KPCO to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Net Income Increases Net income increased $802 thousand or 4% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including KPCo, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 KPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1992-98. The payments were included in Other Property and Investments pending the resolution of this matter. Operating Revenues Operating revenues decreased $10.9 million or 3% in 2001 as a result of decreased retail revenues and decreased trading margins in AEP's traditional marketing area. Changes in the components of operating revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % Retail* $(13.5) (9) Wholesale Marketing and Trading (7.0) (12) Other (0.7) (4) ---- Subtotal (21.2) (9) ----- Energy Delivery* 9.8 8 Sales to AEP Affiliates 0.5 1 --- Total $(10.9) (3) ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Retail revenues decreased as a result of mild weather conditions. Usage by residential customers declined in response to warmer temperatures during November and December 2001. Commercial and industrial sales were stable. The decrease in wholesale marketing and trading revenues is driven by decreased trading margins. The maturing of the Intercontinental Exchange, the development of propriety tools, and increased staffing of energy traders have resulted in an increase in the number of forward electricity purchase and sale contracts in AEP's traditional marketing area yet unfavorable market conditions offset the increase in trading activity. Energy delivery revenues rose largely from providing additional transmission services as a result of increased wholesale marketing and trading transactions and from increased assignment of fees for transmission and distribution delivery services. Operating Expenses Operating expenses decreased $8.8 million in 2001 primarily due to decreases in fuel costs and income taxes. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year) (dollars in millions) Amount % Fuel $(4.0) (5) Marketing Purchases (1.9) (96) AEP Affiliate Purchases 2.5 2 Other Operation 5.8 11 Maintenance (3.4) (13) Depreciation and Amortization 1.5 5 Taxes Other Than Income Taxes 0.6 8 Income Taxes (9.9) (51) - ---- Total $(8.8) (3) ===== The decrease in fuel expense is a result of sharing profits from the trading of power with customers in accordance with the Kentucky Public Service Commission's fuel clause mechanism. Under this mechanism, the profits from KPCo's portion of AEP's wholesale marketing and trading activities are shared with retail customers. This sharing is recognized through credits to fuel expense, thus reducing fuel expense. The decrease in marketing purchases was driven by lower demand and increased net generation. The increase in other operation expense is attributable to increased trading incentive compensation expense, reduced AEP transmission equalization credits and expenses for a full year of factoring accounts receivable. Under the AEP East Region Transmission Agreement, KPCo and certain affiliates share the costs associated with the ownership of their transmission system based upon each company's peak demand and investment. An increase in KPCo's peak demand relative to its affiliates' peak demand was the main reason for the decline in transmission equalization credits. Factoring of accounts receivable began in June 2000. In 2001 we incurred a full year of factoring expenses compared with a partial year in 2000. Lower maintenance expense in 2001 is a result of performing significant planned maintenance at the Big Sandy Plant in 2000 for which there was no comparable activity in the current year. Additions to property, plant and equipment accounted for the increase in depreciation expense. These additions included capitalized software and general distribution equipment upgrades and improvements. Taxes other than income taxes rose as a result of increases in real and personal property tax accruals reflecting higher taxable property values. The decrease in income tax expense was primarily due to a decrease in pre-tax book income and the effect of an unfavorable ruling in 2000 in AEP's suit against the government over interest deductions claimed in prior years related to AEP's COLI program. Nonoperating Income and Nonoperating Expenses Increase The increase in nonoperating income in 2001 is primarily due to increased net gains on forward electricity trading transactions outside AEP's traditional marketing area. Net gains on power trading outside our traditional marketing area increased in 2001 reflecting favorable market conditions and increased trading activity. Nonoperating expenses increased in 2001 due to trading overheads and traders' compensation. The decrease in nonoperating income taxes in 2001 reflects the decrease in nonoperating pre-tax income. Interest Charges Decrease The decline in interest expense was due to the effect of recognizing in 2000 previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies.

KENTUCKY POWER COMPANY Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 8.95 2001 - May 10 $ - $ 20,000 8.90 2001 - May 21 - 40,000 6.65 2003 - May 1 15,000 15,000 6.70 2003 - June 1 15,000 15,000 6.70 2003 - July 1 15,000 15,000 7.90 2023 - June 1 14,500 14,500 Unamortized Discount (117) (159) -------- -------- $ 59,383 $119,341 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due ------ ------------------ (a) 2002 - November 19 $ 70,000 $ 70,000 6.91 2007 - October 1 48,000 48,000 6.45 2008 - November 10 30,000 30,000 Unamortized Discount (375) (510) -------- -------- 147,625 147,490 Less Portion Due Within One Year 70,000 - -------- -------- Total $ 77,625 $147,490 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2001 was 4.3% and on December 31, 2000 was 7.4%. Notes payable to parent company were as follows: December 31, 2001 2000 (in thousands) % Rate Due 4.336 2003 - May 15 $15,000 $ - 6.501 2006 - May 15 60,000 - ------- ------ $75,000 $ - ======= ====== Notes payable to banks outstandings were as follows: December 31, 2001 2000 (in thousands) % Rate Due 7.45 2002 - September 20 $25,000 $25,000 ======= ======= Junior debentures outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 8.72 2025 - June 30 $40,000 $40,000 Unamortized Discount (915) (951) ------- ------- Total $39,085 $39,049 ======= ======= Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ 95,000 2003 60,000 2004 - 2005 - 2006 60,000 Later Years 132,500 -------- Total Principal Amount 347,500 Unamortized Discount 1,407 -------- Total $346,093 KENTUCKY POWER COMPANY Index to Notes to Financial Statements The notes to KPCo's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to KPCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 3 Effects of Regulation Note 6 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Related Party Transactions Note 20 Subsequent Events Note 21 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of Kentucky Power Company: We have audited the accompanying balance sheets and statements of capitalization of Kentucky Power Company as of December 31, 2001 and 2000, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 (November 18, 2002 as to Note 21) OHIO POWER COMPANY AND SUBSIDIARIES

OHIO POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations OPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 698,000 retail customers in northwestern, east central, eastern and southern sections of Ohio. OPCo supplies electric power to the AEP Power Pool and shares the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. OPCo also sells wholesale power to municipalities and cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among Pool members based on their relative peak demands and generating reserves through the payment of capacity charges or the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to OPCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse the previously recorded unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on OPCo's income statement. AEP's tradititonal marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing OPCo to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Income before extraordinary item increased $63 million or 62% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including OPCo, in a suit over deductibility of interest claimed in AEP's consolidated tax returns related to COLI. In 1998 and 1999 OPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Net income was also favorably impacted by the growth in and strong performance by the wholesale business. The favorable effects of the COLI decision and wholesale business were offset in part by the commencement of the amortization of transition regulatory assets in 2001, the effect of mild winter weather and the recent economic downturn. Income before extraordinary item decreased $110 million or 52% in 2000 due predominantly to the unfavorable COLI decision. Operating Revenues Operating revenues decreased 2% in 2001 due to decreased sales to the AEP Power Pool and increased 8% in 2000 because of the significant increase in wholesale marketing and trading volume. The changes in the components of revenues were as follows: Increase (Decrease) From Previous Year (Dollars in Millions) 2001 2000 ----------------------------- Amount % Amount % Retail* $ (66.0) (8) $(135.7) (15) Wholesale Marketing and Trading (18.5) (8) 104.3 84 Unrealized MTM 32.6 N.M. (10.3) N.M. Other (4.3) (5) 2.8 4 -------- ------- Total Marketing and Trading (56.2) (5) (38.9) (3) Energy Delivery* 85.1 18 7.4 2 Sale to AEP Affiliates (71.1)(12) 193.0 50 -------- ------- Total $ (42.2) (2) $ 161.5 8 ======== ======= * Reflects for 2000 the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in operating revenues in 2001 decreased resulted from decrease in sales to the AEP Power Pool due to AEP System plant availability. Sales to AEP affiliates decreased in 2001 because an affiliate was able to supply more power to the Power Pool from two nuclear units that returned to service in June and December 2000. The decrease in 2000 retail revenues was a result of one of OPCo's major industrial customers deciding not to continue its power purchase agreement. OPCo was able to deliver additional power to the power pool in 2000. This accounted for the increase in sales to AEP affiliates in 2000. The maturing of the Intercontinental Exchange, the development of proprietory tools, and increased staffing of energy traders has resulted in an increase in the number of forward electricity purchase and sale contracts in AEP's traditional marketing area caused Wholesale Marketing and Trading to increase in 2000. Operating Expenses Operating expenses decreased by 3% in 2001 mostly due to amortization of transition regulatory assets partly offset by decreases in fuel expense and income taxes. Operating expenses increased by 13% in 2000 mostly due to increases in fuel expense, other operation expense and income taxes. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % Fuel $ (85) (11) $ 84 12 Marketing Purchases 15 30 (35) (42) AEP Affiliate Purchases 12 23 30 143 Other Operation (4) (1) 79 24 Maintenance 18 15 4 3 Depreciation and Amortization 84 54 7 5 Taxes Other Than Income Taxes (10) (6) 5 3 Income Taxes (86) (46) 50 36 ------ ---- Total Operating Expenses $ (56) (3) $224 13 ====== ==== Fuel expense decreased 11% in 2001 mainly due to a 9% decrease in net generation because of decreased sales to the AEP Power Pool caused by an affiliate's two nuclear units returning to service. Fuel expense increased in 2000 due to increases in generation and the average cost of fuel consumed reflecting shutdown costs included in the cost of coal delivered from affiliated mining operations. Marketing purchases expense increased in 2001 and decreased in 2000. The changes were due to increases/decreases in MWH purchases from third parties for resale to wholesale customers and to meet internal demand. Other operation expense increased in 2000 mainly due to increased power generation costs. Increased emission allowance consumption and allowance prices and increased costs of AEP's growing power marketing and trading operation, including trader incentive compensation, accounted for the increase in power generation costs. The increase in emission allowance usage and prices resulted from the stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments which became effective on January 1, 2000. Maintenance expense increased in 2001 mainly due to boiler repairs at Amos, Cardinal, Kammer, Mitchell, Muskingum and Sporn plants, and boiler inspections at the Amos and Cardinal plants. The commencement of amortization of transition regulatory assets in connection with the transition to customer choice and market-based pricing of retail electricity supply under Ohio deregulation accounted for the significant increase in depreciation and amortization expense in 2001. The decrease in taxes other than income taxes in 2001 was due to a decrease in property tax expense reflecting a reduction in rates on generation property under the Ohio Restructuring law partially offset by a new state excise tax. Income taxes decreased in 2001 due to an unfavorable ruling in AEP's suit against the government over interest deductions claimed relating to AEP's COLI program, which was recorded in 2000 and a decrease in pre-tax book income. The increase in income tax expense in 2000 was primarily due to the unfavorable ruling relating to AEP's COLI program. Nonoperating Income and Nonoperating Expense The increases in nonoperating income in 2001 and 2000 were due to an increase in trading transactions outside of the AEP System's traditional marketing area. Increases in nonoperating expenses in 2001 and 2000 were due to increased trading overheads and compensation. Interest Charges The major reason for the decrease in interest expense in 2001 was the recognition in 2000 of deferred interest payments to the IRS related to COLI disallowances. The increase in interest expense in 2000 was due to the recognition of deferred interest payments related to the COLI disallowance. Extraordinary Loss In the second quarter of 2001 an extraordinary loss of $18 million net of tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. In 2000 the application of regulatory accounting for generation under SFAS 71 was discontinued which resulted in an after tax extraordinary loss of $19 million.

OHIO POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 6.75 2003 - April 1 $ 29,850 $ 38,850 6.55 2003 - October 1 27,315 32,135 6.00 2003 - November 1 12,500 25,000 6.15 2003 - December 1 20,000 50,000 8.80 2022 - February 10 5,000 50,000 7.75 2023 - April 1 5,000 40,000 7.375 2023 - October 1 20,250 40,000 7.10 2023 - November 1 12,000 20,000 7.30 2024 - April 1 10,000 21,500 Unamortized Discount (371) (1,191) -------- -------- Total $141,544 $316,294 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 (in thousands) % Rate Due Mason County, West Virginia: 5.45% 2016 - December 1 $ 50,000 $ 50,000 Marshall County, West Virginia: 5.45% 2014 - July 1 50,000 50,000 5.90% 2022 - April 1 35,000 35,000 6.85% 2022 - June 1 50,000 50,000 Ohio Air Quality Development 5.15% 2026 - May 1 50,000 50,000 Unamortized Discount (1,765) (1,870) Total $233,235 $233,130 ======== ======== Under the terms of the installment purchase contracts, OPCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due ------ ------------------ (a) 2001 - May 16 $ - $ 75,000 6.75 2004 - July 1 100,000 100,000 7.00 2004 - July 1 75,000 75,000 6.73 2004 - November 1 48,000 48,000 6.24 2008 - December 4 37,225 37,225 7-3/8 2038 - June 30 140,000 140,000 Unamortized Discount (3,263) (3,642) -------- -------- Total $396,962 $471,583 ======== ======== (a) Redeemed on 5/16/01. Notes payable to parent company were as follows: December 31, 2001 2000 (in thousands) % Rate Due 4.336% 2003 - May 15 $ 60,000 $ - 6.501% 2006 - May 15 240,000 - -------- ------ Total $300,000 $ - ======== ====== Notes payable outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 6.20 2001 - January 31 $ - $ 5,000 6.20 2001 - January 31 - 7,000 6.20 2001 - January 31 - 18,000 ------- ------- Total $ - $30,000 ======= ======= Junior debentures outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 8.16 2025 - September 30 $ 85,000 $ 85,000 7.92 2027 - March 31 50,000 50,000 Unamortized Discount (2,900) (3,020) Total $132,100 $131,980 ======== ======== Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. Finance obligations were entered into by the Company's coal mining subsidiaries for mining facilities and equipment through sale and leaseback transactions. In accordance with SFAS 98, the transactions did not qualify as sales and leasebacks for accounting purposes and therefore are shown as other long-term debt. The remaining long-term debt obligation was paid off in the first quarter of 2001. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ - 2003 149,665 2004 223,000 2005 - 2006 240,000 Later Years 599,475 ---------- Total Principal Amount 1,212,140 Unamortized Discount 8,299 ---------- Total $1,203,841 OHIO POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to OPCo's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to OPCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Acquisitions and Dispositions Note 9 Benefit Plans Note 10 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Supplementary Information Note 14 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Related Party Transactions Note 20 Subsequent Events Note 21 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Ohio Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Ohio Power Company and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ohio Power Company and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 (November 18, 2002 as to Note 21) PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF OKLAHOMA Management's Narrative Analysis of Results of Operations PSO is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 502,000 retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on PSO's behalf by AEP. PSO, along with the other AEP electric operating subsidiaries, shares in the revenues and costs of AEP's wholesale sales to and forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, PSO's consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to PSO. Trading activities allocated to PSO involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contracts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since PSO is a cost-based rate-regulated entity,whose revenues are based on settled transaction, unrealized changes in the fair value of physical forward sale and purchase contracts are deferred as regulatory liabilities (gains) or regulatory assets (losses). Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred as a regulatory liability or a regulatory asset. When the contract settles the total gain or loss is realized in cash and recognized in the income statement. Physical forward trading sale and purchase contracts are included in revenues when the contracts settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts are deferred as regulatory liabilities (gains) or regulatory assets (losses). Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing PSO to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $8.9 million or 13.4% in 2001 due primarily due to the effect of a gain on the sale of a minority interest in Scientech, Inc. recorded in year 2000. Operating Revenues Revenues increased as a result of favorable fuel-related revenues associated with the Oklahoma fuel clause recovery mechanism. Increase (Decrease) From Previous Year Amount % (dollars in millions) Retail* $ 49.1 8 Wholesale Marketing and Trading (95.3) (130) Other 7.9 41 ------ Total Marketing and Trading (38.3) (5) Energy Delivery* 16.8 7 Sales to AEP Affiliates 22.1 151 ------ Total Revenues $ 0.6 - ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Revenues from retail customers increased primarily as a result of an increase in fuel-related revenues. Rising prices for natural gas used for generation and higher purchased power prices accounted for the increase in fuel-related revenues. The Oklahoma fuel clause recovery mechanism provides for the accrual of fuel-related revenues until reviewed and approved for billing to customers by the Oklahoma Corporation Commission. The accrual of additional fuel and purchased power revenues is offset by increases in fuel and purchased power expenses. As a result, accrued fuel-related revenues do not impact results of operations. The decrease in wholesale marketing and trading revenues is attributable to unfavorable wholesale marketing and trading conditions. Operating Expenses Increase Operating expenses were $0.3 million more in 2001 than in 2000 largely as a result of increased fuel expenses. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year Amount % (dollars in millions) Fuel $ 58.5 15 Marketing Purchases (63.9) (73) Affiliated Purchases (17.0) (28) Other Operation 16.0 13 Maintenance 0.3 N.M. Depreciation and Amortization 3.8 5 Taxes Other Than Income Taxes (1.2) (4) Income Taxes 3.8 12 ------ Total $ 0.3 - ------ N.M. = Not Meaningful Fuel expense increased primarily from the recovery of fuel cost due to regulated recovery mechanisms offset in part by a 4% decrease in generation. The decrease in purchased power expense was primarily attributable to reduced prices caused by decreased electricity demand. Other operation expenses increased due mainly to a true-up adjustment in 2000 under a FERC-approved Transmission Coordination Agreement and a full year of our share of incentive compensation for power trading. Depreciation expense increased due to investment relating to repowering Northeast Station Units 1 and 2. The increase in income tax expense was primarily due to adjustments associated with prior year tax returns offset in part by a decrease in pre-tax book income. Nonoperating Income Nonoperating income decreased primarily from the effect of a gain recorded in 2000 on the sale of PSO's minority interest in Scientech, Inc. Scientech provides services, systems and instruments, which describe, regulate, monitor and enhance the safety and reliability of power plant operations and their environmental impact.

