On June 17, 2002, Allegheny Energy, Inc. (Allegheny Energy), a parent of Allegheny Energy Supply Company, LLC, and its subsidiaries (collectively the Company) contributed a $193.0 million parent company contribution to the Company. In recording the transaction, Allegheny Energy partially forgave $193.0 million of the Company's $325.0 million affiliated notes payable to Allegheny Energy. See Note 6 to the Consolidated Financial Statements for additional details.

The Notes to Consolidated Financial Statements of Allegheny Energy Supply Company, LLC, and its subsidiaries (collectively, the Company) in its Annual Report on Form 10-K, as amended, for the year ended December 31, 2001, should be read in conjunction with the accompanying consolidated financial statements and the following notes. The accompanying consolidated financial statements appearing on pages 3 through 7 and these notes to consolidated financial statements are unaudited. In the opinion of the Company, such consolidated financial statements together with these notes contain all adjustments (which consist only of normal recurring adjustments) necessary to present fairly the Company's financial position as of June 30, 2002, the results of its operations and comprehensive income for three and six months ended June 30, 2002 and 2001, and cash flows for the six months ended June 30, 2002 and 2001. Certain prior period amounts in these financial statements and notes have been reclassified for comparati ve purposes.

The Company's energy marketing and trading activities include the marketing and trading of electricity, natural gas, and other energy-related commodities using primarily over-the-counter contracts and exchange-traded contracts such as those traded on the New York Mercantile Exchange (NYMEX).

The Company records the contracts used in its energy marketing and trading activities at fair value on the consolidated balance sheet, with all changes in fair value recorded as gains and losses on the consolidated statement of operations in wholesale revenues. Fair values for exchange-traded instruments, principally futures and certain options, are based on quoted market prices. In establishing the fair value of commodity contracts that do not have quoted market prices, such as physical contracts, over-the-counter options and swaps, management makes estimates using available market data and pricing models, which may change from time to time. Factors such as commodity price risk, operational risk, and credit risk of counterparties are evaluated in establishing the fair value of commodity contracts. The commodity contracts include certain financial instruments, such as interest rate swaps, which are used to mitigate the effect of interest rate changes on the fair value of commodity contracts.

The Company has contracts that are unique due to their long-term nature and are valued using proprietary pricing models. Inputs to the models include estimated forward natural gas and electricity prices, interest rates, and estimates of market volatility for natural gas and electricity prices. These inputs depend heavily on judgments and assumptions by management. These inputs become more difficult to predict and the models become less precise the further into the future these estimates are made. There may be an adverse effect on the Company's

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financial position and results of operations if the judgments and assumptions underlying those models' inputs prove to be wrong or inaccurate.

The fair values of energy trading commodity contracts, which represent the net unrealized gain and loss positions, are recorded as assets and liabilities, respectively, after applying the appropriate counterparty netting agreements in accordance with the Financial Accounting Standards Board's (FASB) Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts - an Interpretation of the Accounting Principles Board's (APB) Opinion No. 10 and FASB Statement No. 105." At June 30, 2002, the fair value of the energy trading commodity contract assets and liabilities was $1,837.5 million and $950.6 million, respectively. At December 31, 2001, the fair value of the energy trading commodity contract assets and liabilities was $1,755.4 million and $1,005.1 million, respectively. Net unrealized gains of $116.7 million and $180.5 million, before income taxes, were recorded to the consolidated statement of operations in wholesale revenues to reflect the change in fair value of the energy trading contracts for the six months ended June 30, 2002 and 2001. As of June 30, 2002, the fair value of the Company's commodity contracts with a counterparty of $1,284.0 million was approximately 20.4 percent of the Company's total assets.

On March 19, 2002, the Company entered into two treasury lock agreements to hedge its exposure to changing United States Treasury interest rates on the forecasted issuance of long-term, fixed-rate debt in April 2002. These treasury lock agreements were accounted for as cash flow hedges under Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." At June 30, 2002, the total fair value of these contracts of $(1.6) million, before income taxes ($(1.0) million net of income taxes), was recorded as an unrealized loss in other comprehensive income. In April 2002, the Company began reclassifying to earnings the amounts in accumulated other comprehensive income for these treasury lock agreements over the life of the ten year debt. For the three and six months ended June 30, 2002, $.04 million, before income taxes ($.02 million, net of income taxes) was reclassified from accumulated other comprehensive income to earnings.

During the three months ended June 30, 2002, the Company recorded a liability and an unrealized loss for derivative instruments of $5.2 million in other current liabilities for eleven wholesale electricity contracts. These contracts previously qualified for the normal purchases and normal sales exception under SFAS No. 133. However, due to changes resulting from the April 2002 integration with the Pennsylvania - New Jersey - Maryland Interconnection, LLC (PJM) these contracts did not qualify for the normal purchases and normal sales exception from April 1, 2002 through June 30, 2002.

The statement of other comprehensive income provides the components of comprehensive income for the three and six months ended June 30, 2002 and 2001.

For the three months ended June 30, 2002 and 2001, other comprehensive income includes unrealized losses, net of reclassifications to earnings, income taxes, and minority interest, on cash flow hedges of $1.5 million and $2.9 million,

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On January 1, 2002, the Company adopted SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 eliminated the pooling-of-interests method and requires all business combinations initiated after June 30, 2001, to be accounted for under the purchase method of accounting. SFAS No. 141 also sets forth guidelines for applying the purchase method of accounting in the determination of goodwill and other intangible assets. The application of SFAS No. 141 did not affect any of the Company's previously reported amounts for goodwill and other intangible assets.

SFAS No. 142 eliminated amortization of goodwill and other intangible assets with indefinite lives effective January 1, 2002. Subsequent to the transitional provisions of SFAS No. 142 (see below), goodwill and other intangible assets with indefinite lives will be tested at least annually for impairment, with impairment losses recognized in operating income. Absent any impairment indicators, the Company expects to perform its annual impairment tests during its fourth quarter, in connection with its annual budgeting process. Other intangible assets with finite lives will continue to be amortized over their useful lives and tested for impairment when events or circumstances warrant.

As applied to the Company, SFAS No. 142 transitional provisions require the Company to test goodwill for impairment as of January 1, 2002, and recognize any transitional goodwill impairment loss as the effect of a change in accounting principle in the first quarter of 2002 irrespective of when the loss was measured and recorded in the Company's books. During the second quarter of 2002, the Company completed its transitional goodwill impairment test, using a discounted cash flow methodology to determine the fair value of its reporting units, and determined that there was no impairment of goodwill. As of June 30, 2002, the Company had no other intangible assets subject to the reporting provisions of SFAS No. 142.

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If the provisions of SFAS No. 142 had been applied for the three and six months ended June 30, 2001, consolidated income before cumulative effect of accounting change and consolidated net income would have been as follows:

For the six month period ended June 30, 2002, members' equity increased by $195.7 million. The increase was due to a $.5 million equity contribution from Allegheny Energy, Inc. (Allegheny Energy), a parent of the Company, the partial forgiveness of $193.0 million of the Company's $325.0 million affiliated notes payable to Allegheny Energy, consolidated net income of $3.2 million, and accumulated other comprehensive income of ($1.0) million.

For the six months ended June 30, 2002, the Company made repayments of $46.5 million on unsecured notes and redeemed $80.0 million of floating rate medium-term debt. The Company also redeemed $3.5 million of pollution control bonds per their original terms.

In April 2002, the Company issued $650.0 million of 8.25 percent notes due April 15, 2012. The Company used the net proceeds from the notes to repay short-term indebtedness of $630.0 million, including a bridge loan in the amount of $550.0 million that was entered into in connection with the acquisition of three generating facilities in the Midwest in May 2001, and for general corporate purposes.

On April 19, 2002, the Company closed on a new revolving credit facility totaling $965.0 million, consisting of a 364-day tranche and a three-year tranche. The revolving credit facility is available for the issuance of letters of credit, to support the Company's commercial paper program, and for general corporate borrowing purposes.

The Company's long-term debt agreements require the Company to maintain specific debt to capitalization ratios that, if violated, would hinder the Company's ability to issue dividends. As of June 30, 2002, the Company has not violated these ratios.

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The Company supplies electricity to its regulated utility affiliates, in accordance with agreements approved by the Federal Energy Regulatory Commission (FERC), including electricity supplied to West Penn Power Company (West Penn), The Potomac Edison Company (Potomac Edison), and Monongahela Power Company (Monongahela Power) to meet their retail load requirements as the default provider during the transition period for deregulation plans approved in Pennsylvania, Maryland, and Ohio. The Company also provides electricity pursuant to a contract to cover the retail load of Potomac Edison in Virginia during a capped rate period that ends on July 1, 2007, unless the Virginia State Corporation Commission reduces this time period. The revenue from these sales is reported on the consolidated statement of operations in affiliated revenues. Total revenue from these sales for the three months ended June 30, 2002 and 2001 was $242.4 million and $243.4 million, respectively. The revenue from these sales for the si x months ended June 30, 2002 and 2001 was $519.5 million and $518.5 million, respectively.

In November 2001, the Company entered into an agreement with Potomac Edison to purchase 180 megawatts (MW) of unit contingent capacity, energy, and ancillary services from January 1, 2002, through December 31, 2004. The AES Warrior Run generation facility serves as the source of the energy. The cost of purchasing power under this contract for the three and six months ended June 30, 2002 was $11.4 million and $20.9 million, respectively.

Other than the officers and employees of Allegheny Energy Supply Lincoln Generating Facility, LLC, all of the Company's employees are employed by Allegheny Energy Service Corporation (AESC), a wholly-owned subsidiary of Allegheny Energy, which performs services, including financial and tax accounting, human resources, cash management and treasury support, purchasing, legal, information technology support, regulatory support, insurance brokering, and office management, at cost for the Company and its affiliates in accordance with the Public Utility Holding Company Act of 1935 (PUHCA). Through AESC, the Company is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to the Company for the six months ended June 30, 2002 and 2001 were $82.5 million and $59.5 million, respectively.