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due 5.91 2001 - March 1 $ - $6,000 6.02 2001 - March 1 - 5,000 6.02 2001 - March 1 - 9,000 6.25 2003 - April 1 35,000 35,000 7.25 2003 - July 1 65,000 65,000 7.38 2004 - December 1 50,000 50,000 6.50 2005 - June 1 50,000 50,000 7.38 2023 - April 1 100,000 100,000 Unamortized Discount (2,228) (2,535) -- ------ -- ------ $297,772 $317,465 First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due Oklahoma Environmental Finance Authority (OEFA): 5.90 2007 - December 1 $ 1,000 $ 1,000 Oklahoma Development Finance Authority (ODFA): 4.875 2014 - June 1 33,700 33,700 Red River Authority of Texas: 6.00 2020 - June 1 12,660 12,660 Unamortized Discount (3) (3) ----- ----- Total $47,357 $47,357 ======= ======= Under the terms of the installment purchase contracts, PSO is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due (a) 2002 - November 21 $106,000 $106,000 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2001 and 2000 was 2.775% and 7.376%. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $106,000 2003 100,000 2004 50,000 2005 50,000 2006 - Later Years 147,360 ------- Total Principal Amount 453,360 Unamortized Discount (2,231) ------ Total $451,129 ======== PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to PSO's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to PSO. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Trust Preferred Securities Note 18 Jointly Owned Electric Utility Plant Note 19 Related Party Transactions Note 20 Subsequent Events Note 21 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Public Service Company of Oklahoma: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Oklahoma and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of the Company for the year ended December 31, 1999, before the restatement described in Note 3 to the consolidated financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such 2001 and 2000 consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 consolidated financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 (November 18, 2002 as to Note 21) SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations SWEPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 431,000 retail customers in northeastern Texas, northwestern Louisiana, and western Arkansas. SWEPCo also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on SWEPCo's behalf by AEP. SWEPCo, along with the other AEP electric operating subsidiaries, shares in the revenues and costs of AEP's wholesale sales to and forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - Our financial statements reflect the actions of regulators since our electricity supply sales in the Louisiana jurisdiction and our transmission and distribution operations our cost-based rate-regulated. As a result of the regulators' actions our financial statements can recognize revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to SWEPCo. Trading activities allocated to SWEPCo involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We generally recognize revenues from trading activities based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues, with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading and derivative contracts exposing SWEPCo to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income increased $16.7 million or 23% for the year resulting from the favorable impact of our sharing in AEP's power marketing and trading activities for a full year. The $10.5 million or 13% decrease in net income in 2000 is due to increased operating expenses. Operating Revenues Operating revenues decreased $16.9 million or 2% in 2001. The slight decrease in operating revenues resulted from unfavorable wholesale marketing and trading conditions. Operating revenues increased in 2000 due to the post merger sharing of AEP's power marketing and trading sales, and offset by an unfavorable revenue adjustment in 1999 as a result of FERC's approval of a transmission coordination agreement. The transmission coordination agreement provides the means by which the AEP West electric operating companies plan, operate and maintain their separate transmission assets as a single system. The agreement also establishes the method by which these companies allocate transmission revenues received under open access transmission tariffs. The following analyzes the changes in operating revenues: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % Retail* $ 14.3 3 $ 29.9 6 Wholesale Marketing and Trading (86.3) (49) 58.4 50 Mark to Market 15.5 N.M. (4.7) N.M. Other 35.4 113 8.5 37 ------ ------ Total Marketing and Trading (21.1) (3) 92.1 15 Energy Delivery* (11.9) (3) 45.6 15 Sales to AEP Affiliates 16.1 26 9.0 17 ------ ------ Total Revenues $(16.9) (2) $146.7 15 ====== ====== N.M. = Not Meaningful * Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in wholesale marketing and trading revenues in 2001 is primarily attributable to unfavorable wholesale marketing and trading conditions. The significant increase in wholesale revenues in 2000 is attributable to SWEPCo's participation in AEP's power marketing and trading operations after the merger of CSW and AEP. Revenues also increased in 2000 because of additional fuel and purchased power revenues and a rise in sales volume caused by warmer summer temperatures. The increase in fuel and purchased power revenues reflects rising prices for natural gas used for generation and related higher costs for purchased power. The Texas and Arkansas fuel clause recovery mechanisms provide for the accrual of fuel-related revenues until reviewed and approved for billing to customers by the regulator. The accrual of additional fuel-related revenues is generally offset by increases in fuel and purchased power expenses. As a result fuel-related revenues do not impact results of operations. Since SWEPCo became a subsidiary of AEP as a result of the merger in June 2000, SWEPCo shares in the AEP System's power marketing and trading transactions with other entities. Operating Expenses Total operating expenses decreased 4% in 2001 and increased 20% for 2000. Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % Fuel $(41.2) (8) $119.2 31 Electricity Marketing Purchases (40.4) (69) 28.6 96 Affiliated Purchases 2.5 19 5.8 77 Other Operation 11.9 7 17.2 12 Maintenance (.4) N.M. 10.9 17 Depreciation and Amortization 14.9 14 (4.2) (4) Taxes Other Than Income Taxes 2.0 4 N.M. N.M. Income Taxes 15.9 60 (12.0) (31) ------ ------ Total $(34.8) (4) $165.5 20 ====== ====== N.M. = Not Meaningful Fuel expense decreased in 2001 from lower natural gas prices and a mild summer resulting in a reduction in generation. Fuel expense increased in 2000 due to an increase in the average unit cost of fuel as a result of an increase in the spot market price for natural gas and an increase in generation to meet the rise in demand for electricity. The decrease in purchased power expense in 2001 was mainly due to reduced prices caused by decreased electricity demand. The major increase in purchased power expense in 2000 was primarily caused by higher natural gas prices. Due to the acquisition of Dolet Hills mining operation in June 2001, other operation expense increased for the year. Other operation expense increased in 2000 due primarily to increased regulatory and consulting expenses. Maintenance expense increased in 2000 as a result of costs to restore service and make repairs following a severe ice storm. Depreciation and amortization expense increased in 2001 due primarily to an increase in excess earnings accruals under the Texas restructuring legislation and the acquisition of Dolet Hills mining operation. The increase in 2001 income tax expense was primarily due to an increase in pre-tax book income. The decrease in income tax expense attributable to operations in 2000 was primarily due to a decrease in pre-tax operating income. Nonoperating Expense The decrease in nonoperating expense in 2000 was due to the effect of a 1999 write off of acquisition expenses following CSW's decision not to continue to pursue the acquisition of Cajun Electric Power Cooperatives non-nuclear assets.

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 6-5/8 2003 - February 1 $ 55,000 $ 55,000 7-3/4 2004 - June 1 40,000 40,000 6.20 2006 - November 1 5,650 5,795 6.20 2006 - November 1 1,000 1,000 7.00 2007 - September 1 90,000 90,000 7-1/4 2023 - July 1 45,000 45,000 6-7/8 2025 - October 1 80,000 80,000 Unamortized Discount (1,201) (1,318) -------- -------- $315,449 $315,477 First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 (in thousands) % Rate Due DeSoto County: 7.60 2019 - January 1 $ 53,500 $ 53,500 Sabine: 6.10 2018 - April 1 81,700 81,700 Titus County: 6.90 2004 - November 1 12,290 12,290 6.00 2008 - January 1 13,070 13,520 8.20 2011 - August 1 17,125 17,125 Unamortized Premium 2,149 2,351 -------- -------- $179,834 $180,486 Under the terms of the installment purchase contracts, SWEPCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due (a) 2002 - March 1 $150,000 $150,000 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2001 and 2000 was 2.311% and 6.97%. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $150,595 2003 55,595 2004 52,885 2005 595 2006 6,520 Later Years 378,145 -------- Total Principal Amount 644,335 Unamortized Premium 948 -------- Total $645,283 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to SWEPCo's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to SWEPCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Acquistions and Dispositions Note 9 Benefit Plans Note 10 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Trust Preferred Securities Note 18 Jointly Owned Electric Utility Plant Note 19 Related Party Transactions Note 20 Subsequent Events Note 21 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Southwestern Electric Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southwestern Electric Power Company and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of the Company for the year ended December 31, 1999, before the restatement described in Note 3 to the consolidated financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such 2001 and 2000 consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 consolidated financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 (November 18, 2002 as to Note 21) WEST TEXAS UTILITIES COMPANY

WEST TEXAS UTILITIES COMPANY Management's Narrative Analysis of Results of Operations WTU is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power and provides electric power to approximately 189,000 retail customers in west and central Texas. WTU also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on WTU's behalf by AEP. WTU, along with the other AEP electric operating subsidiaries, shares in the revenues and costs of AEP's wholesale sales to and forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to WTU. Trading activities allocated to WTU involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues, with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match, then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing WTU to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Income before extraordinary items decreased $15.1 million or 55% during 2001, due mostly to a significant increase in other operation expense. The significant increase in other operation expense is partially due to the effect of a 2001 increase in energy delivery's transmission expenses that resulted from new prices for the Electric Reliability Council of Texas (ERCOT) transmission grid. Other operation expense also increased due to the effect of a favorable adjustment made in 2000 related to a FERC-approved Transmission Coordination Agreement. Operating Revenues Operating revenues decreased $14.6 million or 3% as shown below: Increase (Decrease) From Previous Year (dollars in millions) Amount % ---------------------- ------ - Retail* $ (3.1) (2) Wholesale Electric Marketing and Trading (17.3) (12) Unrealized MTM 6.3 N.M. Other 6.8 18 ------ Total Marketing and Trading (7.4) (2) Energy Delivery* (7.2) (4) ------ Total Revenues $(14.6) (3) ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Revenues from retail customers decreased slightly in 2001 due to milder than normal summer and winter weather. Wholesale electric marketing and trading revenues decreased as a result of unfavorable wholesale marketing and trading conditions. Operating Expenses Operating expense increased $4.3 million or 1% as shown below: Increase (Decrease) From Previous Year (dollars in millions) Amount % ---------------------- ------ - Fuel $ (6.0) (3) Marketing Purchases 2.2 3 Affiliate Purchases (1.1) (2) Other Operation 18.2 20 Maintenance 1.1 5 Depreciation and Amortization (4.5) (8) Taxes Other Than Income Taxes 3.0 12 Income Taxes (8.6) (58) ------ Total $ 4.3 1 ====== Fuel expense decreased in 2001 due to a decrease in generation offset in part by an increase in the average spot market price for natural gas. The decrease in generation reflects milder than normal summer and winter weather. Other operation expense increased from the prior year primarily due to the effect of two items. First, energy delivery's transmission expenses increased as a result of new prices for the ERCOT transmission grid. The increase in other operation expense is also attributable to a favorable adjustment made in 2000 related to the FERC-approved Transmission Coordination Agreement. An increase in maintenance expense is the result of an overhaul in 2001 of the Oklaunion Power Plant. Due to the recordation of increased accruals in 2000 for estimated excess earnings under the Texas Legislation, depreciation and amortization expense decreased during 2001. The increase in taxes other than income taxes is the result of an increase in Texas franchise tax assessments and an increase in the Texas PUCT benefit assessment tax, a new tax in the state of Texas. Income taxes decreased in 2001, reflecting a decrease in pre-tax income. Nonoperating Income Nonoperating income increased $2.7 million due to an increase in interest income earned on under-recovered fuel during 2001. Nonoperating Expense The decrease in nonoperating expenses is mainly due to the effect of a loss provision that was recorded in 2000 for the termination of merchandise sales and the cost of phasing out the merchandising sales programs.

WEST TEXAS UTILITIES COMPANY Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 7-3/4 2007 - June 1 $ 25,000 $ 25,000 6-7/8 2002 - October 1 35,000 35,000 7 2004 - October 1 40,000 40,000 6-1/8 2004 - February 1 40,000 40,000 6-3/8 2005 - October 1 72,000 72,000 Unamortized Discount (343) (467) -------- -------- $211,657 $211,533 First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 (in thousands) % Rate Due Red River Authority of Texas: 6 2020 - June 1 $44,310 $44,310 ======= ======= Under the terms of the installment purchase contracts, WTU is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ 35,000 2003 - 2004 80,000 2005 72,000 2006 - Later Years 69,310 -------- Principal Amount 256,310 Unamortized Discount (343) -------- Total $255,967 WEST TEXAS UTILITIES COMPANY Index to Notes to Financial Statements The notes to WTU's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to WTU. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 11 Risk Management, Financial Instruments and Derivatives Note 12 Income Taxes Note 13 Leases Note 15 Lines of Credit and Sale of Receivables Note 16 Unaudited Quarterly Financial Information Note 17 Jointly Owned Electric Utility Plant Note 19 Related Party Transactions Note 20 Subsequent Events Note 21 Subsequent Events (Unaudited) Note 22 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of West Texas Utilities Company: We have audited the accompanying balance sheets and statements of capitalization of West Texas Utilities Company as of December 31, 2001 and 2000, and the related statements of income, retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of the Company for the year ended December 31, 1999, before the restatement described in Note 3 to the financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such 2001 and 2000 financial statements present fairly, in all material respects, the financial position of West Texas Utilities Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 (November 18, 2002 as to Note 21) NOTES TO FINANCIAL STATEMENTS The notes to financial statements that follow are a combined presentation for indicated registrants. The following list of footnotes shows the registrant to which they apply: 1. Significant Accounting Policies AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 2. Extraordinary Items and Cumulative Effect APCo, CPL, CSPCo, OPCo, SWEPCo, WTU 3. Merger CPL, I&M, KPCo, PSO, SWEPCo, WTU 4. Nuclear Plant Restart I&M 5. Rate Matters APCo, CPL, PSO, SWEPCo, WTU 6. Effects of Regulation AEGCo,APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 7. Customer Choice and Industry APCo, CPL, CSPCo, I&M, OPCo, PSO, Restructuring SWEPCo, WTU 8. Commitments and Contingencies AEGCo,APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 9. Acquisitions and Dispositions OPCo, SWEPCo 10. Benefit Plans APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 11. Business Segments AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 12. Risk Management, Financial AEGCo, APCo, CPL, CSPCo, I&M, KPCo Instruments and Derivatives OPCo, PSO, SWEPCo, WTU 13. Income Taxes AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 14. Supplementary Information APCo, CSPCo, I&M, OPCo 15. Leases AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 16. Lines of Credit and Sale AEGCo, APCo, CPL, CSPCo, I&M, KPCo, of Receivables OPCo, PSO, SWEPCo, WTU 17. Unaudited Quarterly Financial AEGCo, APCo, CPL, CSPCo, I&M, KPCo, Information OPCo, PSO, SWEPCo, WTU 18. Trust Preferred Securities CPL, PSO, SWEPCo 19. Jointly Owned Electric CPL, CSPCo, PSO, SWEPCo, WTU Utility Plant 20. Related Party Transactions AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 21. Subsequent Events APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 22. Subsequent Events (Unaudited) CPL, WTU 1. Significant Accounting Policies: Business Operations - AEP (not included herein) is the parent company of eleven domestic electric utility operating companies whose principal business is the generation, transmission and distribution of electric power. AEP as used herein refers collectively to the eleven operating companies. Nine of AEP's eleven domestic electric utility operating companies, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU, are SEC registrants. AEGCo is a domestic generating company wholly-owned by AEP that is an SEC registrant. These companies are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by FERC. They are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP also engages in wholesale marketing and trading of electricity, and to a lesser extent coal and emission allowances in the United States. Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The rates charged by the utility subsidiaries are approved by the FERC and the state utility commissions. The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail rates. Principles of Consolidation -The consolidated financial statements for APCo, CPL, CSPCo, I&M, OPCo, PSO and SWEPCo include the registrant and its wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method with their equity earnings included in nonoperating income for the registrant subsidiaries. Basis of Accounting - As cost-based rate-regulated electric public utility companies, the financial statements herein reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation," regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues. Application of SFAS 71 for the generation portion of the business was discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia by APCo in June 2000, in Texas by CPL, WTU, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 7, "Customer Choice and Industry Restructuring" for additional information. Use of Estimates - The preparation of these financial statements in conformity with generally accepted accounting principles necessarily includes the use of estimates and assumptions by management. Actual results could differ from those estimates. Property, Plant and Equipment -Electric utility property, plant and equipment are stated at original cost of the acquirer. Property, plant and equipment of other operations and investments are stated at their fair market value at acquisition plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate regulated operations retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overheads incurred to operate and maintain plant are included in operating expenses. Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization - AFUDC is a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. It represents the estimated cost of borrowed and equity funds used to finance construction projects. The amounts of AFUDC for 2001, 2000 and 1999 were not significant. Effective with the discontinuance of the application of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia and West Virginia, interest is capitalized during construction in accordance with SFAS 34, "Capitalization of Interest Costs." The amounts of interest capitalized were not material in 2001, 2000, and 1999. Depreciation, Depletion and Amortization - Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of property, other than coal-mining property, and is calculated largely through the use of composite rates by functional class.

Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages at a current average rate of $3.46 per ton in 2001, $5.07 per ton in 2000 and $2.32 per ton in 1999. These costs are included in the cost of coal charged to fuel expense. Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Inventory - Except for CPL, PSO and WTU, the regulated utility companies value fossil fuel inventories using a weighted average cost method. CPL, PSO and WTU, utilize the LIFO method to value fossil fuel inventories. For those utilities whose generation is unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories are also carried at the lower of cost or market. Accounts Receivable - AEP Credit Inc. (formerly CSW Credit) factors accounts receivable for the utility subsidiaries and certain non-affiliated utilities. On December 31, 2001 AEP Credit, Inc. entered into a sale of receivables agreement with a group of banks and commercial paper conduits. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of the companies balances sheet. See Note 16 for further details. Deferred Fuel Costs - The cost of fuel consumed is charged to expense when the fuel is burned. Where applicable under governing state regulatory commission retail rate orders, fuel cost over or under-recoveries are deferred as regulatory liabilities or regulatory assets in accordance with SFAS 71. These deferrals generally are amortized when refunded or billed to customers in later months with the regulator's review and approval. See also Note 6 "Effects of Regulation". We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings. In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes also impact earnings currently. See Note 5, "Rate Matters" and Note 7, "Customer Choice and Industry Restructuring" for further information about fuel recovery. Revenue Recognition - We recognize revenues from generation, transmission and distribution of electricity. The revenues associated with these activities are recorded when earned as physical commodities are delivered to contractual meter points or services are provided. These revenues also include the accrual of earned, but unbilled and/or not yet metered revenues. Such revenues are based on contract prices or tariffs. Revenue recognition for energy marketing and trading transactions is further discussed within the Energy Marketing and Trading Transactions section below. The Company follows EITF 98-10 and marks to market energy trading activities, which includes the net change in fair value of open trading contracts in earnings. Mark-to-market gains and losses on open contracts and net settlements of financial contracts (see below) are included in operating revenues and nonoperating income, respectively, on a net basis. The net basis of reporting for open contracts is permitted by EITF 98-10 and for settled financial contracts is consistent with industry practice. Settled physical forward trading transactions are reported on a net basis, as permitted by EITF 98-10. Energy Marketing and Trading Transactions - AEP engages in wholesale electricity marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and the trading of financial energy contracts which includes exchange futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are long-term trading contracts. The majority of trading activities represent forward electricity contracts that are typically settled by entering into offsetting physical contracts. Prior to settlement the change in fair values of forward sale and purchase contracts are included in AEP's revenues. All of the registrant subsidiaries except AEGCo participate in AEP's wholesale marketing and trading of electricity. APCo, CSPCo, I&M, KPCo and OPCo record forward electricity trading sale and purchase contracts net in operating revenues when the contracts settle for contracts with delivery points in AEP's traditional marketing area and in nonoperating income for forward electricity trading sale and purchase contracts outside AEP's traditional marketing area. CPL, PSO, SWEPCo and WTU record forward electricity trading sale and purchase contracts net in operating revenues. APCo, CSPCo and OPCo account for open forward electricity sale and purchase contracts on a mark-to-market basis and include the mark-to-market change in operating revenues for open contracts in AEP's traditional marketing area and in nonoperating income for open contracts beyond AEP's traditional marketing area. I&M and KPCo account for open forward electricity sale and purchase contracts on a mark-to-market basis and defer the mark-to-market change as regulatory assets or liabilities for those open contracts in AEP's traditional marketing area and include the mark-to-market change in nonoperating income for open contracts beyond AEP's traditional marketing area. CPL, PSO, SWEPCo and WTU account for open forward electricity sale and purchase contracts on a mark-to-market basis. CPL includes the mark-to-market change for open electricity trading contracts in revenues. PSO defers as regulatory assets or liabilities the mark-to-market change for open forward electricity trading contracts that are included in cost of service on a settlement basis for ratemaking purposes. SWEPCo and WTU include the jurisdictional share of the mark-to-market change in revenues for open electricity trading contracts for those jurisdictions that are not subject to SFAS 71 cost based rate regulation and defer as regulatory assets or liabilities the jurisdictional share of the mark-to-market change for open contracts that are included in cost of service on a settlement basis for ratemaking purposes. Trading purchases and sales through electricity options, futures and swaps, represent financial transactions with the net proceeds reported in nonoperating income at fair value upon entering the contracts. APCo, CSPCo, I&M, KPCo and OPCo share in AEP's trading sales and purchases through electricity options, futures and swaps, which represent financial transactions. Changes in fair values of these financial contracts are reported net in nonoperating income. When these contracts settle, the net proceeds are recorded in nonoperating income and the prior unrealized gain or loss is reversed. Recording of the net changes in fair value of open trading contracts is commonly referred to as mark-to-market accounting. All open contracts from trading activities are marked to market in accordance with EITF 98-10. Except as noted above, the net mark-to-market (change in fair value) amount included in results of operations on a net discounted basis. The fair values of open short-term trading contracts are based on exchange prices and broker quotes. Open long-term trading contracts are marked to market based mainly on internally developed valuation models. The valuation models produce an estimated fair value for open long-term trading contracts. The short-term and long-term fair values are present valued and reduced by appropriate reserves for counterparty credit risks and liquidity risk. The models are derived from internally assessed market prices. Bid/ask price curves are developed for inclusion in the model based on broker quotes and other available market data. The curves are within the range between the bid and ask price. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid side of the bid ask if we have a long position and the ask side if we have a short position. This provides for a conservative valuation net of the reserves. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market risks, at the time of settlement, do not correlate with internally developed price models. The effect of marking to market open electricity trading contracts in regulated jurisdictions is deferred as regulatory assets or liabilities since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading activities whether deferred or recognized in revenues are part of Energy Trading and Derivative Contracts assets or liabilities as appropriate. Hedging and Related Activities - In order to mitigate the risks of market price and interest rate fluctuations, certain subsidiaries utilize interest swaps and currency swaps to hedge such market fluctuations. Changes in the market value of these swaps are deferred until the gain or loss is realized on the underlying hedged asset, liability or commodity. To qualify as a hedge, these transactions must be designated as a hedge and changes in their fair value must correlate with changes in the price and interest rate movement of the underlying asset, liability or commodity. This in effect reduces exposure to the effects of market fluctuations related to price and interest rates. APCo, CSPCo, I&M, and OPCo enter into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses from these transactions are deferred and amortized over the life of the debt issuance with the amortization included in interest charges. There were no such forward contracts outstanding at December 31, 2001 or 2000. See Note 12 - "Risk Management, Financial Instruments and Derivatives" for further discussion of the accounting for risk management transactions. Levelization of Nuclear Refueling Outage Costs - In order to match costs with regulated revenues, incremental operation and maintenance costs associated with periodic refueling outages at I&M's Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage. Maintenance Costs - Maintenance costs are expensed as incurred except where SFAS 71 requires the recordation of a regulatory asset to match the expensing of maintenance costs with their recovery in cost based regulated revenues. See below for an explanation of costs deferred in connection with an extended outage at I&M's Cook Plant. Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement agreements approved by the IURC and the MPSC to resolve all issues related to an extended outage of the Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs during 1999. The deferred amount is being amortized to expense on a straight-line basis over five years from January 1, 1999 to December 31, 2003. I&M amortized $40 million in 2001, 2000 and 1999 leaving $80 million as an SFAS 71 regulatory asset at December 31, 2001 on the Consolidated Balance Sheets of I&M. Other Income and Other Expenses - Other Income includes equity earnings of non-consolidated subsidiaries, gains on dispositions of property, interest and dividends, an allowance for equity funds used during construction (explained above) and various other non-operating and miscellaneous income. Other Expenses includes losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses. Income Taxes - The AEP System follows the liability method of accounting for income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the liability method, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established in accordance with SFAS 71 to match the regulated revenues and tax expense. Investment Tax Credits - Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being amortized over the life of the regulated plant investment. Excise Taxes - AEP's subsidiary registrants, as agents for state or local governments, collect from customers certain excise taxes levied by the state or local government upon the customer. These taxes are not recorded as revenue or expense, but only as a pass-through billing to the customer to be remitted to the government entity. Excise tax collections and payments related to taxes imposed upon the customer are not presented in the income statement. Debt and Preferred Stock - Gains and losses from the reacquisition of debt used to finance regulated electric utility plant are generally deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment. If debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost based regulatory accounting under SFAS 71 are generally deferred and amortized over the term of the replacement debt commensurate with their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to SFAS 71 are reported as a component of net income. Debt discount or premium and debt issuance expenses are deferred and amortized over the term of the related debt, with the amortization included in interest charges. Where rates are regulated redemption premiums paid to reacquire preferred stock of the utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistent with the timing of its inclusion in rates in accordance with SFAS 71. Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities. By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC established investment limitations and general risk management guidelines to protect their ratepayers' funds and to allow those funds to earn a reasonable return. In general, limitations include: o Acceptable investments (rated investment grade or above) o Maximum percentage invested in a specific type of investment o Prohibition of investment in obligations of the applicable company or its affiliates. Trust funds are maintained for each regulatory jurisdiction and managed by investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested in order to optimize the after-tax earnings of the Trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives. Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Other Assets at market value in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. In accordance with SFAS 71, unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates. Comprehensive Income - Comprehensive income is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income has two components, net income and other comprehensive income. There were no material differences between net income and comprehensive income for AEGCo, CPL, CSPCo, PSO, SWEPCo and WTU. Components of Other Comprehensive Income - Accumulated Other Comprehensive Income for AEP registrant subsidiaries as of December 31, 2001, is shown in the following table. Registrant subsidiary balances for Accumulated Other Comprehensive Income for the two years ended December 31, 2000 and 1999 were zero. December 31, Components 2001 (thousands) Foreign Currency Rate Hedge APCo $ (340) I&M (3,835) KPCo (1,903) OPCo (196) Segment Reporting - The AEP System has adopted SFAS No. 131, which requires disclosure of selected financial information by business segment as viewed by the chief operating decision-maker. See Note 11 "Business Segments" for further discussion and details regarding segments. Reclassification - Certain prior year financial statement items have been reclassified to conform to current year presentation. Such reclassification had no impact on previously reported net income. 2. Extraordinary Items and Cumulative Effect: Extraordinary Items - Extraordinary items were recorded for the discontinuance of regulatory accounting under SFAS 71 for the generation portion of the business in the Ohio, Virginia, West Virginia, Texas and Arkansas state jurisdictions. See Note 7 "Customer Choice and Industry Restructuring" for descriptions of the restructuring plans and related accounting effects. OPCo and CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal credits during the quarter ended June 30, 2001. This loss resulted from regulatory decisions in connection with Ohio deregulation which stranded the recovery of the GRT. Effective with the liability affixing on May 1, 2001, CSPCo and OPCo recorded an extraordinary loss under SFAS 101. Both Ohio companies have appealed to the Ohio Supreme Court the PUCO order on Ohio restructuring that the Ohio companies believe failed to provide for recovery for the final year of the GRT. The Ohio Supreme Court decision is expected in 2002. In October 2001 CPL reacquired $101 million of pollution control bonds in advance of their maturity. Since these pollution control bonds were used to finance generation assets, a loss of $2 million after tax was recorded. Cumulative Effect of Accounting Change - The FASB's Derivative Implementation Group (DIG) issued accounting guidance under SFAS 133 for certain derivative fuel supply contracts with volumetric optionality and derivative electricity capacity contracts. This guidance, effective in the third quarter of 2001, concluded that fuel supply contracts with volumetric optionality cannot qualify for a normal purchase or sale exclusion from mark-to-market accounting and provided guidance for determining when electricity capacity contracts can qualify as a normal purchase or sale. Predominantly all of AEP's fuel supply contracts for coal and gas and contracts for electricity capacity, which are recorded on a settlement basis, do not meet the criteria of a financial derivative instrument or qualify as a normal purchase or sale. Therefore, AEP's contracts are generally exempt from the DIG guidance described above. Beginning July 1, 2001, the effective date of the DIG guidance, certain of AEP's fuel supply contracts with volumetric optionality that qualify as financial derivative instruments are marked to market with any gain or loss recognized in the income statement. 3. Merger: On June 15, 2000, AEP, parent company of the electric operating companies, merged with CSW so that CSW and its electric operating companies became a wholly-owned subsidiary of AEP. Under the terms of the merger agreement, approximately 127.9 million shares of AEP Common Stock were issued in exchange for all the outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share of AEP Common Stock for each share of CSW Common Stock. Following the exchange, former shareholders of AEP owned approximately 61.4 percent of the corporation, while former CSW shareholders owned approximately 38.6 percent of the corporation. The merger was accounted for as a pooling of interests. Certain reclassifications have been made to conform the historical financial statement presentation of the electric operating companies of AEP and CSW. As a result of the merger, certain electric operating companies include an adjustment to conform vacation pay accruals.The following table shows the vacation accrual conforming adjustment for CSW's registrant utility subsidiaries: Net Income Reductions Net Asset Year Ended Reduction at December 31, December 31, 1999 1999 ----------------- ---- (in millions) CPL $5.3 $0.7 PSO 2.8 1.1 SWEPCo 4.5 0.5 WTU 2.6 0.4 In connection with the merger, non-recoverable merger costs were expensed in 2001 and 2000. Such cost included transaction and transition costs not recoverable from ratepayers. Merger transaction and transition costs recoverable from ratepayers were deferred pursuant to state regulator approved settlement agreements through December 31, 2001. The deferred merger costs are being amortized over five to eight year recovery periods, depending on the specific terms of the settlement agreements, and are included in depreciation and amortization expense. The following tables show the deferred merger cost and amortization expense of the applicable subsidiary registrants: Amortization Merger Cost Expense for the Deferral at Year Ended December 31, 2000 December 31, 2000 ----------------- ----------------- (in millions) CPL $14.4 $1.3 I&M 6.9 0.7 KPCo 2.5 0.3 PSO 7.9 0.5 SWEPCo 6.1 0.5 WTU 4.2 0.4 Amortization Merger Cost Expense for the Deferral at Year Ended December 31, 2001 December 31, 2001 ----------------- ----------------- (in millions) CPL $11.8 $2.6 I&M 9.1 1.7 KPCo 3.2 0.6 PSO 6.6 1.2 SWEPCo 5.0 1.1 WTU 3.5 0.8 Merger transition costs are expected to continue to be incurred for several years after the merger and will be expensed or deferred for amortization as appropriate. As hereinafter summarized, the state settlement agreements provide for, among other things, a sharing of net merger savings with certain regulated customers over periods of up to eight years through rate reductions which began in the third quarter of 2000. Summary of key provisions of Merger Rate Agreements: State/Company Ratemaking Provisions ------------- --------------------- Texas - CPL, SWEPCo $221 million rate reduction WTU over 6 years. No base rate increases for 3 years post merger. Indiana - I&M $67 million rate reduction over 8 years. Extension of base rate freeze until January 1, 2005. Requires additional annual deposits of $6 million to the nuclear decommissioning trust fund for the years 2001 through 2003. Michigan - I&M Customer billing credits of approximately $14 million over 8 years. Extension of base rate freeze until January 1, 2005. Kentucky - KPCo Rate reductions of approximately $28 million over 8 years. No base rate increases for 3 years post merger. Oklahoma - PSO Rate reductions of approximately $28 million over 5 years. No base rate increase before January 1, 2003. Arkansas - SWEPCo Rate reductions of $6 million over 5 years. Louisiana - SWEPCo Rate reductions of $18 million over 8 years. Base rate cap until June 2005. If actual merger savings are significantly less than the merger savings rate reductions required by the merger settlement agreements in the eight-year period following consummation of the merger, future results of operations, cash flows and possibly financial condition could be adversely affected. See Note 8, "Commitments and Contingencies" for information on a recent court decision concerning the merger. 4. Nuclear Plant Restart: I&M completed the restart of both units of the Cook Plant in 2000. Cook Plant is a 2,110 MW two-unit plant owned and operated by I&M under licenses granted by the NRC. I&M shut down both units of the Cook Plant in September 1997 due to questions regarding the operability of certain safety systems that arose during a NRC architect engineer design inspection. Settlement agreements in the Indiana and Michigan retail jurisdictions that address recovery of Cook Plant related outage costs were approved in 1999. The IURC approved a settlement agreement that resolved all matters related to the recovery of replacement energy fuel costs and all outage/restart costs and related issues during the extended outage of the Cook Plant. The MPSC approved a settlement agreement for two open Michigan power supply cost recovery reconciliation cases that resolved all issues related to the Cook Plant extended outage. The settlement agreements allowed: o deferral of $200 million of non-fuel restart-related nuclear operation and maintenance expense for amortization over five years ending December 31, 2003, o deferral of certain unrecovered fuel and power supply costs for amortization over five years ending December 31, 2003, o a freeze in base rates through December 31, 2003 and a fixed fuel recovery charge through March 1, 2004 in the Indiana jurisdiction, and o a freeze in base rates and fixed power supply costs recovery factors until January 1, 2004 for the Michigan jurisdiction. The amounts of restart costs charged to other operation and maintenance expenses were as follows: Year Ended December 31, 2001 2000 1999 ---- ---- ---- Costs Incurred $ 1 $297 $ 289 Deferred Pursuant to Settlement Agreements - - (200) Amortization of Deferrals 40 40 40 -- -- -- Charged to O&M Expense $41 $337 $ 129 === ==== ===== At December 31, 2001 and 2000, deferred restart costs of $80 million and $120 million, respectively, remained in regulatory assets to be amortized through 2003. Also pursuant to the settlement agreements, accrued fuel-related revenues of $38 million in 2001 and 2000 and $37 million in 1999 were amortized. At December 31, 2001 and 2000, fuel-related revenues of $75 million and $113 million, respectively, were included in regulatory assets and will be amortized through December 31, 2003 for both jurisdictions. The amortization of restart costs and fuel-related revenues deferred under Indiana and Michigan retail jurisdictional settlement agreements will adversely affect results of operations through December 31, 2003 when the amortization period ends. The annual amortization of restart cost and fuel-related revenue deferrals is $78 million. 5. Rate Matters: Texas Jurisdictional Fuel Filings - AEP's Texas electric operating companies experienced significant natural gas price increases in the second half of 2000 and early 2001 which resulted in under-recovery of fuel costs and the need to seek increases in fuel rates and surcharges to recover these under-recoveries. During 2001 gas price declines and PUCT-approved fuel rate and fuel surcharge increases resulted in lower unrecovered fuel balances for SWEPCo and WTU and an overrecovered balance for CPL at the end of 2001. Fuel recovery for Texas utilities is a multi-step procedure. When fuel costs change, utilities file with the PUCT for authority to adjust fuel factors. If a utility's prior fuel factors result in an over- or under-recovery of fuel, the utility will also request a surcharge factor to refund or collect that amount. While fuel factors are intended to recover all fuel-related costs, final settlement of these accounts are subject to reconciliation and approval by the PUCT. Fuel reconciliation proceedings determine whether fuel costs incurred and collected during the reconciliation period were reasonable and necessary. All fuel costs incurred since the prior reconciliation date are subject to PUCT review and approval. If material amounts are determined to be unreasonable and ordered to be refunded to customers, results of operations and cash flows would be negatively impacted. According to Texas Restructuring Legislation, fuel cost in the Texas jurisdiction after 2001 will no longer be subject to PUCT review and reconciliation. During 2002 CPL and WTU will file final fuel reconciliations with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. The ultimate recovery of deferred fuel balances at December 31, 2001 will be decided as part of their 2004 true-up proceedings. If the final under-recovered fuel balances or any amounts incurred but not yet reconciled are disallowed, it would have a negative impact on results of operations and cash flows. In October 2001 the PUCT delayed the start of customer choice in the SPP area of Texas. All of SWEPCo's Texas service territory and a small portion of WTU's service territory are in the SPP. SWEPCo's fuel cost recovery procedures will continue until competition begins. SWEPCo will continue to set fuel factors and determine final fuel costs in fuel reconciliation proceedings during the SPP delay period. The PUCT has ruled that WTU fuel factors in the SPP area will be based upon the price to beat fuel factors offered by the WTU retail electric provider in the ERCOT portion of WTU's service territory. The PUCT has initiated a proceeding to determine the most appropriate method to reconcile fuel costs in WTU's SPP area. The following table lists the status of Texas jurisdictional reconciliation, fuel cost subject to reconciliation and under(over)-recovered fuel balances: Fuel cost subject to reconciliation Reconciliation at December 31, 2001 completed through ----------------- -------------------- Company CPL June 30, 1998 $1.6 billion SWEPCo December 31, 1999 314 million WTU June 30, 2000 303 million Under (Over) -recovered fuel balances at Company December 31, 2001 CPL $(58) million SWEPCo 7 million WTU 34 million During 2001 CPL, SWEPCo and WTU requested and received approval to increase their fuel rates. In orders issued in 2001 the PUCT delayed consideration of fuel surcharges for CPL and WTU to recover their underrecovered fuel until the 2004 true-up proceedings. CPL's net underrecovered position was eliminated between the order date and year end 2001 as gas prices declined. For SWEPCo the PUCT deferred $6.8 million of Texas jurisdictional unrecovered fuel for consideration in a future proceeding. Under Texas restructuring, newly organized retail electric providers will make sales to consumers beginning January 1, 2002. These sales will be at fixed rates during a transition period from 2002 through 2006. However, the fuel cost component of a retail electric providers' fixed rates will be subject to prospective adjustment twice a year based upon changes in a natural gas price index. As part of the preparation for customer choice, CPL, SWEPCo and WTU filed their proposed fuel factors to be implemented as part of the fixed rates effective January 1, 2002. Fuel factors approved for CPL's and WTU's retail electric providers were effective January 1, 2002. Due to the SPP area competition delay, SWEPCo's proceeding was postponed. WTU Fuel Filings - In December 2000 WTU filed with the PUCT an application to reconcile fuel costs. During the reconciliation period of July 1, 1997 through June 30, 2000, WTU incurred $348 million of Texas jurisdiction eligible fuel and fuel-related expenses. In February 2002 the PUCT approved WTU's fuel cost for the reconciliation period except for a disallowance of less than $50,000. Texas Transmission Rates - On June 28, 2001, the Supreme Court of Texas ruled that the transmission pricing mechanism created by the PUCT in 1996 was invalid. The court upheld an appeal filed by unaffiliated Texas utilities that the PUCT exceeded its statutory authority to set such rates for the period January 1, 1997 through August 31, 1999. Effective September 1, 1999, the legislature granted this authority to the PUCT. CPL and WTU were not parties to the case. However, the companies' transmission sales and purchases were priced using the invalid rates. It is unclear what action the PUCT will take to respond to the court's ruling. If the PUCT changes rates retroactively, the result could have a material impact on results of operations and cash flows for CPL and WTU. FERC Wholesale Fuel Complaints - In May 2000 certain WTU wholesale customers filed a complaint with FERC alleging that WTU had overcharged them through the fuel adjustment clause for certain purchased power costs related to 1999 unplanned outages at WTU's Oklaunion generation station. In November 2001 certain WTU wholesale customers filed an additional complaint at FERC asserting that since 1997 WTU had billed wholesale customers for not only the 1999 Oklaunion outage costs, but also certain additional costs that are not permissible under the fuel adjustment clause. In December 2001 FERC issued an order requiring WTU to refund, with interest, amounts associated with the May 2000 complaint that were previously billed to wholesale customers. The effects of this order were recorded in 2001 and management believes that as of December 31, 2001, it has fully provided for that over billing. In response to the November 2001 complaint, management is working to determine amounts of additional costs inappropriately billed to wholesale customers, which could result in refunds, with interest. At this time, management is unable to predict the negative impact this complaint will have on future results of operations, cash flow and financial condition. FERC Transmission Rates - In November 2001 FERC issued an order requiring CPL, PSO, SWEPCo and WTU to submit revised open access transmission tariffs, and calculate and issue refunds for overcharges from January 1, 1997. The order resulted from a remand by an appeals court of a tariff compliance filing order issued in November 1998 that had been appealed by certain customers. CPL and WTU recorded refund provisions of $1.7 million and $0.7 million, respectively, including interest in 2001 for this order. PSO and SWEPCo recorded $100,000 each for this order making the AEP total $2.6 million. West Virginia - On June 2, 2000, the WVPSC approved a Joint Stipulation between APCo and other parties related to base rates and ENEC recoveries. The Joint Stipulation allows for recovery of regulatory assets including any generation-related regulatory assets through the following provisions: o Frozen transition rates and a wires charge of 0.5 mills per KWH. o The retention, as a regulatory liability, on the books of a net cumulative deferred ENEC over-recovery balance of $66 million to be used to offset the cost of deregulation when generation is deregulated in WV. o The retention of net merger savings prior to December 31, 2004 resulting from the merger of AEP and CSW. o A 0.5 mills per KWH wires charge for departing customers provided for in the WV Restructuring Plan (see Note 7 "Customer Choice and Industry Restructuring" for discussion of the WV Restructuring Plan) Management expects that the approved Joint Stipulation, plus the provisions of pending restructuring legislation will, if the legislation becomes effective, provide for the recovery of existing regulatory assets, other stranded costs and the cost of deregulation in WV. 6. Effects of Regulation: In accordance with SFAS 71 the financial statements include regulatory assets (deferred expenses) and regulatory liabilities (deferred revenues) recorded in accordance with regulatory actions in order to match expenses and revenues from cost-based rates in the same accounting period. Regulatory assets are expected to be recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future cost recoveries. Among other things, application of SFAS 71 requires that regulated rates be cost-based and the recovery of regulatory assets be probable. Management has reviewed all the evidence currently available and concluded that the requirements to apply SFAS 71 continue to be met for all electric operations in Indiana, Kentucky, Louisiana, Michigan, Oklahoma and Tennessee. When the generation portion of the electric utility operating companies' business in Arkansas, Ohio, Texas, Virginia and WV no longer met the requirements to apply SFAS 71, net regulatory assets were written off for that portion of the business unless they were determined to be recoverable as a stranded cost through regulated distribution rates or wire charges in accordance with SFAS 101 and EITF 97-4. In the Ohio and WV jurisdictions generation-related regulatory assets that are recoverable through transition rates have been transferred to the distribution portion of the business and are being amortized as they are recovered through charges to regulated distribution customers. As discussed in Note 7, "Customer Choice and Industry Restructing" the Virginia SCC ordered the generation-related regulatory assets in the Virginia jurisdiction to remain with the generation portion of the business. Generation-related regulatory assets in the Virginia jurisdiction are being amortized concurrent with their recovery through capped rates. In the Texas jurisdiction generation-related regulatory assets that have been tentatively approved for recovery through securitization have been classified as "regulatory assets designated for securitization." (See Note 7 "Customer Choice and Industry Restructuring" for further details.)