The transfer of Potomac Edison's generating assets to the Company on August 1, 2000, included Potomac Edison's West Virginia jurisdictional generating assets. The West Virginia jurisdictional generating assets have been leased back to Potomac Edison to serve its West Virginia jurisdictional retail customers. Affiliated revenue for the three months ended June 30, 2002 and 2001 includes $16.0 million and $17.0 million, respectively, for this rental income. Affiliated revenue for the six months ended June 30, 2002 and 2001 includes $37.1 million and $37.1 million, respectively, for this rental income. The original lease term was for one year. The Company and Potomac Edison have mutually agreed to continue the lease beyond August 1, 2001. The ultimate treatment of Potomac Edison's West Virginia jurisdictional generating assets will be resolved when the West Virginia legislature addresses the implementation of deregulation.

The Monongahela Power Ohio and FERC jurisdictional generation assets that were transferred to the Company on June 1, 2001, have been leased back to Monongahela

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Power. The lease was effective on June 1, 2001 for a term of one year and renews automatically. The Company and Monongahela Power have mutually agreed to continue the lease. For the three months ended June 30, 2002 and 2001, the affiliated revenue from this arrangement totaled $9.9 million and $3.3 million, respectively. For the six months ended June 30, 2002 and 2001, the affiliated revenue from this arrangement totaled $19.7 million and $3.3 million, respectively.

The Company joins with Allegheny Energy and its subsidiaries in filing a consolidated federal income tax return. The consolidated tax liability is allocated among the participants generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return tax liability. For the six months ended June 30, 2002, the Company received tax allocation payments from Allegheny Energy of $84.0 million. For the six months ended June 30, 2001, the Company paid tax allocations to Allegheny Energy of $10.5 million.

In second quarter 2002, the Company completed the sale of approximately 150,000 Pennsylvania and Ohio retail customers to Dominion Retail, Inc., a subsidiary of Dominion Resources Inc. In the first quarter 2001, the Company realized a $3.5 million gain on the sale of equipment. The gains on these sales, interest income, and miscellaneous charges are included in other income and expenses on the consolidated statement of operations.

The Company is subject to various laws, regulations, and uncertainties as to environmental matters. Compliance may require the Company to incur substantial additional costs to modify or replace existing and proposed equipment and facilities and may adversely affect the cost of future operations.

The Environmental Protection Agency's (EPA) nitrogen oxides (NO_X) State Implementation Plan (SIP) call regulation has been under litigation and, on March 3, 2000, the United States Court of Appeals issued a decision that upheld the regulation. However, state and industry litigants filed an appeal of that decision in April 2000. On June 23, 2000, the Court denied the request for the appeal. Although the Court did issue an order to delay the compliance date from May 1, 2003, until May 31, 2004, both the Maryland and Pennsylvania state rules

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to implement the EPA NO_X SIP call regulation still require compliance by May 1, 2003. West Virginia has issued a final rule that would require compliance by May 31, 2004. The EPA Section 126 petition regulation also requires the same level of NO_X reductions as the EPA NO_X SIP call regulation and was also under litigation in the United States Court of Appeals. A Court decision in May 2001 upheld the rule. In August 2001, the Court issued an order that suspended the Section 126 petition rule May 1, 2003, compliance date pending EPA review of growth factors used to calculate the state NO_X budgets. In January 2002, the EPA announced its intention to revise the Section 126 petition rule compliance date from May 1, 2003, to May 31, 2004. The Company's compliance with such stringent regulations will require the installation of post-combustion control technologies on most of its power stations. The Company's construction forecast includes the expenditure of $192. 3 million of capital costs during the 2002 through 2003 period to comply with these regulations.

On August 2, 2000, Allegheny Energy received a letter from the EPA requiring it to provide certain information on the following ten electric generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island. The Company and Monongahela Power either individually or together now own these electric generating stations. The letter requested information under Section 114 of the federal Clean Air Act (Act) to determine compliance with the Act and state implementation plan requirements, including potential application of federal New Source Review (NSR). In June 2002, Allegheny Energy received a request from the EPA to provide additional information concerning three of the Company's electric generating stations. The information will be provided to the EPA by the end of the fourth quarter 2002. In general, these standards can require the installation of additional air pollution control equipment upon the major mod ification of an existing facility. Allegheny Energy submitted these records in January 2001. The eventual outcome of the EPA investigation is unknown.

Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in many cases. The Company believes its generating facilities have been operating in accordance with the Clean Air Act and the rules implementing the Act. The experience of other utilities, however, suggests that, in recent years, the EPA may well have revised its interpretation of the rules regarding the determination of whether an action at a facility constitutes routine maintenance, which would not trigger the requirements of NSR, or a major modification of the facility, which would require compliance with NSR. If federal NSR were to be applied to these generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures.

In December 2000, the EPA issued a decision to regulate coal- and oil-fired electric utility mercury emissions under Title III, Section 112 of the Clean Air Act Amendments of 1990 (CAAA). The EPA plans to issue a proposed regulation by December 2003 and a final regulation by December 2004. The timing and level of required mercury emission reductions are unknown at this time.

The Attorney General of the State of New York and the Attorney General of the State of Connecticut in their letters dated September 15, 1999, and November 3, 1999, respectively, notified Allegheny Energy of their intent to commence civil

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actions against Allegheny Energy or certain of its subsidiaries alleging violations at the Fort Martin Power Station under the federal Act, including the new source performance standards, which requires existing generating facilities that make major modifications to comply with the same emission standards applicable to new generating facilities. Other governmental authorities may commence similar actions in the future. Fort Martin is a station located in West Virginia and is now jointly owned by the Company and Monongahela Power. Both Attorney Generals stated their intent to seek injunctive relief and penalties. In addition, the Attorney General of the State of New York in his letter indicated that he might assert claims under the state common law of public nuisance seeking to recover, among other things, compensation for alleged environmental damage caused in New York by the operation of the Fort Martin Power Station. At this time, Allegheny Energy and its subsidiaries are not able to determi ne what effect, if any, these actions threatened by the Attorney Generals of New York and Connecticut may have on them.

In June 2002, NPC commenced its previously announced plan to delay a portion of amounts payable under contracts for power sales, including the contracts between Merrill Lynch and NPC, for energy deliveries occurring between May 1, 2002 and September 15, 2002. Payments that NPC intends to make are equal to 110% of certain benchmark prices established as of May 1, 2002. NPC has announced its intention to pay the excess of such amounts semi-annually, through December 31, 2003, beginning on December 31, 2002. The Company has entered into a separate bilateral arrangement with Merrill Lynch under which it provides power on behalf of Merrill Lynch for the NPC trades, and has agreed to delay receipt of payment from Merrill Lynch on such trades until such time as NPC begins making payments to Merrill Lynch under the three contracts in dispute.

On February 25, 2002, the California Public Utilities Commission (California PUC) and the California Electricity Oversight Board (CAEOB) filed complaints with the FERC regarding various contracts to which the California Department of Water Resources (CDWR) is a counterparty, including two contracts with the Company to

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sell power to the CDWR. The California PUC complaint requested that each of the contracts challenged in the complaint be abrogated, as containing both unreasonable pricing and unjust and unreasonable non-price terms and conditions, or, in the alternative, that the challenged contracts be reformed to provide for just and reasonable pricing, reduce their duration, and strike from the contracts the specific non-price contract terms and conditions found to be unjust and unreasonable. The CAEOB's complaint requested that the contracts be voidable at the state of California's option or reformed. On March 18, 2002, the Company filed its response to the California PUC and CAEOB complaints. On April 25, 2002, the FERC set for hearing the issue of whether the dysfunctional spot market in California had an adverse effect on the long-term, bilateral markets in California, including with respect to two contracts entered into between the Company and the CDWR, and if so, whether the effect was of such a magnitude to warrant modification of bilateral long-term contracts. The FERC held that, with respect to the Company's contracts, the higher "public interest" standard, rather than the "just and reasonable" standard should apply. On July 23, 2002, the FERC denied various requests for rehearing of its April 25, 2002 Order. While the Company believes the Complaint should be dismissed against it, it cannot predict the outcome of this litigation.

On April 25, 2002, the FERC set for hearing the issue of whether the dysfunctional spot market in California had an adverse effect on the long-term, bilateral markets in California, including with respect to two contracts entered into between the Company and the CDWR, and if so, whether the effect was of such a magnitude to warrant modification of bilateral long-term contracts. The FERC held that, with respect to the Company's contracts, the higher "public interest" standard, rather than the "just and reasonable" standard should apply. On July 23, 2002, the FERC denied various requests for rehearing of its April 25, 2002 Order. The Company cannot predict the outcome of this litigation.

On May 30,2002, the FERC dismissed in relevant part a complaint filed by the Attorney General of the State of California alleging that various sellers of electric energy in California violated the Federal Power Act by failing properly to file with the FERC the terms of their short-term power sales to the California Independent System Operator (ISO), the California Power Exchange, and the CDWR. The Attorney General had requested that sellers under these transactions pay refunds with interest for their short-term power sales during 2000 and 2001. On July 1, 2002, the Attorney General filed a request for rehearing with the FERC. While the Company believes that the FERC will reaffirm its prior order and dismiss the rehearing petition, the Company cannot predict the outcome of this proceeding.

In the second quarter of 2002, eight class action lawsuits were filed in the Superior Court of California seeking unspecified amounts of damages against various defendants, including the Company alleging violations of California's Cartwright Act and California's unfair business practices statute. These lawsuits were removed by the defendants to the U.S. District Courts for the Northern and Eastern Districts of California, and on July 12, 2002, were conditionally transferred to the U.S. District Court for the Southern District of California as "tag-along cases" to an existing multi-district litigation proceeding, "In Re California Wholesale Electricity Antitrust Litigation, MDL

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1405, Transfer Order" (June 8, 2001). The Company cannot predict the outcome of these lawsuits at this time.

On May 8, 2002 the FERC staff, pursuant to a fact-finding investigation of potential manipulation of electric and natural gas prices in the western markets, requested that all sellers of wholesale electricity and/or ancillary services to the California ISO and/or the California Power Exchange during 2000 and 2001 provide certain data and other information relating to such sales and to "representative trading strategies." The data request was issued to over 140 companies, including the Company. The Company did not engage in any such sales, and prepared a response to the FERC to such effect.

On December 2, 2001, various Enron Corporation entities, including, but not limited to, Enron North America Corporation and Enron Power Marketing, Inc., (collectively Enron), filed voluntary petitions for Chapter 11 reorganization with the United States Bankruptcy Court for the Southern District of New York.

The Company and Enron have master trading agreements in place, which include an International Swaps and Dealers Association Agreement, a Master Power Purchase and Sale Agreement, and a Master Gas Purchase and Sale Agreement (Agreements). Within all of these Agreements, there is netting and set-off language. This language allows the Company and Enron to net and set-off all amounts owed to each other under the Agreements.

Pursuant to the Agreements, the voluntary petition for Chapter 11 reorganization by Enron constituted an event of default. The Company effected an early termination as of November 30, 2001, with respect to each of the Agreements, as permitted under the terms of the Agreements.

The Company believes it has appropriately exercised its contractual rights to terminate the Agreements and to net out transactions arising within each Agreement. Pursuant to the Bankruptcy Code, the Company believes it should be able to offset any termination values or payment amounts owed it against amounts it owes to Enron as a result of the netting. As of November 30, 2001, the fair value of all the Company's trades with Enron that were terminated was a net asset of approximately $27 million and the Company had a net payable to Enron of approximately $25 million. After applying the netting provisions of each Agreement, including any collateral posted by Enron with the Company, approximately $4.5 million was expensed as uncollectible in 2001.

In early August 2002, Enron sent a demand letter to the Company for approximately $26 million for a net payable from November 2001. The Company has asked Enron for clarification on its calculation including a determination of interest amounts. The Company has also provided its set-off position with Enron. Once the Company receives clarification from Enron, the parties will enter into negotiations regarding the settlement of all outstanding claims under the bankruptcy proceeding. The Company believes it will be able to set-off all outstanding exposures with the various Enron entities and come to a reasonable settlement of these claims.

In the normal course of business, the Company becomes involved in various legal proceedings. The Company does not believe that the ultimate outcome of these

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proceedings will have a material effect on its results of operations, cash flows, or financial position.

In November 2001, the Company entered into an operating lease transaction in connection with the construction of a 628-MW natural gas fired generating facility in St. Joseph County, Indiana. In July 2002, the Company announced the cancellation of two 44-MW simple-cycle combustion turbines, which were included in the project. The reduced 540-MW combined-cycle facility is expected to be in service in 2004. Accordingly, the Company plans to amend the lease to reduce commitments.

In April 2001, the Company entered into an operating equipment lease transaction structured to finance the purchase of turbines and transformers. In May 2002, this lease was terminated for $33.1 million and the equipment was used in the project with CONSOL Energy, Inc. that placed into operation an 88-MW generating facility in southwest Virginia.

The purchase agreement for the energy marketing and trading business of Merrill Lynch provides that Allegheny Energy shall use its best efforts to contribute to the Company the generating capacity from Monongahela Power's West Virginia jurisdictional generating assets by September 16, 2002. If, after using its best efforts to comply with this provision of the purchase agreement, Allegheny Energy is prohibited by law from contributing to the Company substantially all of the economic benefits associated with such assets, then Merrill Lynch shall have the right to require Allegheny Energy to repurchase all, but not less than all, of Merrill Lynch's equity interest in the Company for $115 million plus interest calculated from March 16, 2001. The Company does not anticipate such a transfer being made by September 16, 2002.

The purchase agreement also provides that, if Allegheny Energy has not completed an initial public offering involving the Company within two years of March 16, 2001, Merrill Lynch has the right to sell its equity interest in the Company to Allegheny Energy for $115 million plus interest calculated from March 16, 2001.

Letters of credit are purchased guarantees that ensure the Company's performance or payment to third parties, in accordance with certain terms and conditions, and amounted to $169.2 million of the $586.0 million available as of June 30, 2002. The Company pays fees for its letters of credit based on the amount available and the amount used.

In July 2002, Allegheny Energy announced plans to reduce its workforce of approximately 6,000 employees by approximately 10 percent. The workforce reductions will occur mostly this year through the combination of an early retirement option, normal attrition, and other selected staff reductions. At this time, the Company cannot estimate the cost of the workforce reduction since the results of the early retirement offer to employees is not known. The Company expects to record a charge in conjunction with the early retirement offer in the

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third quarter of 2002 based on the window for employees to accept the offer. The timing for recording charges for involuntary termination benefits related to selective staff reductions is being evaluated, including the potential impact of SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which was issued in June 2002.

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The Notes to Consolidated Financial Statements and Management's Discussion and Analysis of Financial Condition and Results of Operations in Allegheny Energy Supply Company, LLC's, Annual Report on Form 10-K, as amended, for the year ended December 31, 2001, should be read in conjunction with the following Management's Discussion and Analysis information.

Certain statements within constitute forward-looking statements with respect to Allegheny Energy Supply Company, LLC, and its subsidiaries (collectively, the Company). Such forward-looking statements include statements with respect to deregulated activities and movements toward competition in the states served by the Company; markets; products; services; prices; capacity purchase commitments; results of operations; capital expenditures; regulatory matters; liquidity and capital resources; the effect of litigation; and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results of the Company will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

Factors that could cause actual results of the Company to differ materially include, among others, the following: general economic and business conditions, changes in industry capacity, development, and other activities by the Company's competitors; changes in the weather and other natural phenomena; changes in technology; changes in the price of power and fuel for electric generation; changes in the underlying inputs and assumptions used to estimate the fair values of commodity contracts; changes in laws and regulations applicable to the Company, its markets, or its activities; litigation involving the Company; environmental regulations; the loss of any significant customers and suppliers; the effect of accounting policies issued periodically by accounting standard-setting bodies; and changes in business strategy, operations, or development plans.

In July and August 2002, Allegheny Energy, announced a series of initiatives to improve financial performance and respond to the challenges it faces in the current energy marketplace. The combination of the challenges to various electricity sales contracts and markets, the Enron bankruptcy, accounting scandals, energy trading improprieties, and other matters has significantly

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affected the merchant energy market. As a result, trading and origination opportunities have not occurred as Allegheny Energy expected and are not expected to occur in the near future. In addition, additional generating capacity resources, lower than expected demand, and a relatively weak economy have led to reduced wholesale energy prices in several markets in which Allegheny Energy owns, operates, or contractually controls generation capacity.

Allegheny Energy's long-term strategy will be to focus on improving and maximizing the performance of its two business segments: Generation and Marketing, and Delivery and Services. In this context, Allegheny Energy completed a thorough re-examination of its businesses, operations, and strategic plans and has developed the following objectives:

Allegheny Energy also is implementing an aggressive cost reduction program, which includes:

Allegheny Energy has modified its energy marketing and trading and origination activities to focus on short-term trading, asset optimization, and hedging its generating capacity. These activities are more appropriately aligned with Allegheny Energy's existing portfolio of physical assets.

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As a result of the above actions, the Company recorded charges to earnings in the second quarter of 2002 of $38.3 million, before income taxes ($23.3 million, net of income taxes) for the canceled generation projects.

At this time, the Company cannot estimate the cost of the workforce reduction since the results of the early retirement offer to employees are not known. The Company expects to record a charge for the early retirement offer in the third or fourth quarter of 2002. The timing for recording charges for involuntary termination benefits related to selective staff reductions is being evaluated, including the potential impact of Statement of Financial Accounting Standards (SFAS) No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which was issued in June 2002. See the discussion of "Accounting Standards" on page 24 for additional information concerning SFAS No. 146.

The table below summarizes the Company's electric generating capacity, which was in operation on June 30, 2002, and December 31, 2001, including generating capacity purchased through contractual obligations of which the Company does not exercise 100 percent control, along with announced construction and development, contractual control, and planned expansions:

Since the summer of 2001, market prices for energy and capacity have declined across the nation. During this period, the Company has repeatedly reviewed its business strategy relating to the development, construction, and acquisition of generation projects, and as previously discussed, the Company recently announced the cancellation of the 1,080-MW facility planned for La Paz, Arizona and 88 MW of combustion turbine generation planned for St. Joseph, Indiana. During the three months ended June 30, 2002, the Company and CONSOL Energy, Inc. did complete construction of and place into operation an 88-MW generating facility in southwest Virginia. The completion of this facility increased the Company's generating capacity by 44 MW. The Company may undertake selective development projects and opportunistic acquisitions in the future, but in light of current market conditions, the Company is reducing the emphasis it places on such activities.

On March 11, 2000, the West Virginia Legislature approved an electric restructuring plan that would open the State to full retail competition, but assigned tax issues surrounding the plan to a legislative subcommittee for further study. The start date of competition was made contingent upon the necessary tax changes being made and implementation being approved by the

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Legislature. The Company's affiliate, Monongahela Power Company (Monongahela Power) worked with the Public Service Commission of West Virginia (West Virginia PSC) to transfer its generating assets to the Company pending implementation of the restructuring plan. No final legislative action was taken in 2001 or during this year's legislative session, and the current climate regarding restructuring makes it unlikely that the existing plan will be advanced. Accordingly, the Company no longer anticipates receiving Monongahela Power's jurisdictional generating assets pursuant to the previously approved restructuring plan. On June 28, 2002, the West Virginia PSC dismissed its electric restructuring case from its docket, and the Company cannot predict when the State may revisit electric deregulation. The Company is, however, currently in negotiations with the West Virginia PSC to transfer certain generating capacity from Monongahela Power to the Company.

On April 28, 2002, the negotiating teams for Allegheny Energy and the Utility Workers Union of America (UWUA) System Local 102 reached a tentative agreement on a five-year contract. On June 8, 2002, the Company and the UWUA System Local 102 announced that the union's 1,165 members had ratified the agreement.