7. Customer Choice and Industry Restructuring: Prior to 2001 customer choice/industry restructuring legislation was passed in Ohio, Texas, Virginia and Michigan allowing retail customers to select alternative generation suppliers. Customer choice began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and in the ERCOT area of Texas. AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas. Legislation enacted in Oklahoma, Arkansas and WV to allow retail customers to choose their electricity supplier is not yet effective. In 2001 Oklahoma delayed implementation of customer choice indefinitely. Arkansas delayed the start of customer choice until as late as October 2005. The Arkansas Commission has recommended further delays of the start date or repeal of the restructuring legislation. Before West Virginia's choice plan can be effective, tax legislation must be passed to continue consistent funding for state and local government. No further legislation has been passed related to restructuring in Arkansas or West Virginia. In general, state restructuring legislation provides for a transition from cost-based rate regulated bundled electric service to unbundled cost-based rates for transmission and distribution service and market pricing for the supply of electricity with customer choice of supplier. Ohio Restructuring - Affecting CSPCo and OPCo Customer choice of electricity supplier and restructuring began on January 1, 2001, under the Ohio Act. During 2001 alternative suppliers registered and were approved by the PUCO as required by the Ohio Act. At January 1, 2002, virtually all customers continue to receive supply service from CSPCo and OPCo with a legislatively required residential generation rate reduction of 5%. All customers continue to be served by CSPCo and OPCo for transmission and distribution services. The Ohio Act provides for a five-year transition period to move from cost based rates to market pricing for electric generation supply services. It granted the PUCO broad oversight responsibility for promulgation of rules for competitive retail electric generation service, approval of a transition plan for each electric utility company and addressed certain major transition issues including unbundling of rates and the recovery of stranded costs including regulatory assets and transition costs. The Ohio Act made several changes in the taxation of electric companies. Effective January 1, 2001 the assessment percentage for property taxes on all electric company property other than transmission and distribution was lowered from 100% to 25%. The assessment percentage applicable to transmission and distribution property remains at 88%. Also, electric companies were exempted from the excise tax based on receipts. To make up for these tax reductions electric distribution companies became subject to a new KWH based excise tax. Since electric companies no longer paid the gross receipts tax, they became liable, as of January 1, 2002 for the corporation franchise tax and municipal income taxes. In preparation for the January 1, 2001 start of the transition period, CSPCo and OPCo filed a transition plan in December 1999. After negotiations with interested parties including the PUCO staff, the PUCO approved a stipulation agreement for CSPCo's and OPCo's transition plans. The approved plans included, among other things, recovery of generation-related regulatory assets over seven years for OPCo and over eight years for CSPCo through frozen transition rates for the first five years of the recovery period and through a wires charge for the remaining years. At December 31, 2000, the amount of regulatory assets to be amortized as recovered was $518 million for OPCo and $248 million for CSPCo. The stipulation agreement required the PUCO to consider implementation of a gross receipts tax credit rider as the parties could not reach an agreement. As of May 1, 2001, electric distribution companies became subject to an excise tax based on KWH sold to Ohio customers. The last tax year for which Ohio electric utilities will pay the excise tax based on gross receipts is May 1, 2001 through April 30, 2002. As required by law, the gross receipts tax is paid in advance of the tax year for which the utility exercises its privilege to conduct business. CSPCo and OPCo treat the tax payment as a prepaid expense and amortized it to expense during the tax year. Following a hearing on the gross receipts tax issue, the PUCO determined that there was no duplicate tax overlap period. The PUCO ordered the gross receipts tax credit rider to be effective May 1, 2001 instead of May 1, 2002 as proposed by the companies. This order reduced CSPCo's and OPCo's revenues by approximately $90 million. CSPCo's and OPCo's request for rehearing of the gross receipts tax issue was also denied by the PUCO. A decision on an appeal of this issue to the Ohio Supreme Court is pending. As described in Note 2, the PUCO's denial of the request for recovery of the final year's gross receipts tax and the tax liability affixing on May 1, 2001 stranded the prepaid asset. As a result, an extraordinary loss was recorded in 2001. One of the intervenors at the hearings for approval of the settlement agreement (whose request for rehearing was denied by the PUCO) filed with the Ohio Supreme Court for review of the settlement agreement. During 2001 that intervenor withdrew from competing in Ohio. The Court dismissed the intervenor's appeal. CSPCo's and OPCo's fuel costs were no longer subject to PUCO fuel clause recovery proceedings beginning January 1, 2001. The elimination of fuel clause recoveries in Ohio subjects CSPCo and OPCo to risk of fuel market price variations and could adversely affect their results of operations and cash flows. Virginia Restructuring - Affecting APCo In Virginia, choice of electricity supplier for retail customers began on January 1, 2002 under its restructuring law. A finding by the Virginia SCC that an effective competitive market exists would be required to end the transition period. The restructuring law provides an opportunity for recovery of just and reasonable net stranded generation costs. The mechanisms in the Virginia law for net stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. Capped rates are the rates in effect at July 1, 1999 if no rate change request was made by the utility. APCo did not request new rates; therefore, its current rates are its capped rates. Virginia's restructuring law does not permit the Virginia SCC to change generation rates during the transition period except for changes in fuel costs, changes in state gross receipts taxes, or to address financial distress of the utility. The Virginia restructuring law also requires filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. On January 3, 2001, APCo filed its corporate separation plan and rate unbundling plan with the Virginia SCC. The Virginia SCC approved settlement agreements that resolved most issues except the assignment of generation-related regulatory assets among functionally separated generation, transmission and distribution organizations. The Virginia SCC determined that generation-related regulatory assets and related amortization expense should be assigned to APCo's generation function. Presently, capped rates are sufficient to recover generation-related regulatory assets. Therefore, management determined that recovery of APCo's generation-related regulatory assets remains probable. APCo will not collect a wires charge in 2002 per the settlement agreements. The settlement agreements and related Virginia SCC order addressed functional separation leaving decisions related to corporate separation for later consideration. The Virginia SCC order approving the settlement agreements requires several compliance filings, including a fuel/replacement power cost report during an extended outage of an affiliate's nuclear plant. Management is unable to predict the outcome of the Virginia SCC's review of APCo's compliance filings. Texas Restructuring - Affecting CPL, SWEPCo and WTU On January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in other areas of Texas including the SPP area. All of SWEPCo's Texas service territory and a small portion of WTU's service territory are located in the SPP. CPL operates entirely in the ERCOT area of Texas. Texas restructuring legislation, among other things: o provides for the recovery of regulatory assets and other stranded costs through securitization and non-bypassable wires charges; o requires reductions in NOx and sulfur dioxide emissions; o freezes rates until January 1, 2002; o provides for an earnings test for each of the three years of the rate freeze period (1999 through 2001) which will reduce stranded cost recoveries or if there is no stranded cost provides for a refund or their use to fund certain capital expenditures; o requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution utility; o provides for certain limits for ownership and control of generating capacity by companies; o provides for elimination of the fuel clause reconciliation process beginning January 1, 2002; and o provides for a 2004 true-up proceeding to determine recovery of stranded costs including final fuel recovery balances, net regulatory assets, certain environmental costs, accumulated excess earnings and other issues. Under the Texas Legislation, delivery of electricity continues to be the responsibility of the local electric transmission and distribution utility company at regulated prices. Each electric utility was required to submit a plan to structurally unbundle its business activities into a retail electric provider, a power generation company, and a transmission and distribution utility. In 2000 CPL, SWEPCo and WTU filed and the PUCT approved business separation plans. The business separation plans provided for CPL and WTU to establish separate companies and divide their integrated utility operations and assets into a power generation company, a transmission and distribution utility and a retail electric provider. In February 2002 the PUCT approved amendments to SWEPCo's plan. The amended plan separates SWEPCo's Texas jurisdictional transmission and distribution assets and operations into two new regulated transmission and distribution subsidiaries. In addition, a retail electric provider was established by SWEPCo to provide retail electric service to SWEPCo's Texas jurisdictional customers. Until competition commences in the SPP, SWEPCo's assets will not be separated and the SWEPCo retail electric provider will not commence operation. Due to the SPP area delay in the start of competition, only CPL's and WTU's retail electric providers commenced operations on January 1, 2002. Operations for CPL, SWEPCo and WTU have been functionally separated. Under the Texas Legislation, electric utilities are allowed to recover stranded generation costs including generation-related regulatory assets. The stranded costs can be refinanced through securitization (a financing structure designed to provide lower financing costs than are available through conventional financings). In 1999 CPL filed with the PUCT to securitize $1.27 billion of its retail generation-related regulatory assets and $47 million in other qualified restructuring costs. The PUCT authorized the issuance of up to $797 million of securitization bonds ($949 million of generation-related regulatory assets and $33 million of qualified refinancing costs offset by $185 million of customer benefits for accumulated deferred income taxes). Four parties appealed to the Supreme Court of Texas which upheld the PUCT's securitization order. CPL issued its securitization bonds in February 2002. CPL included regulatory assets not approved for securitization in its request for recovery of $1.1 billion of stranded costs. The $1.1 billion request included $800 million of STP costs included in property, plant and equipment-electric on CPL's consolidated balance sheets. These STP costs had previously been identified as excess cost over market (ECOM) by the PUCT for regulatory purposes. They are earning a lower return and being amortized on an accelerated basis for rate-making purposes. After hearings on the issue of stranded costs, the PUCT ruled in October 2001 that its current estimate of CPL's stranded costs was negative $615 million. CPL disagrees with the ruling. The ruling indicated that CPL's costs were below market after securitization of regulatory assets. Management believes CPL has a positive stranded cost exclusive of securitized regulatory assets. The final amount of CPL's stranded costs including regulatory assets and ECOM will be established by the PUCT in the 2004 true-up proceeding. If CPL's total stranded costs determined in the 2004 true-up are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates. The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would be made to the amount of regulatory costs authorized by the PUCT to be securitized. However, the PUCT also ruled that excess earnings for the period 1999-2001 should be refunded through distribution rates to the extent of any over-mitigation of stranded costs represented by negative ECOM. In 2001 the PUCT issued an order requiring CPL to reduce distribution rates by $54.8 million plus accrued interest over a five-year period beginning January 1, 2002 in order to return estimated excess earnings for 1999, 2000 and 2001. The Texas Legislation intended that excess earnings reduce stranded costs. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. Currently the PUCT estimates that CPL will have no stranded costs and has ordered the rate reduction to return excess earnings. Since CPL expensed excess earnings amounts in 1999, 2000 and 2001, the order has no additional effect on reported net income but will reduce cash flows for the five year refund period. The amount to be refunded is recorded as a regulatory liability. 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 has appealed the PUCT's estimate of stranded costs and refund of excess earnings to the Travis County District Court. Unaffiliated parties also appealed the PUCT's refund order contending the entire $615 million of negative stranded costs should be refunded presently. Management is unable to predict the outcome of this litigation. An unfavorable ruling would have a negative impact on results of operations, cash flows and possibly financial condition. The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale or exchange of generation assets, the issuance of power generation company stock to the public or the use of an ECOM model. To the extent that the final 2004 true-up proceeding determines that CPL should recover additional stranded costs, the additional amount recoverable can also be securitized. The Texas Legislation provides for an earnings test each year of the 1999 through 2001 rate freeze period. For CPL, any earnings in excess of the most recently approved cost of capital in its last rate case must be applied to reduce stranded costs. Companies without stranded costs, including SWEPCo and WTU, must pay any excess earnings to customers, invest them in improvements to transmission or distribution facilities or invest them to improve air quality at generating facilities. The Texas Legislation requires PUCT approval of the annual earnings test calculation. The PUCT issued a final order for the 1999 earnings test in February 2001 and adjustments to the accrued 1999 and 2000 excess earnings were recorded in results of operations in the fourth quarter of 2000. After adjustments the 1999 excess earnings for CPL and WTU were $24 million and $1 million, respectively. SWEPCo had no excess earnings in 1999. The PUCT issued a final order in September 2001 for the 2000 excess earnings. CPL's, SWEPCo's and WTU's excess 2000 earnings were $23 million, $1 million and $17 million, respectively. An estimate of 2001 excess earnings of $8 million for CPL, $2 million for SWEPCo and none for WTU has been recorded and will be adjusted, if necessary, in 2002 when the PUCT issues its final order regarding 2001 excess earnings. Due to the companies' disagreement with the PUCT, its staff and the Office of Public Utility Counsel related to the proper determination of 2000 excess earnings, the companies filed in district court in October 2001 seeking judicial review of the PUCT's determination of excess earnings. A decision from the court is not expected until later in 2002. Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel reconciliation proceedings for CPL and WTU's ERCOT customers. Consequently, CPL and WTU will file a final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. Due to the delay of competition for the SPP area, SWEPCo, which operates in the SPP area, continues to record and request recovery of fuel costs under the Texas fuel reconciliation proceeding. For WTU's SPP area customers, the PUCT will determine a method to reconcile their fuel costs beginning in 2002 (see Note 5 "Rate Matters"). 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, they could have a negative impact on results of operations. The elimination of the fuel clause recoveries in 2002 in the ERCOT area of Texas will subject the retail electric providers of CPL and WTU to greater risks of fuel market price increases and could adversely affect future results of operations beginning in 2002. The affiliated retail electric providers of CPL, SWEPCo and WTU are required by the Texas Legislation to offer residential and small commercial customers (with a peak usage of less than 1000 KW) a price-to-beat rate until January 1, 2007. In December 2001 the PUCT approved price-to-beat rates for CPL's and WTU's retail electric providers. Customers with a peak usage of more than 1000 KW are subject to market rates. The Texas restructuring legislation provides for the price to beat to be adjusted up to two times annually to reflect changes in fuel and purchased energy costs using a natural gas price index. Due to the delay in the start of competition in the SPP areas of Texas, several issues are pending before the PUCT. These issues impact SWEPCo's and WTU's Texas SPP operations. WTU's Texas SPP operations are estimated to be less than 5% of WTU's total operations. West Virginia Restructuring - Affecting APCo In 2000 the WVPSC issued an order approving an electricity restructuring plan which the WV Legislature approved by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes tax law changes necessary to preserve the revenues of state and local governments. Since the WV Legislature has not passed the required tax law changes, the restructuring plan has not become effective. APCo and WPCo, provide electric service in WV. The WV restructuring plan provides for: o deregulation of generation assets o separation of the generation, transmission and distribution businesses o a transition period with capped and fixed rates for up to 13 years o establishment of a rate stabilization deferred liability balance of $81 million ($76 million by APCo and $5 million by WPCo) by the end of year ten of the transition period. APCo's Joint Stipulation, discussed in Note 5 "Rate Matters" and approved by the WVPSC in 2000 in connection with a base rate filing, provides additional mechanisms to recover transition generation-related regulatory assets. In order for customer choice to become effective in WV, the WV Legislature must enact tax legislation. Management is unable to predict the timing of the passage of such legislation. Arkansas Restructuring - Affecting SWEPCo In 1999 Arkansas enacted legislation to restructure its electric utility industry. Major provisions of the legislation as amended are: o retail competition delayed until as late as October 2005; o transmission facilities must be operated by an ISO if owned by a company which also owns generating facilities; o rates will be frozen for one to three years; o market power issues will be addressed by the Arkansas Commission; and o an annual progress report to the Arkansas General Assembly on the development of competition in electric markets and its impact on retail customers is required. Based on recommendations in the annual progress report filed by the Arkansas Commission, the Arkansas General Assembly passed and the Governor signed legislation in 2001 changing the start date of electric retail competition to October 1, 2003, and providing the Arkansas Commission with authority to delay that date for up to an additional two years. The Arkansas Commission in December 2001 recommended further delays of the start date or repeal of the restructuring legislation. Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas, Ohio, Texas, Virginia and West Virginia - Affecting APCo, CPL, CSPCo, OPCo, SWEPCo and WTU The enactment of restructuring legislation and the ability to determine transition rates, wires charges and any resultant gain or loss under restructuring legislation in Arkansas, Ohio, Texas, Virginia and West Virginia enabled certain subsidiaries to discontinue regulatory accounting under SFAS 71 for the generation portion of their business in those states. Under the provisions of SFAS 71, regulatory assets and regulatory liabilities are recorded to reflect the economic effects of regulation by matching expenses with related regulated revenues. The discontinuance of the application of SFAS 71 in Arkansas, Ohio, Texas, Virginia and West Virginia in accordance with the provisions of SFAS 101 and EITF Issue 97-4 resulted in recognition of extraordinary gains or losses in 2000 and 1999. The discontinuance of SFAS 71 can require the write-off of regulatory assets and liabilities related to the deregulated operations, unless their recovery is provided through cost-based regulated rates to be collected in a portion of operations which continues to be rate regulated. Additionally, a company must determine if any plant assets are impaired when they discontinue SFAS 71 accounting. At the time the companies discontinued SFAS 71, the analysis showed that there was no accounting impairment of generation assets. Prior to 1999, the electric utility operating companies' financial statements reflected the economic effects of regulation under the requirements of SFAS 71. As a result of deregulation of generation, the application of SFAS 71 for the generation portion of the business in Arkansas, Ohio, Texas, Virginia and West Virginia was discontinued. Remaining generation-related regulatory assets will be amortized as they are recovered under terms of transition plans. Management believes that substantially all generation-related regulatory assets and stranded costs will be recovered under terms of the transition plans. If future events including the 2004 true-up proceeding in Texas were to make their recovery no longer probable, the applicable companies would write-off the portion of such regulatory assets and stranded costs deemed unrecoverable as a non-cash extraordinary charge to earnings. If any write-off of regulatory assets or stranded costs occurred, it could have a material adverse effect on future results of operations, cash flows and possibly financial condition. Michigan Restructuring - Affecting I&M On June 5, 2000, the Michigan Legislation became law. Its major provisions, which were effective immediately, applied only to electric utilities with one million or more retail customers. I&M has less than one million customers in Michigan. Consequently, I&M was not immediately required to comply with the Michigan Legislation. The Michigan Legislation gives the MPSC broad power to issue orders to implement retail customer choice of electric supplier no later than January 1, 2002 including recovery of regulatory assets and stranded costs. In compliance with MPSC orders, on June 5, 2001, I&M filed its proposed unbundled rates, open access tariffs and terms of service. On October 11, 2001, the MPSC approved a settlement agreement which generally approved I&M's June 5, 2001 filing except for agreed upon modifications. In accordance with the settlement agreement, I&M agreed that recovery of implementation costs and regulatory assets would be determined in future proceedings. The settlement agreement did not modify the procedure for review of decom-missioning costs recoveries. Customer choice commenced for I&M's Michigan customers on January 1, 2002. Effective with that date the rates on I&M's Michigan customers' bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M's total rates in Michigan remain unchanged and reflect cost of service. At this time, none of I&M's customers have elected to change suppliers and no competing suppliers are active in I&M's Michigan service territory. Management has concluded that as of December 31, 2001 the requirements to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan continue to be cost-based regulated. As a result I&M has not yet dis-continued regulatory accounting under SFAS 71. Oklahoma Restructuring - Affecting PSO Under Oklahoma restructuring legislation passed in 1997 retail open access and customer choice was scheduled to begin by July 1, 2002. In June 2001 the Oklahoma Governor signed into law a bill to delay, indefinitely, the implementation of the transition to customer choice and market based pricing under restructuring legislation. Consequently, PSO will remain rate-regulated until further legislation passes and continues the application of SFAS 71 regulatory accounting. 8. Commitments and Contingencies: Construction and Other Commitments - The following table shows the estimated construction expenditures of the subsidiary registrants for 2002 - 2004: (in millions) AEGCo $171.9 APCo 815.5 CPL 573.1 CSPCo 408.7 I&M 556.9 KPCo 223.3 OPCo 1,008.0 PSO 364.9 SWEPCo 321.4 WTU 169.6 APCo, which operates in Virginia and West Virginia, has been seeking regulatory approval to build a new high voltage transmission line for over a decade. Through December 31, 2001 we had invested approximately $40 million in this effort. If the required regulatory approvals are not obtained and the line is not constructed, the $40 million investment would be written off adversely affecting future results of operations and cash flows. Long-term contracts to acquire fuel for electric generation have been entered into for various terms. The expiration date of the longest fuel contract is 2006 for APCo, 2005 for CSPCo, 2014 for I&M, 2004 for KPCo, 2012 for OPCo, 2014 for PSO, 2006 for SWEPCo and 2006 for WTU. The contracts provide for periodic price adjustments and contain various clauses that would release the subsidiaries from their obligations under certain force majeure conditions. The AEP System has contracted to sell approximately 1,300 MW of capacity on a long-term basis to unaffiliated utilities. Certain of these contracts totaling 250 MW of capacity are unit power agreements requiring the delivery of energy only if the unit capacity is available. The power sales contracts expire from 2002 to 2012. In connection with a lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to assume the obligations of the mining contractor. The contractor's actual obligation outstanding at December 31, 2001 was $75 million. As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide guarantees of mine reclamation in the amount of $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by a third party miner. At December 31, 2001 the cost to reclaim the mine is estimated to be approximately $36 million. OPCo has entered into a purchased power agreement to purchase electricity produced by an unaffiliated entity's three-unit natural gas fired plant that is under construction. The first unit is anticipated to be completed in October 2002 and the agreement will terminate 30 years after the third unit begins operation. Under the terms of the agreement OPCo has the options to run the plant until December 31, 2005 taking 100% of the power generated. For the remainder of the 30 year contract term, OPCo will pay the variable costs to generate the electricity it purchases which could be up to 20% of the plant's capacity. The estimated fixed payments through December 2005 are $55 million. Nuclear Plants - Affecting CPL and I&M I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. CPL owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on behalf of the joint owners under licenses granted by the NRC. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the U.S., the resultant liability could be substantial. By agreement I&M and CPL are partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery in rates is not possible, results of operations, cash flows and financial condition would be adversely affected. Nuclear Incident Liability - Affecting CPL and I&M The Price-Anderson Act establishes insurance protection for public liability arising from a nuclear incident at $9.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance provides $200 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $88 million on each licensed reactor in the U.S. payable in annual installments of $10 million. As a result, I&M could be assessed $176 million per nuclear incident payable in annual installments of $20 million. CPL could be assessed $44 million per nuclear incident payable in annual installments of $5 million as its share of a STPNOC assessment. The number of incidents for which payments could be required is not limited. Insurance coverage for property damage, decommissioning and decontamination at the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8 billion each. Cook Plant and STPNOC jointly purchase $1 billion of excess coverage for property damage, de-commissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage. I&M and STPNOC utilize an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurer requires a contingent financial obligation of up to $36 million for I&M and $3 million for CPL which is assessable if the insurer's financial resources would be inadequate to pay for losses. SNF Disposal - Affecting CPL, and I&M Federal law provides for government responsibility for permanent SNF disposal and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $220 million for fuel consumed prior to April 7, 1983 at Cook Plant have been recorded as long-term debt. I&M has not paid the government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. At December 31, 2001, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon are in external funds and approximate the liability. CPL is not liable for any assessments for nuclear fuel consumed prior to April 7, 1983 since the STP units began operation in 1988 and 1989. Decommissioning and Low Level Waste Accumulation Disposal - Affecting CPL and I&M Decommissioning costs are accrued over the service lives of the Cook Plant and STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014 and 2017. After expiration of the licenses, Cook Plant is expected to be decommissioned through dismantlement. The estimated cost of decommissioning and low level radioactive waste accumulation disposal costs for Cook Plant ranges from $783 million to $1,481 million in 2000 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time SNF may need to be stored at the plant site subsequent to ceasing operations. This, in turn, depends on future developments in the federal government's SNF disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is re-covering estimated Cook Plant decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. The amount recovered in rates for decommissioning the Cook Plant and deposited in the external fund was $27 million in 2001 and $28 million in 2000 and 1999. The licenses to operate the two nuclear units at STP expire in 2027 and 2028. After expiration of the licenses, STP is expected to be decommissioned using the decontamination method. CPL estimates its portion of the costs of decommissioning STP to be $289 million in 1999 nondiscounted dollars. CPL is accruing and recovering these decommissioning costs through rates based on the service life of STP at a rate of $8 million per year. Decommissioning costs recovered from customers are deposited in external trusts. In 2001 and 2000 I&M deposited in its decommissioning trust an additional $12 million and $6 million, respectively, related to special regulatory commission approved funding for decommissioning of the Cook Plant. Trust fund earnings increase the fund assets and the recorded liability and decrease the amount needed to be recovered from ratepayers. Decommissioning costs including interest, unrealized gains and losses and expenses of the trust funds are recorded in other operation expense for Cook Plant. For STP, nuclear decommissioning costs are recorded in other operation expense, interest income of the trusts are recorded in nonoperating income and interest expense of the trust funds are included in interest charges. On I&M's balance sheets, nuclear decommissioning trust assets are included in other assets and a corresponding nuclear decommissioning liability is included in other noncurrent liabilities. On CPL's balance sheets, the nuclear decommissioning liability of $99 million is included in electric utility plant-accumulated depreciation and amortization. At December 31, 2001 and 2000, the decommissioning liability for Cook Plant and STP combined totals $699 million and $654 million, respectively. Municipal Franchise Fee Litigation - Affecting CPL In 2001 CPL settled litigation regarding municipal franchise fees in Texas. CPL paid $11 million to settle the litigation and be released from any further liability. The City of San Juan, Texas had filed a class action suit in 1996 seeking $300 million in damages. Texas Base Rate Litigation - Affecting CPL In 2001 the Texas Supreme Court denied CPL's request to review a case resulting from a 1997 PUCT base rate order. The Court also denied CPL's rehearing request. The primary issues were: o the classification of $800 million of invested capital in STP as ECOM and assigning it a lower return on equity than other generation property; o and an $18 million disallowance of an affiliate service billings. Lignite Mining Agreement Litigation - Affecting SWEPCo In 2001 SWEPCo settled ongoing litigation concerning lignite mining in Louisiana. Since 1997 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 jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. Under terms of a settlement, SWEPCo purchased an unaffiliated mine operator's interest in the mining operations and related debt and other obligations for $86 million. Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo Since 1999 APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged that AEP System companies and eleven unaffiliated utilities modified certain units at coal fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against AEP System companies in U.S. District Court for the Southern District of Ohio. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case. The alleged modification of the generating units occurred over a 20 year period. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In March 2001 the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief. In February 2001 the government filed a motion requesting a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. In January 2002 the U.S. Court of Appeals for the 11th Circuit ruled that TVA may pursue its court challenge of a Federal EPA administrative order charging similar violations to those in the complaints against AEP System companies and other utilities. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and 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 (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 results of operations and cash flows. NOx Reductions - Affecting AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The NOx Rule has been upheld on appeal. The compliance date for the NOx Rule is May 31, 2004. The NOx Rule required states to submit plans to comply with its provisions. In 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit approvable compliance plans. Those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. AEP System companies and other utilities requested that the D.C. Circuit Court review this ruling. In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of AEP System companies' coal-fired generating units. Affected utilities including certain AEP System companies, petitioned the D.C. Circuit Court to review the Section 126 Rule. After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP System companies' and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. On August 24, 2001, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. Federal EPA has announced that it intends to adopt May 31, 2004, as the compliance date for the Section 126 Rule when it finalizes the NOx budgets for both rules. In 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. During 2001 selective catalytic reduction (SCR) technology to reduce NOx emissions on OPCo's Gavin Plant commenced operations. Construction of SCR technology at certain other AEP System companies' generating units continues with completion scheduled in 2002 through 2006. Our estimates indicate that compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures of approximately $1.6 billion of which approximately $450 million has been spent through December 31, 2001 for the AEP System. Estimated compliance costs and amounts spent by registrant subsidiaries are as follows: Estimated Amount Spent Compliance Cost --------------- ------------ (in millions) AEGCo $125 $ - APCo 365 130 CPL 57 4 CSPCo 106 1 I&M 202 - KPCo 140 13 OPCo 606 277 SWEPCo 28 21 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 of additional pollution control equipment are recovered from customers, they will have an adverse effect on results of operations, cash flows and possibly financial condition. Merger Litigation - On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to prove that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit its conclusion that the merger met PUHCA requirements that utilities be "physically interconnected" and confined to a "single area or region." In its June 2000 approval of the merger, the SEC agreed that the AEP and CSW companies' systems are integrated because they have transmission access rights to a single high-voltage line through Missouri and also met the PUCHA's single region requirement because it is now technically possible to centrally control the output of power plants across many states. In its ruling, the appeals court said that the SEC failed to explain its conclusions that the transmission integration and single region requirements are satisfied. Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably. Enron Bankruptcy - Affecting APCo, CSPCo, I&M, KPCo and OPCo At the date of Enron's bankruptcy certain electric operating companies had open trading contracts and trading accounts receivables and payables with Enron. In the fourth quarter of 2001 certain registrants provided the following amounts for their estimated loss from the Enron bankruptcy: Amounts Amounts Net of Registrant Provided Tax -------- -- --- (in millions) APCo $5.2 $3.4 CSPCo 3.2 2.1 I&M 3.4 2.2 KPCo 1.3 0.8 OPCo 4.3 2.8 The amounts provided were based on an analysis of contracts where certain registrants and Enron are counterparties, the offsetting of receivables and payables, and the application of deposits from Enron. If there are any adverse unforeseen developments in the bankruptcy proceedings, our future results of operations, cash flows and possibly financial condition could be adversely impacted. Other - AEP's registrant subsidiaries are involved in a number of other legal proceedings and claims. While management is unable to predict the ultimate outcome of these matters, it is not expected that their resolution will have a material adverse effect on results of operations, cash flows or financial condition. 9. Acquisitions and Dispositions: SFAS 141 "Business Combinations" apply to all business combinations initiated and consummated after June 30, 2001. SWEPCo purchased the Dolet Hills mining operations including existing mine reclamation liabilities at its jointly owned lignite reserves in Louisiana. The purchase resulted from a litigation settlement discussed in Note 8, "Commitments and Contingencies". Management expects the acquisition to have minimal impact on results of operations. Regarding the above acquisition management has recorded the assets acquired and liabilities assumed at their estimated fair values in accordance with SFAS 141 based on currently available information and on current assumptions as to future operations. The allocation of the purchase price is subject to revision based on the final determinations. Dispositions In July 2001 OPCo, an AEP subsidiary, sold coal mines in Ohio and West Virginia and agreed to purchase approximately 34 million tons of coal from the purchaser of the mines through 2008. The sale is expected to have a nominal impact on results of operations and cash flows. 10. Benefit Plans: The registrant subsidiaries participate in two AEP System qualified and two non-qualified pension plans. Substantially all employees are covered by one or both of the pension plans. Postretirement benefits other than pensions are provided for retired employees for medical and death benefits under an AEP System plan.