On January 1, 2002, the Company adopted SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 eliminated the pooling-of-interests method and requires all business combinations initiated after June 30, 2001, to be accounted for under the purchase method of accounting. SFAS No. 141 also sets forth guidelines for applying the purchase method of accounting in the determination of goodwill and other intangible assets. The application of SFAS No. 141 did not affect any of the Company's previously reported amounts for goodwill and other intangible assets.

SFAS No. 142 eliminated amortization of goodwill and other intangible assets with indefinite lives effective January 1, 2002. Subsequent to the transitional provisions of SFAS No. 142 (see below), goodwill and other intangible assets with indefinite lives will be tested at least annually for impairment, with impairment losses recognized in operating income. Absent any impairment indicators, the Company expects to perform its annual impairment tests during its fourth quarter, in connection with its annual budgeting process. Other intangible assets with finite lives will continue to be amortized over their useful lives and tested for impairment when events or circumstances warrant.

As applied to the Company, SFAS No. 142 transitional provisions required the Company to test goodwill for impairment as of January 1, 2002, and recognize any transitional goodwill impairment loss as the effect of a change in accounting principle in the first quarter of 2002 irrespective of when the loss was measured and recorded in the Company's books. During the second quarter of 2002, the Company completed its transitional goodwill impairment test, using a discounted cash flow methodology to determine the fair value of its reporting units, and determined that there was no impairment of goodwill. As of June 30, 2002, the Company had no other intangible assets subject to the reporting provisions of SFAS No. 142.

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See Note 5 to the consolidated financial statements for additional information regarding SFAS No. 142.

On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This standard establishes one accounting model for long-lived assets to be disposed of by sale, including discontinued operations, and carries forward the general impairment provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The adoption of SFAS No. 144 did not have a material effect on the Company's results of operation, cash flows, or financial position.

In April 2002, the Financial Accounting Standards Board (FASB) issued SFAS No. 145, "Rescission of FASB Statement Nos. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections as of April 2002." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt," and an amendment of that Statement, SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No. 145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor Carriers." SFAS No. 145 amends SFAS No. 13, "Accounting for Leases," to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The provisions of this S tatement are effective over various dates beginning May 15, 2002. SFAS No. 145 is not expected to have a material effect on the Company's results of operations, cash flows, or financial position.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Costs associated with exit or disposal activities include termination benefits provided to employees that are involuntarily terminated, costs to terminate an operating lease or other contract, and incremental direct costs associated with, for example, facility closures and restructuring plans. The principal difference between this Statement and EITF Issue No. 94-3 involves the timing of recognition of a liability. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF Issue No. 9 4-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with earlier application encouraged. The Company is currently evaluating the effect of applying SFAS No. 146 on its results of operations and financial position. The Company has not determined whether the Company will adopt the Statement early or what effect, if any, SFAS No. 146 may have on the accounting for the 10 percent workforce reduction announced in July 2002.

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In June 2002, the EITF reached a consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts," that mark-to-market gains and losses on energy trading contracts (whether realized or unrealized) should be shown net in the consolidated statement of operations. This consensus will be applicable to financial statements for periods ending after July 15, 2002. The Company currently reports realized purchased energy and transmission under energy trading contracts that require physical delivery of the commodity under cost of revenues on the consolidated statement of operations. The Company reports net unrealized gains and losses resulting from energy trading in operating revenues on the consolidated statement of operations. During the third quarter of 2002, the Company plans to modify its reporting as a result of the EITF consensus to present the revenues from energy trading activities net of the cost of purchased energy and transmission under contracts that require physical delivery. As a result, the Company will report lower operating revenues and lower cost of revenues with no affect on consolidated net income.

While the Company has not completed its evaluation of the effect of the adoption of EITF 02-3, the following table provides the Company's most current estimate of the restated operating revenues and cost of revenues for the three and six months ended June 30, 2002 and 2001, respectively, on net basis.

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For the three months ended June 30, 2002, the Company's results primarily reflect weak wholesale energy markets nationwide, lower net revenue, reduced economic activity, and unplanned outages at the Company's generating stations. The Company recorded an after-tax charge for generation and marketing for the three months ended June 30, 2002, of $23.3 million for the cancellation of generating capacity planned for La Paz, Arizona.  The Company's results were also affected by increased operation expenses and reduced excess generation available for sale into the wholesale markets due to unplanned generation outages. These unplanned outages also resulted in the purchase of higher priced replacement power for the Company.

For the six months ended June 30, 2002, the decrease in the Company's earnings was partially offset by increased net revenues for the three months ended March 31, 2002, reflecting acquisitions of generating assets and an energy trading business.

On May 3, 2001, the Company acquired three natural gas-fired generating facilities with a total generating capacity of 1,710 MW in Illinois, Indiana, and Tennessee (Midwest). On June 1, 2001, Monongahela Power, a regulated utility affiliate, transferred 352 MW of its Ohio and Federal Energy Regulatory Commission (FERC) jurisdictional generating assets to the Company. In December 2001, the Company also completed the construction of and placed into service two 44-MW simple-cycle natural gas combustion turbines.

On March 16, 2001, the Company acquired an energy marketing and trading business from Merrill Lynch Capital Services, Inc. (Merrill Lynch). This acquisition significantly increased the volume and scope of the Company's energy marketing and trading activities. The Company now trades electricity, natural gas, and other energy-related commodities.

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The Company had certain option contracts that were derivatives as defined by SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which did not qualify for hedge accounting. In accordance with SFAS No. 133, the Company recorded a charge of $31.1 million against earnings, net of the related income taxes ($52.3 million, before income taxes) for these contracts as a change in accounting principle on January 1, 2001.

Total operating revenues for the three and six months ended June 30, 2002 and 2001 were as follows:

Retail The Company is in the retail markets as an alternative generation supplier in states where retail competition has been implemented. The decrease in retail revenues for the three and six months ended June 30,2002 of $21.5 million and $54.4 million, respectively, was primarily due to the Company's continued shift in focus away from retail customers toward wholesale markets and energy commodity trading. In second quarter 2002, the Company completed the sale of approximately 150,000 Pennsylvania and Ohio retail customers to Dominion Retail, Inc., a subsidiary of Dominion Resources Inc. The retail customer account sale had a minimal impact on the Company's retail revenues for the three and six months ended June 30, 2002.

Wholesale The decrease in wholesale revenues for the three and six months ended June 30, 2002 of $715.9 million and $205.5 million, respectively, was primarily due to weak wholesale energy markets nationwide, generation outages at the Company's generating stations, and decreased unrealized gains from energy trading activities.

The Company significantly increased the volume and scope of its energy marketing and trading activities as a result of its acquisition of an energy trading business from Merrill Lynch on March 16, 2001. The Company now trades electricity, natural gas, and other energy-related commodities. The Company records contracts entered into in connection with energy trading at fair value on the consolidated balance sheet, with all changes in fair value recorded as gains and losses on the consolidated statement of operations in wholesale revenues. The realized revenues from energy trading activities, with the exception of certain financial instruments, including swaps and certain options, are recorded on a gross basis as individual discrete transactions as either revenues or expenses because the contracts require physical delivery of the underlying asset. Fair values for exchange-traded instruments, principally futures and certain options, are based on actively quoted market prices. In establishing the fair

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value of commodity contracts that do not have quoted market prices, such as physical contracts, over-the-counter options, and swaps, management makes estimates using available market data and pricing models, which may change from time to time. The Company has certain contracts that are unique, which extend to 2010 and beyond, and are valued using proprietary pricing models. Inputs to the models include estimated forward natural gas and electricity prices, interest rates, estimates of market volatility for natural gas and electricity prices, the correlation of natural gas and electricity prices, and other factors such as generating unit availability and location, as appropriate. These inputs require management judgments and assumptions.

The Company's models also adjust the fair value of commodity contracts to reflect uncertainty in prices, operational risks related to generating facilities, and risks related to the performance of counterparties. These inputs become more challenging, and the models become less precise the further into the future these estimates are made. Additionally, various factors, including accounting and energy trading improprieties of others, have significantly affected the merchant energy marketplace during the six months ended June 30, 2002. Market liquidity and the number of creditworthy participants have been dramatically reduced and trading and origination opportunities have been significantly curtailed within energy markets. Actual effects on the Company's financial position and results of operations may vary significantly from expected results, if the judgments and assumptions underlying those models' inputs prove to be wrong or the models prove to be unreliable.

The fair values of energy trading commodity contracts, which represent the net unrealized gain and loss positions, are recorded as assets and liabilities as stated above, after applying the appropriate counterparty netting agreements in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts - an Interpretation of the Accounting Principles Board's (APB) Opinion No. 10 and FASB Statement No. 105." At June 30, 2002, the fair value of energy trading commodity contract assets and liabilities was $1,837.5 million and $950.6 million, respectively. At December 31, 2001, the fair value of energy trading commodity contract assets and liabilities was $1,755.4 million and $1,005.1 million, respectively.

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The following table disaggregates the net fair value of commodity contract assets and liabilities, excluding the Company's generating assets and power sales agreements with the Company's regulated utility affiliates for their provider of last resort obligations, as of June 30, 2002, based on the underlying market price source and the contract delivery periods:

In the table above, each commodity contract is classified by the source of fair value, based on the entire contract being assigned to a single classification (even though a portion of a contract may be valued based on one of the other classifications) and the fair values are shown for the scheduled delivery or settlement dates. The Company determines prices actively quoted from various industry services, broker quotes, and the New York Mercantile Exchange (NYMEX). Electricity markets are generally liquid for approximately three years and natural gas markets are generally liquid for approximately five years. For times beyond these periods, some market prices can be observed, but market liquidity is less robust.

Approximately $1.1 billion of the Company's commodity contracts were classified as prices based on models (even though a portion of these contracts are valued based on observable market prices). The most significant variable to the Company's models used to value these contracts is the forward prices for both electricity and natural gas. These forward prices are based on observable market prices to the extent prices are available in the market. Generally, electricity forward prices are actively quoted for about three years and some observable market prices are available for about five years. After five years, the forward prices for electricity are based on the forward price of natural gas and a marginal heat rate for generation (based on more efficient natural gas-fired generation) to convert natural gas into electricity. For natural gas, forward prices are generally actively quoted for about five years, and some observable market prices are available for about 10 years. Beyond 10 years, natural gas prices are escalated, based on trends in prior years.

For deliveries from July 1, 2002, to June 30, 2003, the fair value of the Company's commodity contracts was a net liability of $222.8 million, primarily related to commodity contracts used to hedge the California Department of Water Resources (CDWR) agreement. As discussed below, the Company expects to incur realized losses related to the contract with the CDWR and related hedges through 2002.

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Net unrealized gains of $116.7 million and $180.5 million in the six months ended June 30, 2002 and 2001, respectively, were recorded in the consolidated statement of operations in wholesale revenues to reflect the change in the estimated fair value of the energy commodity contracts. The following table provides a roll-forward of the net fair value, or commodity contract assets less commodity contract liabilities, of the Company's commodity contracts from December 31, 2001, to June 30, 2002:

As shown in the table above, the net fair value of the Company's commodity contracts increased by $136.6 million as a result of unrealized gains recorded during the six months ended June 30, 2002, of which $114.9 million related to the Company's contracts in the Western Systems Coordinating Council (WSCC), including the fixed-price contract with the CDWR, the contract to call up to 1,000 MW of generating capacity in southern California, and the contract for 222 MW of generating capacity from a plant being constructed in Las Vegas, Nevada (LV Cogen).  The increase in the fair value of the WSCC portfolio was primarily due to rising prices for the three months ended March 31, 2002, which increased the value of the contract to call up to 1,000 MW of generating capacity in southern California, plus certain changes in the valuation of the contracts with the CDWR, as discussed below. For the three months ended June 30, 2002, the fair value of the WSCC portfolio remained relatively flat with only a $2. 8 million decrease in fair value.

On February 21, 2002, the California Public Utilities Commission (California PUC) approved a rate agreement with the CDWR in order for the CDWR to issue bonds to repay the state of California's general fund and other outstanding loans and pay its ongoing long-term purchased power costs. The agreement creates two streams of revenue for the CDWR by calling for the California PUC to impose bond charges and power charges on retail electric customers sufficient to pay the CDWR's debt service and operating expenses, including payment of its long-term power purchase agreements with the Company. To date, all payments to the Company by the CDWR for purchased power have been made on time and in full.

The California PUC rate agreement is a positive development relative to the prior assumptions used in assessing the long-term creditworthiness of the CDWR and the estimation of the fair value of the Company's contracts with the CDWR. As a result, the valuation adjustments used in estimating the fair value of these contracts have been reduced. The effect of this change, which was made during the three months ended March 31, 2002, resulted in a $35.8 million increase in

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the estimated fair value of the CDWR contracts before consideration of the other valuation factors.

During the six months ended June 30, 2002, the Company's energy trading activities resulted in $43.1 million of net realized losses. These realized losses were primarily from the Company's contract with the CDWR and the related hedges. Due to the existing hedges of the CDWR contract, the Company is currently paying for power at prices above the fixed-price contract to sell power to the CDWR. The Company expects to continue to incur realized losses related to the CDWR contract due to the hedges through 2002, but at a reduced level as the hedges mature. Starting with 2003, the Company expects to realize gains related to the CDWR contract for the remainder of the term of the contract.

There has been and may continue to be significant volatility in the market prices for electricity and natural gas at the wholesale level, which will affect the Company's operating results. Similarly, volatility in interest rates will affect the Company's operating results. The effects may be either positive or negative, depending on whether the Company is a net buyer or seller of electricity and natural gas.

The decrease in wholesale revenues for the three months ended June 30, 2002, also reflects the Company having increased generation available for sale with a wholesale market that has low prices, low volatility, and excess capacity. On May 3, 2001, the Company completed the acquisition of three natural gas-fired generating facilities with a total generating capacity of 1,710 MW in the Midwest. In December 2001, the Company also completed the construction of and placed into service two 44-MW simple-cycle natural gas combustion turbines. On June 25, 2002, the Company and CONSOL Energy, Inc. also completed construction of and placed into operation an 88-MW generating facility in southwest Virginia. The completion of this facility increased generation and marketing's generating capacity by 44 MW. As a result, the Company had more generation available for sale into the deregulated marketplace in the three and six months ended June 30, 2002.

Affiliated Affiliated revenues are revenues that the Company obtained from Allegheny Energy's regulated utility subsidiaries under power sales agreements and two generating asset leases. In Maryland, Ohio, Pennsylvania, and Virginia, the Company is obligated under power sales agreements to supply the regulated utility subsidiaries of Allegheny Energy - West Penn Power Company (West Penn), Monongahela Power, and The Potomac Edison Company (Potomac Edison) - with power. Under these agreements, the Company is obligated to provide these companies with the amount of electricity, up to their provider of last resort retail load, that they may demand. The Company would expect to provide power pursuant to similar obligations to Potomac Edison and Monongahela Power in West Virginia were this state to implement customer choice. These agreements have a fixed price as well as a market-based pricing component. The amount of electricity purchased under these agreements that is subject to the market-based pri cing component escalates each year through Allegheny Energy's regulated utility subsidiaries' electric deregulation transition periods. During the three months ended June 30, 2002 and 2001, the Company recorded revenue of $242.4 million and $243.4 million under these agreements. The decrease of $1.0 million for the three months ended June 30, 2002 was primarily due to a reduction in the provider of last resort retail

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load served by Allegheny Energy's regulated utility subsidiaries which was partially offset by an increase in price resulting from the market-based pricing component of the agreements. For the six months ended June 30, 2002 and 2001, the Company recorded revenue of $519.5 million and $518.5 million under these agreements. The increase of $1.0 million was primarily due to an increase in price resulting from the market-based pricing component of the agreements which was partially offset by a reduction in the provider of last resort retail load served by Allegheny Energy's regulated utility subsidiaries as a result of milder weather versus the first quarter of 2001.

The transfer of Potomac Edison's generating assets to the Company on August 1, 2000, included Potomac Edison's generating assets located in West Virginia. The Company has leased back a portion of these generating assets to Potomac Edison to serve its West Virginia jurisdictional retail customers. Affiliated revenue for the three months ended June 30, 2002 and 2001 includes $16.0 million and $17.0 million, respectively, for this rental income. Affiliated revenue for the six months ended June 30, 2002 and 2001 includes $37.1 million and $37.1 million, respectively, for this rental income. The original lease term was for one year. The parties have mutually agreed to continue the lease beyond August 1, 2001.

The Monongahela Power Ohio and FERC jurisdictional generation assets that were transferred to the Company on June 1, 2001, have been leased back to Monongahela Power. The lease was effective on June 1, 2001 for a term of one year and renews automatically. The Company and Monongahela Power have mutually agreed to continue the lease. For the three months ended June 30, 2002 and 2001, the rental income from this arrangement totaled $9.9 million and $3.3 million, respectively. Total rental income for the six months ended June 30, 2002 and 2001 was $19.7 million and $3.3 million, respectively.

The table below separates operating revenues and cost of revenues into two components: Provider of Last Resort and Excess Generation and Trading. The Provider of Last Resort component represents the Company's obligation under long-term power sales agreements to provide West Penn, Potomac Edison, and Monongahela Power with the amount of electricity, up to their provider of last resort retail load, that they may demand in their Pennsylvania, Maryland, Virginia, and Ohio service territories. The Excess Generation and Trading component represents the Company's energy marketing and trading activities and any generation in excess of the provider of last resort obligations. The table also separates operating revenues and cost of sales into contracts that required physical delivery and those that provided for financial net settlement. This separation was performed based on the Company's accounting policy, which provides that realized revenues, with the exception of certain financial instruments, including swa ps, certain options, and certain natural gas transactions, are recorded on a gross basis in revenues or expenses as individual discrete transactions because the contracts require physical delivery of the underlying asset. All unrealized gains from energy trading activities were recorded net in operating revenues.

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Fuel Consumed for Electric Generation Fuel consumed for electric generation represents the cost of fuel consumed by the Company's generating stations and the results of energy commodity contracts used to manage the price risk associated

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with the purchase of natural gas for use in certain generating stations. Total fuel expenses remained flat for the three months ended June 30, 2002, with only a $.1 million increase.  For the six months ended June 30, 2002, total fuel expenses increased by $13.0 million primarily due to increased average fuel prices partially offset by lower kilowatt-hours (kWh's) generated. The increase in average fuel prices increased fuel expense by approximately 2.6 percent and the decrease in kWh's generated, which was partially due to generation outages, decreased fuel expense by approximately 1.8 percent.

Purchased Energy and Transmission The decrease in purchased energy and transmission of $575.5 million and $176.7 million for the three and six months ended June 30, 2002, respectively, was primarily due to decreases in purchases made in support of various energy marketing and trading activities and physical energy supply commitments, which was partially offset by increased purchases resulting from generation outages.

Operation Expense The increase in operation expenses of $36.0 million for the three months ended June 30, 2002, was primarily due to the Company recording charges of $38.3 million, before income taxes ($23.3 million, net of income taxes) for canceled generation capacity and expenses resulting from generation outages. The increase in operation expenses of $48.4 million for the six months ended June 30, 2002, was primarily due to the charges to earnings for the canceled generation capacity, higher salaries and wages, employee benefits, and materials and supplies from the acquisition of the energy trading business on March 16, 2001,and the acquisition of the Midwest generating assets on May 3, 2001.

Depreciation and Amortization Total depreciation and amortization expenses increased by $1.0 million and $12.3 million for the three and six months ended June 30, 2002,respectively, primarily due to depreciation expenses related to the generating facilities in the Midwest that were acquired on May 3, 2001, and the generating assets transferred from Monongahela Power on June 1, 2001.

Effective January 1, 2002, the Company adopted SFAS No. 142 and, accordingly, ceased the amortization of all goodwill. The Company had goodwill amortization of $6.7 million and $7.8 million for the three and six months ended June 30, 2001, which primarily related to its acquisition of the energy trading business acquisition.