AEP Savings Plans - The AEP Savings Plans are defined contribution plans offered to non-UMWA U.S. employees. Beginning in 2001 AEP registrant subsidiaries contributions to the plans increased to 4.5% of the initial 6% of employee pay contributed from the previous 3% of the initial 6% of employee base pay contributed. The following table provides the cost for contributions to the savings plans by the following AEP registrant subsidiaries for fiscal years 2001, 2000 and 1999: 2001 2000 1999 ---- ---- ---- (in thousands) APCo $7,031 $3,988 $4,091 CPL 3,046 3,161 3,284 CSPCo 2,789 1,638 1,679 I&M 7,833 4,231 3,996 KPCo 1,016 544 561 OPCo 6,398 3,713 3,744 PSO 2,235 2,306 2,435 SWEPCo 2,776 2,880 2,961 WTU 1,558 1,708 1,766 Other UMWA Benefits - OPCo provides UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements. The benefits are administered by UMWA trustees and contributions are made to their trust funds. Contributions are expensed as paid as part of the cost of active mining operations and were not material in 2001, 2000 and 1999. 11. Business Segments: In fiscal year 2000, AEP's registrant subsidiaries were considered single, vertically integrated units, and were reported collectively in a Domestic Electric Utilities segment. In 2001, we moved toward our goal of functionally and structurally segregating our businesses. The ensuing realignment of our operations resulted in our business segments, Wholesale and Energy Delivery. The business activities of each of these segments are as follows: Wholesale o Generation of electricity for sale to retail and wholesale customers o Marketing and trading of electricity Energy Delivery o Electricity transmission o Electricity distribution Segment results of operations for the twelve months ended December 31, 2001, 2000 and 1999 are shown below. These amounts include certain estimates and allocations where necessary. We have used Earnings before Interest and Income Taxes (EBIT) as a measure of segment operating performance. The EBIT measure is total operating revenues net of total operating expenses and other routine income and deductions from income. It differs from net income in that It does not take into account interest expense or income taxes. EBIT is believed to be a reasonable gauge of results of operations. By excluding interest and income taxes, EBIT does not give guidance regarding the demand of debt service or other interest requirements, or tax liabilities or taxation rates. The effects of interest expense and taxes on overall corporate performance can be seen in the consolidated income statement. Geographically our business is transacted in the United States. Of the registrant operating company subsidiaries, all of the registrant subsidiaries except AEGCo have two business segments. The segment results for each of these subsidiaries are reported in the table below. AEGCo has one segment, a wholesale generation business. AEGCo's results of operations are reported in AEGCo's financial statements.