Taxes Other than Income Taxes Taxes other than income taxes primarily includes gross receipts taxes, payroll taxes, property taxes, and capital stock/franchise taxes. Total taxes other than income taxes increased $1.3 million and $.8 million for the three and six months ended June 30, 2002, respectively, primarily due to increased Federal Insurance Contribution Act taxes resulting from a higher tax base due to the energy trading business acquisition and property taxes which were partially offset by decreased gross receipts tax resulting from lower taxable revenues.

Other Income and Expenses Other income and expenses increased $1.7 million for the three months ended June 30, 2002 primarily due to a gain on the sale of

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approximately 150,000 Pennsylvania and Ohio retail customers in the Company's deregulated markets to Dominion Retail, Inc., a subsidiary of Dominion Resources Inc., and higher other interest and dividend income.  Other income and expenses decreased $2.9 million for the six months ended June 30, 2002 primarily due to a $3.5 million gain on the disposal of equipment in the first quarter 2001 that was partially offset by the gain on the sale of the Company's retail customers in the second quarter 2002. See Note 8 to the Consolidated Financial Statements for additional details.

Interest Charges The increase in interest charges of $12.3 million and $30.5 million for the three and six months ended June 30, 2002, respectively, resulted from increased average long-term debt outstanding. The increase in average long-term debt outstanding was primarily the result of the Company borrowing $380 million at 8.13 percent under a credit agreement in November 2001 and issuing $400 million of unsecured 7.80 percent notes in March 2001. In April 2002, the Company issued $650.0 million of 8.25 percent notes due April 15, 2012. The Company used the net proceeds from the notes to repay short-term indebtedness of $630.0 million, which included a bridge loan for $550.0 million that was entered into in connection with the acquisition of the Midwest Assets, and for general corporate purposes.

Federal and State Income Taxes Federal and state income taxes decreased by $75.7 million and $62.8 million for the three and six months ended June 30, 2002, respectively, due to decreased pre-tax earnings and lower effective tax rates.

Minority Interest Minority interest was $1.0 million and $2.1 million for the three and six months ended June 30, 2002. As of June 30, 2002, the minority interest primarily represents Monongahela Power's 22.97% minority interest in Allegheny Generating Company (AGC). In August 2000, Potomac Edison transferred to the Company all of its generating assets, except certain hydroelectric facilities located in Virginia, at net book value. The asset transfer included Potomac Edison's 28% ownership of AGC. As a result of the transfer, the Company's ownership increased from 45% as of July 31, 2000, to 73% as of August 1, 2000. Effective August 1, 2000, the Company's consolidated financial statements include the operations of AGC and the related minority interest. In connection with the transfer of 352 MW of Monongahela Power's generating assets, the Company received an additional 4.03% ownership of AGC, which increased its ownership percentage to its current level of 77.03%.

Cumulative Effect of Accounting Change The Company had certain option contracts that met the derivative criteria in SFAS No. 133, which did not qualify for hedge accounting. In accordance with SFAS No. 133, the Company recorded a charge of $31.1 million against earnings, net of the related income tax effects ($52.3 million, before income taxes) for these contracts as a change in accounting principle on January 1, 2001.

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Other Comprehensive Income Other comprehensive income includes an unrealized loss, net of income taxes, on cash flow hedges of $1.5 million and $2.9 million for the three months ended June 30, 2002 and 2001, respectively. For the six months ended June 30, 2002 and 2001, other comprehensive income includes an unrealized loss, net of income taxes, on cash flow hedges of $1.0 million and $3.1 million, respectively.

The Company's discussion of Financial Condition, Requirements, and Resources and Significant Continuing Issues in its Annual Report on Form 10-K, as amended, for the year ended December 31, 2001, should be read in conjunction with the following information.

In the normal course of business, the Company is subject to various contingencies and uncertainties relating to its operations and construction programs, including legal actions, and regulations and uncertainties related to environmental matters.

To meet cash needs for operating expenses, the payment of interest, retirement of debt, and acquisitions and construction programs, the Company has used internally generated funds (net cash provided by operating activities less dividends), member contributions from Allegheny Energy, and external financings, such as debt instruments, installment loans, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, the Company's cash needs, and its capital structure objectives. The availability and cost of external financings depend upon the Company's financial condition and market conditions.

The Company's ability to meet its payment obligations under its indebtedness, fund capital expenditures, and maintain adequate direct and indirect credit support will depend on its future operations. The Company's future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control, as discussed in "Factors That May Affect Future Results" on page 20. The Company's future performance could affect its ability to maintain its investment grade credit rating.

The Company previously had 364-day credit facilities totaling $1.3 billion, which required the Company to maintain an investment grade credit rating. The failure of the Company to maintain an investment grade credit rating would have constituted an event of default as defined in the credit agreements.

In April 2002, the Company replaced those credit facilities with two new credit facilities and long-term debt. The two new credit facilities totaling $965.0 million do not require the Company to maintain any given credit rating. These facilities do require the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio. Also in April 2002, the Company issued $650 million of 8.25 percent notes due April 15, 2012. As a result, the Company no longer has any credit facilities that require it to maintain an investment grade credit rating.

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The Company has credit facilities and lease agreements that require the maintenance of certain fixed-charge coverage ratio and debt-to-capitalization ratio. The Company is required to maintain a .65 debt-to-capitalization ratio. The Company is also required to maintain a 2.0 fixed-charge coverage ratio. As of June 30, 2002, the Company was in compliance with the requirements.

The Company's $965.0 million credit facility is available for direct borrowing, commercial paper backstop, and letters of credit. As of June 30, 2002, the Company had borrowed $50.0 million on the credit facility, issued $265.6 million of commercial paper, and had $169.2 million in letters of credit outstanding, leaving $480.2 million available under the credit facility. As of June 30, 2002, the Company had also used all $15.0 million of an additional line of credit.

On August 8, 2002, Moody's Investors Service (Moody's) announced that it had placed its ratings of Allegheny Energy and all of Allegheny Energy's subsidiaries on review. Moody's also indicated in its press release that its review will focus on a number of factors, including the Company's weaker-than-expected operating cash flows and earnings, currently unfavorable power purchase and hedging arrangements, challenges to a key power sales agreement, and a deteriorating outlook for wholesale power markets, as well as the Company's plans for mitigating actions.

On April 16, 2002, Fitch, Inc. (Fitch) changed the rating of Allegheny Energy's senior unsecured debt to BBB+ from A- and the rating for commercial paper to F2 from F1. In addition, the ratings on West Penn's and Potomac Edison's senior unsecured debt was changed to A from A+. The commercial paper ratings of both West Penn and Potomac Edison were affirmed at F1. On May 31, 2002, Fitch lowered the debt and preferred stock ratings of Monongahela Power. Monongahela Power's senior unsecured debt rating was changed to A- from A, the preferred stock rating was changed to BBB+ from A-, and its commercial paper rating was affirmed at F1.

On August 12, 2002, Fitch placed the ratings of Allegheny Energy, AGC, Monongahela Power, Potomac Edison, West Penn, and the Company, and the Company's special purpose entity Allegheny Energy Supply Statutory Trust 2001 (Allegheny Energy Supply Statutory Trust) on "Rating Watch Negative." Fitch indicated that the Rating Watch Negative affecting Allegheny Energy, Inc. and the Company reflects Fitch's concern over the tight liquidity position of both companies in 2002 and weakening credit protection measures resulting from unfavorable developments in the power markets. Ratings for Monongahela Power, Potomac Edison, West Penn, AGC, and Allegheny Energy Supply Statutory Trust were placed on Rating Watch Negative due to Fitch's policy regarding the notching of subsidiaries within a holding company group.

On April 4, 2002, Standard & Poor's announced that it had equalized the corporate credit ratings of all rated Allegheny Energy companies at BBB+. This rating equalizes the Company, AGC, and Allegheny Energy's three regulated utility subsidiaries - Monongahela Power, Potomac Edison, and West Penn. Standard & Poor's unsecured debt ratings for the companies are now as follows: Allegheny Energy, BBB; the Company, BBB+; AGC, BBB+; Monongahela Power, BBB; Potomac Edison, BBB; and West Penn, BBB+. Standard & Poor's outlooks for all companies are stable.

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The Company is required to provide collateral to certain energy trading counterparties. The amount of collateral required is affected by market price changes for electricity, natural gas, and other energy-related commodities and other factors. Such collateral might be in the form of letters of credit, cash deposits, or liquid securities. Any requirement to provide additional collateral in the future could have an adverse effect on the Company's liquidity. As of June 30, 2002, the Company had received $2.0 million of cash collateral from and provided $.4 million of cash collateral to counterparties involved in the Company's energy trading activities.

The Company also has credit facilities, or lines of credit, which provide for direct borrowings, a backstop to commercial paper programs, and the issuance of letters of credit to support general corporate purposes and energy trading activities. As of June 30, 2002, none of AGC's $195.0 million of the Company's lines of credit with banks were drawn. All of the available lines of credit were supporting commercial paper. Effective July 1, 2002, the lines of credit declined to $175.0 million.

In summary, the Company and Allegheny Energy had approximately $373.1 million of trade credit support commitments outstanding as of June 30,2002, for energy trading activities, which included $169.2 million of letters of credit, $1.6 million of net cash deposits held, and $205.5 million of Allegheny Energy guarantees. As of December 31, 2001, the Company and Allegheny Energy had approximately $400.5 million of trade credit support commitments for energy trading activities, which included $207.7 million of outstanding letters of credit, $12.3 million of net cash deposits posted, and $180.5 million of Allegheny Energy guarantees.

Internal generation of cash, consisting of cash flows from operations was $(24.8) million and $(193.3) million for the six months ended June 30, 2002 and 2001, respectively.

Cash flows from operations for the six months ended June 30, 2002 increased by $168.4 million versus the six months ended June 30, 2001. During the six months ended June 30, 2002, the Company received cash of $87.2 million relating to estimated tax overpayments and net operating loss carrybacks generated in 2001. During the six months ended June 30, 2001, the Company made payments for income taxes of $20.1 million. Cash flows from operations in the first quarter of 2002 also increased due to an increase in depreciation expenses of $12.3 million and a decrease in affiliated accounts receivable/payable, net of $77.7 million. These increases in cash flows from operations were partially offset by an increase in materials and supplies of $11.0 million and an increase in accrued payroll expenses of $38.0 million. The Company's cash flows from operations also include the results of its energy trading activities. During the six months ended June 30, 2002 and 2001, the Company's energy trading activities res ulted in approximately $43.1 million and $89.7 million of net realized losses, respectively. See "Operating Revenues" starting on page 27 for additional details regarding the cash outflows for the energy trading activities.

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Cash flows used in investing for the six months ended June 30, 2002 decreased by $1,549.6 million from the first quarter of 2001. For the six months ended June 30, 2001, the Company paid $489.2 million for the acquisition of energy marketing and trading business and $1,053.0 million for the acquisition of three generating facilities in the Midwest. Construction expenditures during the six months ended June 30, 2002 and 2001 were $49.3 million and $79.9 million, respectively. For the six months ended June 30, 2002, the Company had expenditures of $29.7 million for unregulated investments.

Cash flows provided by financing for the six months ended June 30, 2002 decreased by $1,718.0 million from the six months ended June 30, 2001. This decrease was due primarily to a $1,561.5 million decrease in short-term debt and notes payable to parent and affiliates financing, a $8.4 million increase in notes receivable due within one year, a $270.4 million decrease in Allegheny Energy member contributions to the Company and a $130.0 million increase in the retirement of long-term debt which were partially offset by a $252.3 million increase for the issuance of long-term debt.

Members' Equity For the six month period ended June 30, 2002, members' equity increased by $195.7 million. The increase was due to a $.5 million equity contribution from Allegheny Energy, a parent of the Company, the partial forgiveness of $193.0 million of the Company's $325.0 million affiliated notes payable to Allegheny Energy, consolidated net income of $3.2 million, and other comprehensive income of ($1.0) million.

Long-term Debt The Company's long-term debt increased by $514.9 million during the six months ended June 30, 2002 to $1,864.1 million as of June 30, 2002. For the six months ended June 30, 2002, the Company made repayments of $46.5 million on unsecured notes and redeemed $80.0 million of floating rate medium-term debt. The Company also redeemed $3.5 million of pollution control bonds per their original terms.

In April 2002, the Company issued $650.0 million of 8.25 percent notes due April 15, 2012. The Company used the net proceeds from the notes to repay short-term indebtedness of $630.0 million, which included a bridge loan in the amount of $550.0 million that was entered into in connection with the acquisition of the Midwest Assets, and for general corporate purposes.

Short-term Debt Short-term debt and notes payable to Allegheny Energy and affiliates decreased by $591.4 million during the six months ended June 30, 2002 to $482.4 million. As of June 30, 2002, short-term debt and notes payable to Allegheny Energy and affiliates consisted of commercial paper borrowings of $265.6 million, lines of credit of $65.0 million, and notes payable to Allegheny Energy and affiliates of $151.8 million.

A one percent increase in the short-term borrowing interest rate would increase projected short-term interest expense by approximately $1.9 million for the six months ended December 31, 2002, based on projected short-term borrowings.

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Operating Lease Transactions In November 2001, the Company entered into an operating lease transaction in connection with the construction of a 628-MW natural gas fired generating facility in St. Joseph County, Indiana. In July 2002, the Company announced the cancellation of two 44-MW simple-cycle combustion turbines. The reduced 540-MW combined-cycle facility is expected to be in service in 2004. Accordingly, the Company plans to amend the lease to reduce commitments.

In April 2001, the Company entered into an operating equipment lease transaction structured to finance the purchase of turbines and transformers. In May 2002, this lease was terminated for $33.1 million and the equipment was used in the project with CONSOL Energy, Inc. that placed into operation an 88-MW generating facility in southwest Virginia.

The electricity supply segment of the energy industry in the United States is becoming increasingly competitive. The national Energy Policy Act of 1992 led to market-based regulation of the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. The Company continues to be an advocate of federal legislation to remove artificial barriers to competition in electricity markets, avoid regional dislocations, and ensure a level playing field.

The U.S. House and Senate each have passed energy bills and a conference representing the two chambers is in the initial stages of reconciling the two pieces of legislation. A final conference report is expected to be one of the last matters to be dealt with by this Congress prior to adjournment, probably in September or October of 2002. Included in energy legislation passed by the Senate and favorably considered by the House are restructuring provisions including the repeal or significant revision of the Public Utility Holding Company Act of 1935 (PUHCA), which is an issue of primary importance to the Company. Among other issues that will be considered by the conference are revisions of Section 210 (Mandatory Purchase Provisions) of the Public Utility Regulatory Policies Act (PURPA) and the possibility of a renewable portfolio standard mandate, resolution of transmission issues and possibly regional transmission organizations (RTOs).

Congressional interest has increased concerning the replacement of the piecemeal federal approach to improving air quality with a more comprehensive strategy to regulate Clean Air Act pollutants - sulfur dioxide (SO₂), nitrogen oxides (NO_X), and mercury. The current Administration has drafted and sent to Congress the Clear Skies legislation, which is its attempt at accomplishing this strategy. While its introduction so late in the session in all likelihood prevents

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meaningful action in this Congress, it is drawing serious debate and is expected to be reintroduced in 2003. Another pending proposal in the current Congress would require carbon dioxide (CO₂) emission reductions. Legislation to regulate SO₂, NOX, mercury, and CO₂ was approved by the Senate Environment and Public Works Committee. However, a number of both political and technical impediments will very likely prevent any further action before Congress adjourns this year.

The Environmental Protection Agency's (EPA) nitrogen oxides (NO_X) State Implementation Plan (SIP) call regulation has been under litigation, and, on March 3, 2000, the United States Court of Appeals issued a decision that upheld the regulation. However, state and industry litigants filed an appeal of that decision in April 2000. On June 23, 2000, the Court denied the request for the appeal. Although the Court did issue an order to delay the compliance date from May 1, 2003, until May 31, 2004, both the Maryland and Pennsylvania state rules to implement the EPA NO_X SIP call regulation still require compliance by May 1, 2003. West Virginia has issued a final rule that would require compliance by May 31, 2004. The EPA Section 126 petition regulation also requires the same level of NO_X reductions as the EPA NO_X SIP call regulation and was also under litigation in the United States Court of Appeals. A Court decision in May 2001 upheld the rule. In Augus t 2001, the Court issued an order that suspended the Section 126 petition rule May 1, 2003, compliance date pending EPA review of growth factors used to calculate the state NO_X budgets. In January 2002, the EPA announced its intention to revise the Section 126 petition rule compliance date from May 1, 2003, to May 31, 2004. The Company's compliance with such stringent regulations will require the installation of post-combustion control technologies on most of its power stations. The Company's construction forecast includes the expenditure of $192.3 million of capital costs during the 2002 through 2003 period to comply with these regulations.

Other Litigation

On April 23, 2002, a class action complaint was filed in the Superior Court of California seeking relief and an unspecified amount of restitution from various defendants, including the Company, under the California Unfair Business Practices Act related to the alleged manipulation of energy markets in California by power suppliers and to its contract with the Department of Water Resources. While the Company believes that the charges are without merit, it cannot predict the outcome of the litigation at this time.

On May 13, 2002, it was reported in the press that two additional complaints were filed in the Superior Court of California alleging that power suppliers, including the Company, took advantage of a manipulated market to overcharge for contracted electricity. As of the date of this report, the Company has not been served any documents related to the two additional complaints. At this time, it is not possible to predict the outcome of these proceedings.

On May 8, 2002 the FERC staff, pursuant to a fact-finding investigation of potential manipulation of electric and natural gas prices in the western markets,

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requested that all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator (ISO) and/or the California Power Exchange during 2000 and 2001 provide certain data and other information relating to such sales and to "representative trading strategies." The data request was issued to over 140 companies, including the Company. The Company did not engage in any such sales, and prepared a response to the FERC to such effect.

In the normal course of business, the Company becomes involved in various legal proceedings. The Company does not believe that the ultimate outcome of these proceedings will have a material effect on its results of operations, cash flows, or financial position. See Note 9 for additional information regarding environmental matters and litigation, including FERC proceedings in California.

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The Company is exposed to market risks associated with commodity prices and interest rates. The commodity price risk exposure results from market fluctuations in the price and transportation costs of electricity, natural gas, and other energy-related commodities. The interest rate risk exposure results from changes in interest rates related to interest rate swaps, commercial paper, and variable and fixed-rate debt. The Company is mandated by Allegheny Energy's Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

Allegheny Energy has a Corporate Energy Risk Policy adopted by its Board of Directors and monitored by a Risk Management Committee chaired by its Chief Executive Officer and composed of senior management. An Allegheny Energy risk management group actively measures and monitors the risk exposures to ensure compliance with the policy and that it is periodically reviewed.

To manage the Company's financial exposure to commodity price fluctuations in its energy trading, fuel procurement, power marketing, natural gas supply, and risk management activities, the Company routinely enters into contracts, such as electricity and natural gas purchase and sale commitments, to hedge its risk exposure. However, the Company does not hedge the entire exposure of its operations from commodity price volatility for a variety of reasons. To the extent the Company does not successfully hedge against commodity price volatility, its results of operations, cash flows, or financial position may be affected either favorably or unfavorably by a shift in the future price curves.

Also, the Company's energy trading business enters into certain contracts for the sale of electricity produced by its Midwest generating assets and its other generating facilities in excess of the power provided to Allegheny Energy's regulated utility subsidiaries to meet their provider of last resort obligations. These contracts are recorded at their fair value and are an economic hedge for the generating facilities. For accounting purposes, the generating facilities are recorded at historical cost less depreciation. As a result, the Company's results of operations and financial position can be favorably or unfavorably affected by a change in future market prices used to value the contracts, since there is not an offsetting adjustment to the recorded cost of the generating facilities.