12. Risk Management, Financial Instruments and Derivatives: Risk Management We are subject to market risks in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Management Committee and administered by Chief Risk Officer. The Risk Management Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers. The risks and related strategies that management can employ are: Risk Description Strategy Price Risk Volatility in Trading and commodity prices hedging Interest Rate Risk Changes in Interest rates Hedging Foreign Exchange Fluctuations in Risk foreign currency rates Hedging Credit Risk Non-performance on contracts Guarantees, with Collateral counterparties We employ physical forward purchase and sale contracts, over-the-counter options, swaps, and other derivative contracts to offset price risk where appropriate. However, we engage in trading of electricity, and to a lesser degree coal and emission allowances and as a result the we are subject to price risk. This risk is managed by the management of the trading operations, the Chief Risk Officer and the Risk Management Committee. If the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to the limits unless specifically approved by the Risk Management Committee. Although we do not hedge all commodity price exposure, manage-ment makes informed risk taking decisions supported by the above described risk management controls. We are exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of Texas (effective January 1, 2002) or frozen by settlement agreements in Indiana, Michigan and West Virginia. To the extent all fuel supply for the generating units in these states are not under fixed price long-term contracts, we are subject to market price risk. We continue to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. We employ fair value hedges, cash flow hedges and swaps to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. We do not hedge all interest rate risk. We employ cash flow forward hedge contracts to lock-in prices on transactions denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure. Our open trading contracts, including structured transactions, are marked-to-market daily using the price model and price curve(s) corresponding to the instrument. Forwards and swaps are generally valued by subtracting the contract price from the market price and then multiplying the difference by the contract volume and adjusting for net present value and other impacts. Significant estimates in valuing such contracts include forward price curves, volumes, seasonality, weather, and other factors. Forwards and swaps (which are a series of forwards) are valued based on forward price curves which represent a series of projected prices at which transactions can be executed in the market. The forward price curve includes the market's expectations for prices of a delivered commodity at that future date. The forward price curve is developed from the market bid price, which is the highest price which traders are willing to pay for a contract, and the ask or offer price, which is the lowest price traders are willing to receive for selling a contract. Options contracts, consisting primarily of options on forwards and spread options, are valued using models, which are variations on Black-Scholes option models. The market-related inputs are the interest rate curve, the underlying commodity forward price curve, and the implied volatility curve. Option prices or volatilities may be quoted in the market. Significant estimates in valuing these contracts include forward price curves, volumes, and other volatilities. Market prices utilized in valuing all forward contracts, OTC options, swaps and structured transactions represent mid-market price, which is the average of the bid and ask prices. These bids and offers come from brokers, on-line exchanges such as the Intercontinental Exchange, and directly from other counterparties. These prices exist for delivery periods and locations being traded or quoted and vary by period, location and commodity. For periods and locations that are not liquid and for which external information is not readily available, management uses the best information available to develop bid and ask prices and forward curves. Electricity markets have primary trading hubs or delivery points/regions and less liquid secondary delivery points. In North American natural gas markets, the primary delivery points are generally traded from Henry Hub, Louisiana. The less liquid gas or power trading points may trade as a spread (based on transportation costs, constraints, etc.) from the nearest liquid trading hub. Also, some commodities trade more often and therefore are more liquid than others. For example, peak electricity is a more liquid product than off-peak electricity. Henry Hub gas trades in monthly blocks for up to 36 months and after that only trades in seasonal or calendar blocks. In the near term, forward price curves for gas have a seasonal shape. They are based on market quotes beyond that. For all these factors, the curve used for valuation is the mid-point. At times bids or offers may not be available due to market events, volatility, constraints, long-dated part of the curve, etc. When this occurs, the Company uses its best judgment to estimate the curve values until actual values are available again. The value used will be based on various factors such as last trade price, recent price trend, product spreads, location spreads (including transportation costs), cross commodity spreads (e.g., heat rate conversion of gas to power), time spreads, cost of carry (e.g., cost of gas storage), marginal production cost, cost of new entrant capacity, and alternative fuel costs. Also, an energy commodity contract's price volatility generally increases as it approaches the delivery month. Spot price volatility (e.g., daily or hourly prices) can cause contract values to change substantially as open positions settle against spot prices. When a portion of a curve has been estimated for a period of time and market changes occur, assumptions are updated to align the company's curve to the market. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is based on credit ratings of counterparties and represents the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. The liquidity reserve essentially reserves half of the difference between bids and offers for each open position, such that the wider the bid-offer spread (indicating lower liquidity), the greater the reserve. We also mark to market derivatives that are not trading contracts in accordance with generally accepted accounting principles. There may be unique models for these transactions, but the curves the company inputs into the models are the same forward curves, which are described above. We have developed independent controls to evaluate the reasonableness of our valuation models and curves. However, there are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. Therefore, there could be a significant favorable or adverse effect on future results of operations and cash flows if market prices at settlement differ from the price models and curves. We limit credit risk by extending unsecured credit to entities based on internal ratings. We use Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. This data, in conjunction with the ratings information, is used to determine appropriate risk parameters. We also require cash deposits, letters of credit and parental/affiliate guarantees as security from certain below investment grade counterparties in our normal course of business. We trade electricity with numerous counterparties. Since our open energy trading contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that our credit and market exposures with any one counterparty is not material to financial condition at December 31, 2001. At December 31, 2001 less than 5% of the counterparties were below investment grade as expressed in terms of Net Mark to Market Assets. Net Mark to Market Assets represents the aggregate difference (either positive or negative) between the forward market price for the remaining term of the contract and the contractual price. We enter into transactions for electricity as part of wholesale trading operations. Electric transactions are executed over-the-counter with counterparties or through brokers. Brokers and counterparties require cash or cash related instruments to be deposited on these transactions as margin against open positions. These margin accounts are restricted and therefore are not included in cash and cash equivalents on the Balance Sheet. We can be subject to further margin requirements should related commodity prices change. The margin deposits at December 31, 2001 for the registrants were: (in thousands) APCo $2,832 CPL 299 CSP 1,736 I&M 1,879 KPCo 698 OPCo 2,862 PSO 247 SWEPCo 299 WTU 99 Financial Derivatives and Hedging In the first quarter of 2001, we adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 137 and SFAS 138. SFAS 133 requires that entities recognize all derivatives including fair value hedges as either assets or liabilities and measure such derivatives at fair value. Changes in the fair value of derivatives are included in earnings unless designated as a cash flow hedge. This practice is commonly referred to as mark-to-market accounting. Changes in the fair value of derivatives that are designated as effective cash flow hedges are included in other comprehensive income. Derivatives included in the transition adjustment are interest rate swaps, foreign currency swaps and commodity swaps, options and futures. The amounts of net revenue margins recorded in 2001, 2000 and 1999 for the registrant subsidiaries were: 2001 2000 1999 ---- ---- ---- (in thousands) APCo $78,521 $72,649 $28,970 CPL 15,711 3,385 - CSPCo 51,765 48,142 14,800 I&M 36,089 58,909 16,147 KPCo 12,466 23,417 5,563 OPCo 65,118 73,474 24,389 PSO (2,483) 9,268 - SWEPCo 7,897 6,404 - WTU (1,491) 1,821 - The fair value of open trading contracts that are marked-to-market are based on management's best estimates using over-the-counter quotations and exchange prices for short-term open trading contracts, and internally developed price curves for open long-term trading contracts. The fair values of trading contracts at December 31 are: 2001 2000 ------------------ -------------------- Fair Fair Value Value (in thousands) (in thousands) APCo Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 801,306 2,234,522 Options - OTC 46,649 59,814 Swaps 34,578 51,470 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (748,016) (2,258,596) Options - OTC (21,895) (35,955) Swaps (36,921) (44,855) KPCo Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 197,545 530,828 Options - OTC 11,503 14,207 Swaps 8,529 12,227 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (190,389) (536,512) Options - OTC (5,372) (8,521) Swaps (9,106) (10,656) 2001 2000 ------------------ -------------------- Fair Fair Value Value (in thousands) (in thousands) I&M Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 560,393 1,349,950 Options - OTC 31,397 36,139 Swaps 22,950 31,095 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (513,026) (1,371,793) Options - OTC (15,864) (25,807) Swaps (24,505) (27,099) OPCo Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 668,142 1,776,259 Options - OTC 38,108 46,731 Swaps 29,730 41,788 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (619,756) (1,792,417) Options - OTC (18,227) (29,350) Swaps (32,551) (37,398) CSPCo Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 491,290 1,192,203 Options - OTC 28,612 31,918 Swaps 21,211 27,461 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (456,613) (1,204,948) Options - OTC (13,403) (19,220) Swaps (22,648) (23,932) 2001 2000 ------------------ -------------------- Fair Fair Value Value (in thousands) (in thousands) CPL Trading Assets Electric Physicals $285,481 $ 542,626 Trading Liabilities Electric Physicals (281,624) (550,817) PSO Trading Assets Electric Physicals 217,415 431,186 Trading Liabilities Electric Physicals (214,981) (437,694) SWEPCo Trading Assets Electric Physicals 249,531 516,385 Trading Liabilities Electric Physicals (246,631) (524,180) WTU Trading Assets Electric Physicals 84,784 171,597 Trading Liabilities Electric Physicals (83,869) (174,187) The FASB's Derivatives Implementation Group (DIG) Issued guidance, effective in the third quarter of 2001, regarding the imple-mentation of SFAS 133 for certain fuel supply contracts with volume optionality and electricity capacity contracts. The guidance concluded that fuel supply contracts with volumetric optionality cannot qualify for a normal purchase or sale exclusion from mark-to-market accounting and provided guidance for determining when electricity capacity con-tracts can qualify as normal purchases or sales. Predominantly all of our contracts for coal, gas and electricity, which are recorded on a settlement basis, do not meet the criteria of a financial derivative instrument and qualify as normal purchases or sales. As a result they are exempt from the DIG guidance described above and have not been marked-to-market. Beginning July 1, 2001, the effective date of the DIG guidance, certain of our fuel supply contracts with volumetric optionality that qualify as financial derivative instruments are marked to market with any gain or loss recognized in the income statement. 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 trans-action. 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 of the item being hedged. Changes in the fair value that result from ineffectiveness of a hedge under SFAS 133 are recognized currently in earnings through mark-to-market accounting. Changes in the fair value of effective cash flow 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 the accounting periods in which the variability of cash flows of the hedged items affect earnings. 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 at December 31, 2001. (in thousands) APCo Transition Adjustment, January 1, 2001 $- Effective portion of changes in fair value (340) Reclasses from OCI to net income - -- Accumulated OCI derivative gain, December 31, 2001 $(340) ===== KPCo Transition Adjustment, January 1, 2001 $(557) Effective portion of changes in fair value (2,348) Reclasses from OCI to net income 1,002 ----- Accumulated OCI derivative gain, December 31, 2001 $(1,903) ======= I&M Transition Adjustment, January 1, 2001 $(317) Effective portion of changes in fair value (5,368) Reclasses from OCI to net income 1,850 ----- Accumulated OCI derivative gain, December 31, 2001 $(3,835) ======= OPCo Transition Adjustment, January 1, 2001 $- Effective portion of changes in fair value (196) Reclasses from OCI to net income - -- Accumulated OCI derivative gain, December 31, 2001 $(196) ===== 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 5 years. FINANCIAL INSTRUMENTS Market Valuation of Non-Derivative Financial Instrument The book values of cash and cash equivalents, accounts receivable, short-term debt and accounts payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. The fair values of long-term debt and preferred stock subject to mandatory redemption are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange. The book values and fair values of significant financial instruments for AEP's registrant subsidiaries December 31, 2001 and 2000 are summarized in the following tables.

Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The trust investments which are classified as held for sale for decommissioning and SNF disposal, reported in other assets, are recorded at market value in accordance with SFAS 115. At December 31, 2001 and 2000 the fair values of the trust investments were $933 million and $873 million, respectively, and had a cost basis of $839 million and $768 million, respectively. The change in market value in 2001, 2000, and 1999 was a net unrealized holding loss of $11 million, and net unrealized holding gain of $6 million, and $18 million, respectively.

We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for the years prior to 1991. We have received Revenue Agent's Reports from the IRS for the years 1991 through 1996, and have filed protests contesting certain proposed adjustments. Returns for the years 1997 through 2000 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations. COLI Litigation - On February 20, 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP in its suit against the United States over deductibility of interest claimed by AEP in its consolidated federal income tax returns related to its COLI program. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 we paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets pending the resolution of this matter. As a result of the U.S. District Court's decision to deny the COLI interest deductions, net income was reduced by the amounts shown in the table below in 2000. The Company has filed an appeal of the U.S. District Court's decision with the U.S. Court of Appeals for the 6th Circuit. The earnings reductions for affected registrant subsidiaries are as follows: (in millions) APCo $ 82 CSPCo 41 I&M 66 KPCo 8 OPCo 118 The AEP System companies join in the filing of a consolidated federal income tax return. The allocation of the AEP System's current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determing their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.

15. Leases: Leases of property, plant and equipment are for periods up to 35 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment for regulated operations. The components of rental costs are as follows:

Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets. CPL, PSO, SWEPCo and WTU do not lease property, plant and equipment under capital leases.

Operating leases include lease agreements with special purpose entities related to Rockport Plant Unit 2 and the Gavin Plant's flue gas desulfurization system (Gavin Scrubbers). The Rockport Plant lease resulted from a sale and leaseback transaction in 1989. The gain from the sale was deferred and is being amortized over the term of the lease which expires in 2022. The Gavin Scrubber lease expires in 2009. AEGCo and OPCo have no ownership interest in the special purpose entities and do not guarantee their debt. The special purpose entities are not consolidated in accordance with applicable accounting standards. As a result, neither the leased plant and equipment nor the debt of the special purpose entities is included in AEGCo or OPCo's balance sheets. The future lease payment obligations to the special purpose entities are included in the above table of future minimum lease payments under noncancellable operating leases. 16. Lines of Credit and Sale of Receivables: The AEP System uses short-term debt, primarily commercial paper, to meet fluctuations in working capital requirements and other interim capital needs. AEP has established a money pool to coordinate short-term borrowings for certain subsidiaries, including AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU and also incurs borrowings outside the money pool for other subsidiaries. The registrant subsidiaries incurred interest expense for amounts borrowed from the AEP money pool as follows: Year Ended December 31, 2001 2000 1999 (in millions) AEGCo 0.8 - - APCo 9.8 - - CPL 11.4 16.9 14.1 CSPCo 5.0 1.4 - I&M 13.1 0.8 - KPCo 2.3 - - OPCo 14.6 9.2 - PSO 6.3 7.5 2.0 SWEPCo 3.4 4.2 4.7 WTU 3.1 2.7 0.6 Interest income earned from amounts advanced to the AEP money pool by the registrant subsidiaries were: Year Ended December 31, 2001 2000 1999 (in millions) APCo 1.7 - - CPL 0.1 - - CSPCo 0.8 1.1 - I&M 1.6 9.0 - KPCo 0.1 1.8 - OPCo 8.6 3.4 - SWEPCo 0.1 - 0.1 WTU - - 0.2 Under a factoring arrangement the registrant subsidiaries (excluding AEGCo) sell without recourse certain of their customer accounts receivable and accrued utility revenue balances to AEP Credit and are charged a fee based on AEP Credit financing costs, uncollectible accounts experience for each company's receivables and administrative costs. The costs of factoring customer accounts receivable is reported as an operating expense. At December 31, 2001 the amount of factored accounts receivable and accrued utility revenues for each registrant subsidiary was as follows: Company (in millions) ------- APCo $ 61 CPL 89 CSPCo 106 I&M 95 KPCo 26 OPCo 100 PSO 43 SWEPCo 47 WTU 23 The fees paid by the registrant subsidiaries to AEP Credit for factoring customer accounts receivable were: Year Ended December 31, 2001 2000 1999 (in millions) APCo $ 5.2 $- $- CPL 14.7 15.7 14.7 CSPCo 15.2 10.8 - I&M 8.5 6.8 - KPCo 2.7 1.9 - OPCo 12.8 8.4 - PSO 9.6 8.3 6.5 SWEPCo 7.4 9.2 9.3 WTU 3.8 4.0 3.5

Each of the business trusts is treated as a subsidiary of its parent company. The only assets of the business trusts are the subordinated debentures issued by their parent company as specified above. In addition to the obligations under their subordinated debentures, each of the parent companies has also agreed to a security obligation which represents a full and unconditional guarantee of its capital trust obligation.\

The accumulated depreciation with respect to each AEP registrant subsidiary's share of jointly owned facilities is shown below: December 31, 2001 2000 ---- ---- (in thousands) CPL $863,130 $834,722 CSPCo 410,756 389,558 PSO 35,653 33,669 SWEPCo 392,728 367,558 WTU 100,430 98,045 20. Related Party Transactions AEP System Power Pool APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company's "member-load-ratio," which is calculated monthly on the basis of each company's maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO2 Allowances associated with transactions under the Interconnection Agreement. As part of AEP's restructuring settlement agreement filed with FERC, CSPCo and OPCo would no longer be parties to the Interconnection agreement and certain other modifications to its terms would also be made. Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement. Trading activities involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options and over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the AEP System's traditional marketing area and are typically settled by entering into offsetting contracts. The regulated physical forward purchase and sale contracts are recorded in operating revenues on a net basis in the month when the contract settles. In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area. CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement). The CSW Operating Agreement requires the operating companies of the west zone to maintain specified annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP subsidiaries as capacity commitments. The CSW Operating Agreement also delegates to AEP Service Corporation the authority to coordinate the acquisition, disposition, planning, design and construction of generating units and to supervise the operation and maintenance of a central control center. The CSW Operating Agreement has been accepted for filing and allowed to become effective by FERC. AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the distribution, between the two operating zones, of costs and benefits associated with the System's generating plants. It is designed to function as an umbrella agreement in addition to the AEP Interconnection Agreement and the CSW Operating Agreement, each of which will continue to control the distribution of costs and benefits within each zone.