Of its commodity-driven risks, the Company is primarily exposed to risks associated with the wholesale marketing of electricity, including the generation, fuel procurement, power marketing, and trading of electricity. The Company's wholesale activities principally consist of marketing and trading over-the-counter forward contracts, swaps, and NYMEX futures contracts for the purchase and sale of electricity and natural gas. The majority of these contracts represent commitments to purchase or sell electricity and natural gas at fixed prices in the future. The Company's forward contracts generally require physical

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delivery of electricity and natural gas. The swap and NYMEX futures contracts generally require financial settlement.

The Company also uses option contracts to buy and sell electricity and natural gas at fixed prices in the future. These option contracts are generally entered into for energy trading and risk management purposes. The risk management activities focus on management of volume risks (supply), operational risks (facility outages), and market risks (energy prices).

A portion of the Company's energy trading activities involves long-term structured transactions. Since January 1, 2002, the Company entered into certain long-term contracts as part of its energy trading activities that may affect its market risk exposure. Uncertainty regarding market conditions and commodity prices increases further into the future. The following contracts that extend beyond five years were added to the Company's energy trading portfolio during 2002:

- The Company has a long-term agreement with Kern River Gas Transmission   Company that will start in May 2003, under tariffs approved by the FERC.   These agreements, in part, provide for firm transportation of 45,112 million   cubic feet (Mcf) of natural gas per day through April 30, 2018, from southwest   Wyoming to southern California; and

- In March 2002, the Company entered into a financial natural gas tolling   contract to sell 88MW to Dominion Energy Marketing starting August 2002   through June 2009.

Credit Risk Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. The credit standing of counterparties is established through the evaluation of the prospective counterparty's financial condition, specified collateral requirements where deemed necessary, and the use of standardized agreements, which facilitate netting of cash flows, associated with a single counterparty. Financial conditions of existing counterparties are monitored on an ongoing basis. Allegheny Energy's risk management group oversees credit risk. As of June 30, 2002, the Company has received $2.0 million of cash collateral from counterparties involved in its energy trading activities.

The Company is engaged in various energy trading activities in which counterparties primarily include electric and natural gas utilities, independent power producers, oil and natural gas exploration and production companies, energy marketers, and commercial and industrial customers. In the event the counterparties do not fulfill their obligations, the Company may be exposed to credit risk. The risk of default depends on the creditworthiness of the counterparty or issuer of the instrument. The Company has a concentration of customers in the electric and natural gas utility and oil and natural gas exploration and production industries. These concentrations in customers may affect the Company's overall exposure to credit risk, either positively or

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negatively, in that the customers may be similarly affected by changes in economic or other conditions. The following table provides the net fair value of commodity contract asset positions by counterparty credit quality for the Company as of June 30, 2002:

The net fair value of $1.3 billion, or 20.3 percent of the Company's total assets, for "No external ratings - Government agencies" mainly relates to the Company's power sales agreement with the CDWR, the department within the state government of California that is responsible for buying electricity for that state. As of June 30, 2002, the CDWR had not received a credit rating from an external, independent credit rating agency. On February 21, 2002, the California PUC approved a rate agreement with the CDWR in order for the CDWR to issue bonds to repay the state of California's general fund and other outstanding loans. The agreement would create two streams of revenue for the CDWR by establishing bond charges and power charges on electricity customers. Revenues from power charges will be used to pay the CDWR's operating expenses, including payment of its long-term power purchase agreements. Certain, as yet unspecified, operating expenses of the CDWR will be payable from the bond charge. The rate agre ement would require the CDWR to use its best efforts to renegotiate its long-term power agreements and does not limit the ability of the California PUC or the CDWR to engage in litigation regarding those contracts. If the Company's agreement were renegotiated or if the CDWR failed for any reason to meet its obligations under this agreement, the value of the agreement as an asset might need to be reduced on the Company's consolidated balance sheet, with a corresponding reduction in net income. As of June 30, 2002, the CDWR has met all of its obligations under this agreement.

On February 25, 2002, the California PUC and the California Electricity Oversight Board (CAEOB) filed complaints with the FERC regarding various contracts to which the CDWR is a counterparty, including two contracts with the Company to sell power to the CDWR. The California PUC complaint requested that each of the contracts challenged in the complaint be abrogated, as containing both unreasonable pricing and unjust and unreasonable non-price terms and conditions, or, in the alternative, that the challenged contracts be reformed to provide for just and reasonable pricing, reduce their duration, and strike from the contracts the specific non-price contract terms and conditions found to be unjust and unreasonable. The CAEOB's complaint requested that the contracts be voidable at the state of California's option, abrogated, or reformed. On March 18, 2002, the Company filed its response to the California PUC and CAEOB complaints in which it requested that the complaints be expeditiously denied.

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On April 25, 2002, in response to complaints filed by the California PUC and the CAEOB against the Company and numerous other suppliers, the FERC set for hearing the issue of whether the dysfunctional spot market in California had an adverse effect on the long-term, bilateral markets in California, including with respect to two contracts entered into between the Company and the CDWR, and if so, whether the effect was of such a magnitude to warrant modification of bilateral long-term contracts. The FERC also held that, with respect to the Company's contracts, the higher "public interest" standard, rather than the "just and reasonable" standard should apply. On July 23, 2002, the FERC denied various requests for rehearing of the its April 25, 2002 Order. The Company cannot predict the outcome of this litigation.

On December 2, 2001, various Enron Corporation entities, including, but not limited to, Enron North America Corporation and Enron Power Marketing, Inc., collectively Enron, filed voluntary petitions for Chapter 11 reorganization with the United States Bankruptcy Court for the Southern District of New York.

The Company and Enron have master trading agreements in place, which include an International Swaps and Dealers Association Agreement, a Master Power Purchase and Sale Agreement, and a Master Gas Purchase and Sale Agreement (Agreements). Within all of these Agreements, there is netting and set-off language. This language allows the Company and Enron to net and set-off all amounts owed to each other under the Agreements.

Pursuant to the Agreements, the voluntary petition for Chapter 11 reorganization by Enron constituted an event of default. The Company effected an early termination as of November 30, 2001, with respect to each of the Agreements, as permitted under the terms of the Agreements.

The Company believes it has appropriately exercised its contractual rights to terminate the Agreements and to net out transactions arising within each Agreement. Pursuant to the Bankruptcy Code, the Company believes it should be able to offset any termination values or payment amounts owed it against amounts it owes to Enron as a result of the netting. As of November 30, 2001, the fair value of all the Company's trades with Enron that were terminated was a net asset of approximately $27 million and the Company had a net payable to Enron of approximately $25 million. After applying the netting provisions of each Agreement, including any collateral posted by Enron with the Company, approximately $4.5 million was expensed as uncollectible in 2001.

In early August 2002, Enron sent a demand letter to the Company for approximately $26 million for a net payable from November 2001. The Company has asked Enron for clarification on its calculation including a determination of interest amounts. The Company has also provided its set-off position with Enron. Once The Company receives clarification from Enron, the parties will enter into negotiations regarding the settlement of all outstanding claims under the bankruptcy proceeding. The Company believes it will be able to set-off all outstanding exposures with the various Enron entities and come to a reasonable settlement of these claims.

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Market Risk Market risk arises from the potential for changes in the value of energy related to price and volatility in the market. The Company reduces these risks by using its generating assets and contractual generation under its control to back positions on physical transactions. Aggregate and counterparty market risk exposure and credit risk limits are monitored within the guidelines of the Corporate Energy Risk Policy. The Company evaluates commodity price risk, operational risk, and credit risk in establishing the fair value of commodity contracts.

The Company uses various methods to measure its exposure to market risk, including a value at risk model (VaR). VaR is a statistical model that attempts to predict risk of loss based on historical market price and volatility data over a given period of time. The quantification of market risk using VaR provides a consistent measure of risk across diverse energy markets and products with different risk factors to set the overall corporate risks tolerance, determine risk targets, and monitor positions. The Company calculates VaR using a variance/covariance technique that models option positions, using a linear approximation of their value based upon the options' delta equivalents. Due to inherent limitations of VaR, including the use of approximations to value options, subjectivity in the choice of liquidation period, and reliance on historical data to calibrate the model, the VaR calculation may not accurately reflect the Company's market risk exposure. As a result, the actual changes in the Company's market risk sensitive instruments could differ from the calculated VaR, and such changes could have a material effect on its financial results. In addition to VaR, the Company routinely performs stress and scenario analyses to measure extreme losses due to exceptional events. The VaR and stress test results are reviewed to determine the maximum allowable reduction in the fair value of the energy trading portfolios.

The Company's VaR calculation includes all contracts, whether financially or physically settled, associated with its wholesale marketing and trading of electricity, natural gas, and other commodities. The Company calculates the VaR, including its generating capacity and the power sales agreements for Allegheny Energy's regulated utility subsidiaries' provider of last resort retail load obligations. The VaR calculation does not include positions beyond three years because there is a limited, observable, liquid market. The VaR calculation also does not include commodity price exposure related to the procurement of fuel for its generation. The Company believes that this represents the most complete calculation of its value at risk.

The VaR amount represents the potential loss in fair value from the market risk sensitive positions described above over a one-day holding period with a 95-percent confidence level. As of June 30, 2002, the Company's VaR was $2.8 million, including its generating capacity and power sales agreements with Allegheny Energy's regulated utility subsidiaries. This VaR is lower than the Company's VaR at December 31, 2001, of $14.4 million. The change in VaR for the six months ended June 30, 2002, is primarily due to a reduction in the net open positions in the Company's energy marketing and trading portfolio and a change in the methodology used to compute the volatility of energy prices used in the VaR calculation. The Company also calculated VaR using the full term of all trading

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positions, but excluded its generating capacity and the provider of last resort retail load obligations of its regulated utility subsidiaries. This calculation includes positions beyond three years for which there is a limited, observable, liquid market. As a result, this calculation is based upon management's best estimates and modeling assumptions, which could materially differ from actual results. As of June 30, 2002, this calculation yielded a VaR of $10.1 million.