AEP System Transmission Pool APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kv and above) and certain facilities operated at lower voltages (138 kv and above). Like the Interconnection Agreement, this sharing is based upon each company's "member-load-ratio." The following table shows the net (credits) or charges allocated among the parties to the Transmission Agreement during the years ended December 31, 1998, 1999 and 2000: 1999 2000 2001 ---- ---- ---- (in thousands) APCo $ (8,300) $ (3,400) $ (3,100) CSPCo 39,000 38,300 40,200 I&M (43,900) (43,800) (41,300) KPCo (4,300) (6,000) (4,600) OPCo 17,500 14,900 8,800 CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Transmission Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA established a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone operating subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the Open Access Transmission Tariff (OATT) filed with the FERC and the rules of the FERC relating to such tariff. Under the TCA, the west zone operating subsidiaries have delegated to AEP Service Corporation the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The TCA also provides for the allocation among the west zone operating subsidiaries of revenues collected for transmission and ancillary services provided under the OATT. AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone operating subsidiaries. Like the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the AEP Transmission Agreement and the Transmission Coordination Agreement. The System Transmission Integration Agreement contains two service schedules that govern: o The allocation of transmission costs and revenues. o The allocation of third-party transmission costs and revenues and System dispatch costs. The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant. Unit Power Agreements and Other A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo unit power agreement expires on December 31, 2004. APCo and OPCo, jointly own two power plants. The costs of operating these facilities are apportioned between the owners based on ownership interests. Each company's share of these costs is included in the appropriate expense accounts on each company's consolidated statements of income. Each company's investment in these plants is included in electric utility plant on its consolidated balance sheets. I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from barging services as nonoperating income. AEGCo, APCo and OPCo record costs paid to I&M for barging services as fuel expense. The amount of affiliated revenues and affiliated expenses were: Year Ended December 31, 2001 2000 1999 ---- ---- ---- Company (in millions) I&M - revenues $30.2 $23.5 $28.1 AEGCo - expense 8.5 8.8 8.5 APCo - expense 11.5 7.8 10.5 OPCo - expense 10.2 6.9 9.1 American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable bases of proration for shared services. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act. 21. Subsequent Events - Affecting APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU During 2002, the EITF discussed Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17" (EITF 02-3) and reached consensus on certain issues. EITF 98-10, "Accounting for Contracts Involving Energy Trading and Risk Management Activities," requires that energy trading contracts be accounted for at fair value. EITF 02-3 rescinds Issue No. 98-10 effective for any new contracts entered into after October 25, 2002. For energy trading contracts entered into through October 25, 2002, such contracts will continue to be accounted for at fair value through December 31, 2002. Effective January 1, 2003, such contracts are required to be accounted for at historical cost and we will report this as a cumulative effect of an accounting change. Our energy contracts that qualify as derivatives will continue to be accounted for at fair value under SFAS 133. EITF 02-3 requires that all derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis effective January 1, 2003. Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, we reclassified such forward trading activity to a net basis of reporting, as permitted by EITF 98-10, which resulted in a substantial reduction in both operating revenues and purchased energy as well as nonoperating income and expense for APCo, CSPCo, OPCo, KPCo, and I&M. In addition, for PSO and SWEPCo a reclassification was made for 2001 between Electricity Marketing and Trading Purchased Power and AEP Affiliates Purchase Power in order for its presentation to be consistent with the new net basis presentation that was adopted. These reclassifications did not have any impact on our financial conditions, results of operations or cash flows. 22. Subsequent Events (Unaudited) - Affecting CPL and WTU Plant Closings and Staff Reductions - Affecting CPL and WTU In September 2002 AEP proposed closing 16 gas-fired power plants in the ERCOT control area of Texas (8 WTU plants and 8 CPL plants). ERCOT indicated that it may designate some of those plants as "reliability must run" (RMR) status. In October ERCOT designated seven RMR plants (3 WTU plants and 4 CPL plants) and approved AEP's plan to inactivate nine other plants (5 WTU plants and 4 CPL plants). The process of moving the plants to inactive status will take up to two months. Employees of the plants to become inactive (approximately 183) will be eligible for severance and outplacement services. RMR plants are required to ensure the reliability of the power grid, even if electricity from those plants is not required to meet market needs. ERCOT and AEP negotiated interim contracts for the remainder of 2002 for the seven RMR plants. It is expected that 2003 RMR requirements will be announced before the end of 2002. As a result of the decision to inactivate WTU plants, a write-down of utility assets of approximately $34 million (pre-tax) was recorded in Other Operation expense during the third quarter. The decision to inactivate the CPL plants resulted in a write-down of utility assets of approximately $100 million which was deferred and recorded in Regulatory Assets. Inventory on hand to service the 16 plants is being evaluated for use at other plants within the AEP System as part of the closing process. A write-down, if any, associated with inventory becoming obsolete as a result of the plant closings will be recorded as identified during the closing process. Severance benefit arrangements for employees at these plants are expected to be finalized in the fourth quarter of 2002. Wind Project - Affecting WTU WTU is assessing recoverability of certain wind generating assets due to performance concerns. The net book value of these assets is approximately $5 million as of December 31, 2001. 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's registrant subsidiaries. Management's discussion and analysis of results of operations for each of AEP's subsidiary registrants is presented with their financial statements earlier in this document. The following is a list of sections of management's discussion and analysis of financial condition, contingencies and other matters and the registrant to which they apply: Financial Condition APCo, CPL, I&M, OPCo, SWEPCo Market Risks AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU Industry Restructuring APCo, CPL, CSPCo, I&M, OPCo, PSO, SWEPCo, WTU Litigation AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU Environmental Concerns and Issues APCo, CPL, CSPCo, I&M, OPCo, SWEPCo Other Matters AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU Financial Condition - Affecting APCo, CPL, I&M, OPCo and SWEPCo We measure our financial condition by the strength of the balance sheet and the liquidity provided by cash flows and earnings. Balance sheet capitalization ratios and cash flow ratios are principal determinants of our credit quality. Year-end ratings of AEP's subsidiaries' first mortgage bonds are listed in the following table: Company Moody's S&P Fitch APCo A3 A A- CPL A3 A- A CSPCo A3 A- A I&M Baa1 A- BBB+ KPCo Baa1 A- BBB+ OPCo A3 A- A- PSO A1 A A+ SWEPCO A1 A A+ WTU A2 A- A The ratings at the end of the year for senior unsecured debt are listed in the following table: Company Moody's S&P Fitch APCo Baa1 BBB+ BBB+ CPL Baa1 BBB+ A- CSPCo A3 BBB+ A- I&M Baa2 BBB+ BBB KPCo Baa2 BBB+ BBB OPCo A3 BBB+ BBB+ PSO A2 BBB+ A SWEPCO A2 BBB+ A o The rating is for a series of senior notes issued with a Support Agreement from AEP. Rating agencies have become more focused in their evaluation of credit quality as a result of the Enron bankruptcy. They are focusing especially on the composition of the balance sheet (off-balance sheet leases, debt and special purpose financing structures), the cash liquidity profile and the impact of credit quality downgrades on financing transactions. We have worked closely with the agencies to provide them with all the information they need, but we are unable to predict what actions, if any, they may take regarding our current ratings. Cash from operations and short-term borrowings provide working capital and meet other short-term cash needs. We generally use short-term borrowings to fund property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include long-term debt and sale-leaseback or leasing arrangements. The electric subsidiaries generally issue short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt and additional capital contributions from their parent company. AEP operates a money pool and sells accounts receivables to provide liquidity for the electric subsidiaries. For the AEP subsidiary registrants' contractual obligations please see each registrant's schedules of capitalization and long-term debt included with each registrants' financial statements in sections B through J for the timing of debt payment obligations and the lease footnote (Note 15) in section L for the timing of rent payments. Special purpose entities have been employed for certain contractual cash obligations. The lease of Rockport Plant Unit 2 and the Gavin Plant's flue gas desulfurization system (Gavin Scrubbers) use special purpose entities. Neither the AEP System companies nor any related parties have an ownership interest in the special purpose entities or provides a guarantee for the debt of these entities. These special purpose entities are not consolidated in any AEP System companies' financial statements in accordance with generally accepted accounting principles. As a result, neither the assets nor the debt of the special purpose entities is included on any AEP System company balance sheet. Certain AEP subsidiaries make commitments in the normal course of business. These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds, and other commitments. SWEPCo guarantanees an unaffiliated mine operator's obligations (payable upon their default) of $111 million at December 31, 2001, and OPCo has obligations under a power purchase agreement of $6 million in 2002 and $16 million each year in 2003 through 2005. OPCo has entered into a purchased power agreement to purchase electricity pro-duced by an unaffiliated entity's three-unit natural gas fired plant that is under construction. The first unit is anticipated to be completed in October 2002 and the agree-ment will terminate 30 years after the third unit begins operation. Under the terms of the agreement OPCo has the option to run the plant until December 31, 2005 taking 100% of the power generated. For the remainder of the 30 year contract term, OPCo will pay the variable costs to generate the electricity it pur-chases which could be up to 20% of the plant's capacity. The estimated fixed pay-ments through December 2005 are $55 million and are included in the Other Commercial Commitments table shown above. Construction expenditures for the registrant subsidiaries for the next three years excluding AFUDC are: Construction Projected Expenditures Construction Financed with Expenditures Internal Funds (in millions) APCo $ 815.5 92% CPL 573.1 80% I&M 556.9 ALL OPCo 1,008.0 68% SWEPCo 321.4 92% Financing Activity In 2001 CSPCo and OPCo, AEP's Ohio subsidiaries, reacquired $295.5 million and $175.6 million, respectively, of first mortgage bonds in preparation for corporate separation. AEP Credit purchases, without recourse, the accounts receivable of most of the domestic utility operating companies and certain non-affiliated electric utility companies. In February 2002 CPL issued $797 million of securitization notes that were approved by the PUCT as part of Texas restructuring to help decrease rates and recover regulatory assets. The proceeds were used to reduce CPL's debt and equity. In 2002 AEP plans to continue restructuring its debt for corporate separation assuming receipt of all necessary regulatory approvals. Corporate separation will require the transfer of assets between legal entities. With corporate separation, a newly created holding company for the unregulated business is expected to issue all debt needed to fund the wholesale business and unregulated generating companies. The size and maturity lengths of the original offering is presently being determined. The regulated holding company is expected to issue the debt needed by the wires companies in Ohio and Texas. The regulated integrated utility companies will continue their current debt structure until the regulatory commissions approve changes. At that time, the regulated holding company may also issue the debt for the regulated companies' funding needs. We have requested credit ratings for the holding companies consistent with our existing credit quality, but we cannot predict what the outcome will be. AEP uses a money pool to meet the short-term borrowings for certain of its subsidiaries, primarily the electric utility operations. Following corporate separation, the current money pool which was approved by the appropriate regulatory authorities will continue to service the regulated business subsidiaries. Market Risks - Affecting AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU As a major power producer and trader of wholesale electricity, we have certain market risks inherent in our business activities. These risks include com-modity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates. Policies and procedures are established to identify, assess, and manage market risk exposures in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Management Committee and administered by a Chief Risk Officer. The Risk Management Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers. We use a risk measurement model which calculates Value at Risk (VaR) to measure our commodity price risk. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assuming a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2001 a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition. The following table shows the high, average, and low market risk as measured by VaR at: December 31, 2001 2000 ---- ---- High Average Low High Average Low (in millions) APCo $4 $1 - $6 $2 - CPL 3 1 - 4 1 - CSPCo 2 1 - 3 1 - I&M 3 1 - 4 1 - KPCo 1 - - 1 - - OPCo 3 1 - 5 2 - PSO 2 1 - 3 1 - SWEPCo 3 1 - 4 1 - WTU 1 1 - 1 - - We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one year holding period. The volatilities and correlations were based on three years of weekly prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, is detailed in the table below. However, since we would not expect to liquidate our entire debt portfolio in a one year holding period, a near term change in interest rates should not materially affect results of operations or consolidated financial position. The following table shows the potential loss in fair value as measured by VaR allocated to the AEP registrant subsidiaries based upon debt outstanding: VaR for Registrant Subsidiaries: December 31, 2001 2000 (in millions) Company AEGCo $5 $4 APCo 100 149 CPL 80 135 CSPCo 60 84 I&M 86 129 KPCo 16 31 OPCo 59 112 PSO 17 44 SWEPCo 36 60 WTU 20 24 AEGCo is not exposed to risk from changes in interest rates on short-term and long-term borrowings used to finance operations since financing costs are recovered through the unit power agreements. We are exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001 for CSPCo and OPCo) and in the ERCOT area of Texas (effective January 1, 2002 for CPL and WTU) or frozen by settlement agreements in Indiana, Michigan and West Virginia. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts we our subject to market price risk. We continue to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. We employ physical forward purchase and sale contracts, over-the-counter options, swaps, and other derivative contracts to offset price risk where appropriate. However, we engage in trading of electricity, and to a lesser degree coal, and emission allowances and as a result are subject to price risk. The amount of risk taken by the traders is controlled by the management of the trading operations and the Chief Risk Officer and his staff. When the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to the limits unless specifically approved by the Risk Management Committee. We employ fair value hedges, cash flow hedges and swaps to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. We do not hedge all interest rate risk. We employ cash flow forward hedge contracts to lock-in prices on transactions denominated in foreign currencies where deemed necessary. We limit credit risk by extending unsecured credit to entities based on internal ratings. In addition, we use Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. This data, in conjunction with the ratings information, is used to determine appropriate risk parameters. We also require cash deposits, letters of credit and parental/affiliate guarantees as security from certain below investment grade counterparties in our normal course of business. We trade electricity contracts with numerous counterparties. Since our open energy trading contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that our credit and market exposures with any one counterparty is not material to financial condition at December 31, 2001. At December 31, 2001 less than 5% of the counterparties were below investment grade as expressed in terms of Net Mark to Market Assets. Net Mark to Market Assets represents the aggregate difference (either positive or negative) between the forward market price for the remaining term of the contract and the contractual price. The following table approximates counterparty credit quality that is generally consistent for all registrant subsidiaries. Futures, Forward and Swap Counterparty Contracts Options Total Credit Quality: December 31, 2001 (in millions) AAA/Exchanges $ 147 $- $ 147 AA 140 4 144 A 304 7 311 BBB 932 34 966 Below Investment Grade 23 ------- --- -- 56 79 -- Total $1,579 $68 $1,647 ====== === ====== We enter into transactions for electricity as part of wholesale trading operations. Electric transactions are executed over the counter with counterparties or through brokers. Brokers and counterparties require cash or cash related instruments to be deposited on these transactions as margin against open positions. We can be subject to further margin requirements should related commodity prices change. We recognize the net change in the fair value of all open trading contracts, a practice commonly called mark-to-market accounting, in accordance with generally accepted accounting principles and include the net change in mark-to-market amounts on a net discounted basis in revenues. The fair values of open short-term trading contracts are based on exchange prices and broker quotes. The fair value of open long-term trading contracts are based mainly on internally developed valuation models. The valuation models produce an estimated fair value for open long-term trading contracts. This fair value is present valued and reduced by appropriate reserves for counterparty credit risks and liquidity risk. The models are derived from internally assessed market prices. Forward price curves are developed for inclusion in the model based on broker quotes and other available market data. The curves are within the range between the bid and ask prices. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid price of the bid ask prices if we have a long position and the ask side if we have a short position. This provides for a conservative valuation net of the reserves. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market risks, at the time of settlement, do not correlate with the internally developed price models. The effect on the statements of income of marking to market open electricity trading contracts in the Company's regulated jurisdictions is deferred as regulatory assets or liabilities since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading are reported as assets or liabilities. The table "Energy Trading Contracts" disaggregates realized and unrealized changes in fair value; identifies changes in fair value as a result of changes in valuation methodologies; and reconciles the net fair value of energy trading contracts at the beginning of the year to the end of the year. Contracts realized/settled during the period include both sales and purchase contracts. The table "Energy Trading Contract Maturities" shows exposures to changes in fair values and realization periods over time for each method used to determine fair value.

We have investments in debt and equity securities which are held in nuclear trust funds. The trust investments and their fair value are discussed in Note 12, "Risk Management, Financial Instruments and Derivatives." Financial instruments in these trust funds have not been included in the market risk calculation for interest rates as these instruments are marked-to-market and changes in market value of these instruments are reflected in a corresponding decommissioning liability. Any differences between the trust fund assets and the ultimate liability are expected to be recovered through regulated rates from our regulated customers. Inflation affects our cost of replacing utility plant and the cost of operating and maintaining plant. The rate-making process limits recovery to the historical cost of assets, resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses. Industry Restructuring In 2000 California's deregulated electricity market suffered problems including high energy prices mainly due to short energy supplies and financial difficulties for retail distribution companies. This energy crisis has highlighted the importance of risk management and has contributed to certain state regulatory and legislative actions which have delayed the start of customer choice and the transition to competitive, market based pricing for retail electricity supply in some of the states in which AEP System companies operate. Seven of the eleven state retail jurisdictions in which the AEP electric utility companies operate have enacted restructuring legislation. In general, 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. As legislative and regulatory proceedings evolved, six AEP electric operating companies (APCo, CPL, CSPCo, OPCo, SWEPCo and WTU) doing business in five of the seven states that have passed restructuring legislation have discontinued the application of SFAS 71 regulatory accounting for the generation business. The seven states in various stages of restructuring to transition power generation and supply to market based pricing are Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia, and West Virginia. Regulatory accounting has not been discontinued for subsidiaries doing business in Michigan and Oklahoma pending the effective implementation of the legislation. Restructuring legislation, the status of the transition plans and the status of the electric utility companies' accounting to comply with the changes in the seven state regulatory jurisdictions affected by restructuring legislation is presented in the Note 7 of the Notes to Financial Statements. RTO Formation FERC Order No. 2000 and many of the settlement agreements with the FERC and state regulatory commissions to approve the AEP-CSW Merger have provisions for the transfer of functional control of our transmission system to an RTO. Certain AEP registrant subsidiaries are participating in the formation of the Alliance RTO. Other subsidiaries are a member of ERCOT or SPP. In 2001 the Alliance companies and MISO entered into a settlement addressing transmission pricing and other "seam" issues between the two RTOs. The FERC subsequently expressed its opinion that four large RTO regions serving the continental US would best support competition and reliability of electric service. Certain state regulatory commissions have taken exception to the FERC's RTO actions. Louisiana's commission ordered utilities it regulates, including SWEPCo, to show the advantage of large RTOs to their customers. On December 19, 2001 the FERC approved the proposal of the Midwest ISO for a regional transmission organization and told the Alliance companies, which had submitted a separate RTO proposal, to explore joining the Midwest ISO organization. The FERC's order is intended to facilitate the establishment of a single RTO in the Midwest and to support the establishment of viable, for-profit transmission companies under an RTO umbrella and concluded that the RTO proposed by Alliance companies lacks sufficient scope to exist as a stand-alone RTO and thus directed the Alliance companies to explore how their business plan can be accommodated within the Midwest ISO. Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, AEP System companies transmission operations or future results of operations and cash flows. Litigation AEP System companies are involved in various litigation. The details of significant litigation contingencies are disclosed in Note 8 and summarized below. COLI - Affecting APCo, CSPCo, I&M, KPCo and OPCo A decision by U.S. District Court for the Southern District of Ohio in February 2001 that denied AEP's deduction of interest claimed on AEP's consolidated federal income tax returns related to its COLI program resulted in a reduction in net income for 2000. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 AEP and the impacted subsidiaries paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 for APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other property and investments on the balance sheets pending the resolution of this matter. AEP has appealed the Court's decision. The earnings reductions for affected registrant subsidiaries are as follows: (in millions) APCo $ 82 CSPCo 41 I&M 66 KPCo 8 OPCo 118 FERC Wholesale Fuel Complaints - Affecting WTU In November 2001 certain WTU wholesale customers filed a complaint with FERC alleging that WTU has overcharged them since 1997 through the fuel adjustment clause. The customers allege inappropriate costs related to purchased power were included in the fuel adjustment clause. Management is working to compute if any overcharges occurred and is unable to predict their impact on results of operations, cash flow and financial condition. Municipal Franchise Fee Litigation - Affecting CPL In 2001 CPL paid $11 million to settle class action litigation regarding municipal franchise fees in Texas. The City of San Juan, Texas had filed a class action lawsuit in 1996 seeking $300 million in damages. Texas Base Rate Litigation - Affecting CPL In 2001 the Texas Supreme Court denied CPL's request for the court to review a 1997 PUCT base rate order. Subsequently the Court also denied CPL's rehearing request. The primary issues CPL requested the Court to review were: o the classification of $800 million of invested capital in STP as ECOM and assigning it a lower return on equity than other generation property; o and an $18 million disallowance of affiliated service billings. Lignite Mining Agreement Litigation - Affecting SWEPCo In 2001 SWEPCo settled litigation concerning lignite mining in Louisiana. Since 1997 SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO, an unaffiliated utility, are each a 50% owner of the Dolet Hills Power Station Unit 1 and jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. Under terms of a settlement, SWEPCo purchased an unaffiliated mine operator's interest in the mining operations and related debt and other obligations for $86 million. Merger Litigation - Affecting all AEP Subsidiary Registrants In January 2002, a federal court ruled that the SEC failed to prove that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably. Other - Affecting all AEP Subsidiary Registrants AEP registrant subsidiaries are involved in a number of other legal proceedings and claims. While management is unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on the results of operations, cash flows or financial condition. Environmental Concerns and Issues The U.S. continues to debate an array of environmental issues affecting the electric utility industry including new emission limitations recommended by the Bush Administration in February 2002. Most of the policies are aimed at reducing air emissions citing alleged impacts of such emissions on public health, sensitive ecosystems or the global climate. AEP's subsidiaries policy on the environment continues to be the development and application of long-term economically feasible measures to improve air and water quality, limit emissions and protect the health of employees, customers, neighbors and others impacted by their operations. In support of this policy, we continue to invest in research through groups like the Electric Power Research Institute and directly through demonstration projects for new technology for the capture and storage of carbon dioxide, mercury, NOx and other emissions. The AEP System companies intend to continue in a leadership role to protect and preserve the environment while providing vital energy commodities and services to customers at fair prices. AEP's registrant subsidiaries have a proven record of efficiently producing and delivering electricity and gas while minimizing the impact on the environment. AEP's registrant subsidiaries have spent billions of dollars to equip their facilities with the latest cost effective clean air and water technologies and to research new technologies. We are proud of our award winning efforts to reclaim our mining properties. The introduction of multi-pollutant control legislation is being discussed by members of Congress and the Bush Administration. The legislation being considered may regulate carbon dioxide, NOx, sulfur dioxide, mercury and other emissions from electric generating plants. Management will continue to support solutions which are based on sound science, economics and demonstrated control technologies. Management is unable to predict the timing or magnitude of additional pollution control laws or regulations. If additional control technology is required on facilities owned by the electric utility companies and their costs were not recoverable from ratepayers or through market based prices or volumes of product sold, they could adversely affect future results of operations and cash flows. The following discussions explains existing control efforts, litigation and other pending matters related to environmental issues for AEP System companies. Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M and OPCo Since 1999 APCo, CSPCo, I&M and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA, a number of states and certain special interest grups alleged that APCo, CSPCo, I&M and OPCo modified certain generating units over a 20 year period in violation of the Clean Air Act. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. We believe our maintenance, repair and replacement activities were in conformity with the Clean Air Act and intend to vigorously pursue our defense. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In March 2001 the District Court ruled that claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief. Management is unable to estimate a loss or predict the timing of the resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If we do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition. An unaffiliated utility which operates certain plants jointly owned by CSPCo reached a tentative agreement to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing and a settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future results of operations and cash flows. NOx Reduction - Affecting APCo, CPL, I&M, OPCo and SWEPCo Federal EPA issued a NOx rule (the NOx Rule) and granted petitions filed by certain northeastern states (the Section 126 Rule) requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. Federal EPA ruled that eleven states, including certain states in which AEP's generating units are located, failed to submit approvable plans to comply with the NOx Rule. This ruling means that those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. A request for the D.C. Circuit Court to review this ruling is pending. The compliance date for the NOx Rule is May 31, 2004. The D.C. Circuit Court instructed Federal EPA to justify methods used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. In response to AEP and other utilities request for the D.C. Circuit Court to suspend the May 2003 compliance date of the Section 126 Rule, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. In April 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. In 2001 selective catalytic reduction (SCR) technology to reduce NOx emissions on OPCo's Gavin Plant commenced operation. Construction of SCR technology at certain other generating units continues with completion scheduled in 2002 through 2006. Our estimates indicate that compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures for certain of AEP's registrant subsidiaries. Estimated Amounts Compliance Costs Spent ---------------- ------- (in millions) Company APCo $365 $130 CPL 57 4 I&M 202 - OPCo 606 277 SWEPCo 28 21 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs of additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Superfund - Affecting APCo, CPL, CSPCo, I&M, OPCo and SWEPCo By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, PCBs and other hazardous and non-hazardous materials. We are currently incurring costs to safely dispose of these substances. Additional costs could be incurred to comply with new laws and regulations if enacted. Superfund addresses clean-up of hazardous substances at disposal sites and authorized Federal EPA to administer the clean-up programs. As of year-end 2001, certain AEP registrant subsidiaries have been named by the Federal EPA as a PRP for five sites. APCo, CSPCo, and OPCo each have one PRP site and I&M has two PRP sites. There are four additional sites for which APCo, CSPCo, I&M, OPCo and SWEPCo have received information requests which could lead to PRP designation. CPL, OPCo and SWEPCo have also been named a PRP at two sites under state law. Our liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where certain AEP registrant subsidiaries have been named a PRP or defendant, their disposal or recycling activities were in accordance with the then-applicable laws and regulations. Unfortunately, Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding certain AEP registrant subsidiaries' potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Although liability is joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which we have been declared PRPs. If significant cleanup costs are attributed to certain AEP registrant subsidiaries in the future under Superfund, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered from customers. Global Climate Change - Affecting all AEP Registrant Subsidiaries At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly carbon dioxide, which many scientists believe are contributing to global climate change. Although the U.S. signed the Kyoto Protocol on November 12, 1998, the treaty was not submitted to the Senate for its advice and consent by President Clinton. In March 2001 President Bush announced his opposition to the treaty and its U.S. ratification. At the Seventh Conference of the Parties in November 2001, the parties finalized the rules, procedures and guidelines required to facilitate ratification of the protocol. The protocol is expected to become effective by 2003. U.S. representatives attended the Seventh Conference but they did not take any positions on issues being negotiated or attempt to block the approval of any issue. AEP does not support the Kyoto Protocol but intends to work with the Bush Administration and U.S. Congress to develop responsible public policy on this issue. Management expects due to President Bush's opposition to legislation mandating greenhouse gas emissions controls, any policies developed and implemented in the near future are likely to encourage voluntary measures to reduce, avoid or sequester such emissions. Costs for Spent Nuclear Fuel and Decommissioning - Affecting CPL and I&M I&M, as the owner of the Cook Plant, and CPL, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste. By law CPL and I&M participate in the DOE's SNF disposal program which is described in Note 8 of the Notes to Financial Statements. Since 1983 I&M has collected $288 million from customers for the disposal of nuclear fuel consumed at the Cook Plant. $116 million of these funds have been deposited in external trust funds to provide for the future disposal of SNF and $172 million has been remitted to the DOE. CPL has collected and remitted to the DOE, $49 million for the future disposal of SNF since STP began operation in the late 1980s. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel. However, in 1996, the DOE notified the companies that it would be unable to begin accepting SNF by the January 1998 deadline required by law. To date DOE has failed to comply with the requirements of the Nuclear Waste Policy Act. As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and STPNOC on behalf of CPL and the other STP owners, along with a number of unaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C. Circuit Court order DOE to meet its obligations under the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities. In August 2000, in an appeal of related cases involving other unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held that the delays clause of the standard contract between utilities and the DOE did not apply to DOE's complete failure to perform its contract obligations, and that the utilities' suits against DOE may continue in court. AEP's and I&M's suit has been stayed pending further action by the U.S. Court of Federal Claims. As long as the delay in the availability of a government approved storage repository for SNF continues, the cost of both temporary and permanent storage and the cost of decommissioning will continue to increase. In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related to DOE's nuclear waste fund cost recovery settlement with PECO Energy Corporation. The settlement allows PECO to skip two payments to the DOE for disposal of SNF due to the lack of progress towards development of a permanent repository for SNF. The companies believe the settlement is unlawful as the settlement would force other utilities to make up any shortfall in DOE's SNF disposal funds. The cost to decommission nuclear plants is affected by both NRC regulations and the delayed SNF disposal program. Studies completed in 2000 estimate the cost to decommission the Cook Plant ranges from $783 million to $1,481 million in 2000 non-discounted dollars. External trust funds have been established with amounts collected from customers to decommission the plant. At December 31, 2001, the total decom-missioning trust fund balance for Cook Plant was $598 million which includes earnings on the trust investments. Studies completed in 1999 for STP estimate CPL's share of decommissioning cost to be $289 million in 1999 non-discounted dollars. Amounts collected from customers to decommission STP have been placed in an external trust. At December 31, 2001, the total decommission-ing trust fund for CPL's share of STP was $99 million which includes earnings on the trust investments. Estimates from the decommissioning studies could continue to escalate due to the uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site. We will work with regulators and customers to recover the remaining estimated costs of decommissioning Cook Plant and STP. However, CPL's and I&M's future results of operations, cash flows and possibly their financial conditions would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. AEP's registrant subsidiaries are exposed to other environmental concerns which are not considered to be material or potentially material at this time. Should they become significant or should any new concerns be uncovered that are material they could have a material adverse effect on results of operations and possibly financial condition. We perform environmental reviews and audits on a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues. APCo operates in Virginia and West Virginia, and has been seeking regulatory approval to build a new high voltage transmission line for over a decade. Through December 31, 2001 we have invested approximately $40 million in this effort. If the required regulatory approvals are not obtained and the line is not constructed, the $40 million investment would be written off adversely affecting APCo's future results of operations and cash flows. OTHER MATTERS Enron Bankruptcy - Affecting APCo, CSPCo, I&M, KPCo and OPCo At the date of Enron's bankruptcy certain electric operating companies had open trading contracts and trading accounts receivables and payables with Enron. The amounts for certain subsidiary registrants were: Amounts Amounts Net of Registrant Provided Tax -------- -- --- (in millions) APCo $5.2 3.4 CSPCo 3.2 2.1 I&M 3.4 2.2 KPCo 1.3 0.8 OPCo 4.3 2.8 The amounts provided were based on an analysis of contracts where AEP and Enron are counterparties, the offsetting of receivables and payables, and the application of deposits from Enron. If there are any adverse unforeseen developments in the bankruptcy proceedings, our future results of operations, cash flows and possibly financial condition could be adversely impacted. New Accounting Standards - Affecting AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU The FASB recently issued SFAS 141, "Business Combinations" and SFAS 142, "Goodwill And Other Intangible Assets." SFAS 141 requires that the purchase method of accounting be used to account for all business combinations entered into after June 30, 2001. SFAS 142 requires that goodwill amortization cease and that goodwill and other intangible assets with indefinite lives be tested for impairment upon SFAS 142 implementation and annually thereafter. The registrant subsidiaries did not have significant goodwill at December 31, 2001. SFAS 143, "Accounting for Asset Retirement Obligations," will become effective for us beginning January 1, 2003. SFAS 143 established accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. We are currently in the process of evaluating the provisions of the standard and determining its impact on future results of operations and financial condition. To the extent AEP's registrant subsidiaries are regulated entities, we anticipate that the cumulative effect of this accounting change on future results of operations will be significantly offset by a regulatory asset representing the right to recover legal asset retirement obligations (ARO) relative to regulated long lived assets included in rate base. The impact on future results of operations from the implementation of this new standard on non-regulated long lived assets has not yet been determined. We anticipate that the considerable effort to identify all long lived assets with legal ARO and to determine the required discounted legal ARO will take the remainder of 2002. In August 2001 the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-lived Assets" which sets forth the accounting to recognize and measure an impairment loss. This standard replaces the previous standard, SFAS 121, "Accounting for the Long-lived Assets and for Long-lived Assets to be Disposed Of." SFAS 144 will apply to us beginning January 1, 2002. We do not expect that the imple-mentation of SFAS 144 will materially affect results of operations or financial condition. The FASB recently revised its prior guidance related to SFAS 133, "Accounting for Deriviative Instruments and Hedging Activities" with regard to certain power option and forward contracts. The revised guidance states that power contracts, including both forward and option contracts, that include certain qualitative characteristics are considered capacity contracts, and qualify for the normal purchases and normal sales exception from being marked to market even if they are subject to being booked out, or scheduled to be booked out. As normal purchases and sales these open energy contracts are not marked to market. Rather they are accounted for on a settlement basis. Most of AEP System companies' power contracts that are not marked to market as trading transactions do not qualify as derivatives and thus are not subject to the revised guidance. The few contracts that are derivatives qualified for the exception under the previous guidance and will continue to qualify under the new guidance. Item 7. Financial Statements and Exhibits. (c) Exhibits 23.1 Consent of Deloitte & Touche LLP for APCo 23.2 Consent of Deloitte & Touche LLP for CPL 23.3 Consent of Deloitte & Touche LLP for CSP 23.4 Consent of Deloitte & Touche LLP for I&M 23.5 Consent of Deloitte & Touche LLP for KPCo 23.6 Consent of Deloitte & Touche LLP for OPCo 23.7 Consent of Deloitte & Touche LLP for PSO 23.8 Consent of Deloitte & Touche LLP for SWEPCo 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 signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. 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/Joseph M. Buonaiuto ---------------------------- Joseph M. Buonaiuto Controller and Chief Accounting Officer Date: November 18, 2002 Exhibit 23.1 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-100451 of Appalachian Power Company on Form S-3 of our report dated February 22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of Appalachian Power Company. Deloitte & Touche LLP Columbus, Ohio November 18, 2002 Exhibit 23.2 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-49577 and 33-52759 of Central Power and Light Company on Form S-3 of our report dated February 22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of Central Power and Light Company. Deloitte & Touche LLP Columbus, Ohio November 18, 2002 Exhibit 23.3 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-50447 and 333-54025 of Columbus Southern Power Company on Form S-3 of our report dated February 22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of Columbus Southern Power Company. Deloitte & Touche LLP Columbus, Ohio November 18, 2002 Exhibit 23.4 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-58656 of Indiana Michigan Power Company on Form S-3 of our report dated February 22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of Indiana Michigan Power Company. Deloitte & Touche LLP Columbus, Ohio November 18, 2002 Exhibit 23.5 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-87216 of Kentucky Power Company on Form S-3 of our report dated February 22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of Kentucky Power Company. Deloitte & Touche LLP Columbus, Ohio November 18, 2002 Exhibit 23.6 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-50373 and 33-53133 of Ohio Power Company on Form S-3 of our report dated February 22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of Ohio Power Company. Deloitte & Touche LLP Columbus, Ohio November 18, 2002 Exhibit 23.7 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 333-33284, 333-00973 and 333-100623 of Public Service Company of Oklahoma on Form S-3 of our report dated February 22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of Public Service Company of Oklahoma. Deloitte & Touche LLP Columbus, Ohio November 18, 2002 Exhibit 23.8 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 333-87834, 333-96213 and 333-100632 of Southwestern Electric Power Company on Form S-3 of our report dated February 22,2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of Southwestern Electric Power Company. Deloitte & Touche LLP Columbus, Ohio November 18, 2002

KENTUCKY POWER CO 8-K