ALLEGHENY GENERATING CO - 10-K Annual Report

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Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY ENERGY, INC., ALLEGHENY ENERGY SUPPLY COMPANY, LLC, MONONGAHELA POWER COMPANY, THE POTOMAC EDISON COMPANY, WEST PENN POWER COMPANY, AND ALLEGHENY GENERATING COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.

Allegheny Energy, Inc. (AE) was incorporated in Maryland in 1925. AE is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). It is a diversified utility holding company that has experienced significant changes in its business in the states in which its subsidiaries operate. As deregulation of electric generation has been implemented, AE’s subsidiaries have transferred their generating assets, excluding Monongahela Power Company’s (Monongahela) West Virginia jurisdictional generating assets, from their regulated utility businesses to Allegheny Energy Supply Company, LLC (AE Supply), an affiliated, unregulated (i.e., not subject to state rate regulation) generation business, in accordance with approved deregulation plans. AE operates primarily through various directly and indirectly owned regulated and unregulated subsidiaries (collectively and generically, Allegheny, we, us, or our).

AE Supply is an unregulated energy company that develops, owns, operates, and manages electric generating facilities and, through its fuel and power markets division, purchases and sells energy and energy-related commodities. AE Supply manages its generating assets as an integral part of its wholesale marketing, fuel procurement, risk management, and asset-based energy trading activities. AGC owns and sells generating capacity to its parent companies, AE Supply and Monongahela.

During 2002, the Generation and Marketing segment achieved operating revenues of $936.7 million, net of intersegment eliminations.

Monongahela (including Mountaineer), Potomac Edison, and West Penn all do business under the trade name Allegheny Power. We refer, collectively, to Monongahela, Potomac Edison, and West Penn and their subsidiaries as the Distribution Companies. The principal business of the Distribution Companies and the Delivery and Services segment is the operation of electric and natural gas public utility systems. The primary service areas of the Distribution Companies are rural and suburban with economies based primarily in manufacturing and natural resources and services.

During 2002, the Delivery and Services segment achieved operating revenues of $2,051.8 million, net of intersegment eliminations.

AE Supply is a Delaware limited liability company formed in 1999. It owns and operates a diverse set of generating assets. AE Supply is registered as a holding company under PUHCA. As of December 31, 2002, the Generation and Marketing segment owned or contractually controlled 12,041 megawatts (MW) of generating capacity (including long-term contractual rights to call up to 1,000 MW in California). As of September 1, 2003, taking into account the addition of AE Supply’s new facilities in Springdale, Pennsylvania, AE Supply’s sale of its interest in the Conemaugh Generating Facility, and the terminations of certain of AE Supply’s tolling agreements, the Generating and Marketing segment owned or contractually controlled 11,498 MW of generating capacity. AE Supply’s generating assets include an entitlement to 202 MW of capacity in the Ohio Valley Electric Corporation (OVEC). AE Supply, as part of its fuel and power markets division, markets the Generation and Marketing segment’s electric generating capacity to various customers and markets. Currently, the majority of AE Supply’s normal operating capacity is dedicated to supplying the provider-of-last resort (PLR) obligations of the Distribution Companies. (See ITEM 1. BUSINESS, Fuel, Power, and Resource Supply—The Delivery and Services Segment). AE Supply’s 2002 total operating revenues were $683.0 million.

Monongahela (Generation). Monongahela’s West Virginia jurisdictional generation assets are included in our Generation and Marketing segment. Monongahela was incorporated in Ohio in 1924. It owns generating capacity in West Virginia and Pennsylvania. In 2001, Monongahela transferred part of its share in generating assets and AGC to AE Supply pursuant to state legislation and regulatory authorizations. Monongahela also operates an electric T&D system in northern West Virginia and in an adjacent portion of Ohio. Its business is managed along two segments, its Generation and Marketing segment, which comprises its generation operations, and its Delivery and Services segment, which encompasses its T&D business.

AGC was incorporated in Virginia in 1981. It is owned by AE Supply (77.03 percent) and Monongahela (22.97 percent). AGC has no employees. Its sole asset is a 40-percent undivided interest in the Bath County, Virginia, pumped-storage hydroelectric station, which was placed in commercial operation in December 1985, and its connecting transmission facilities. All of AGC’s revenue is derived from sales of its 960-MW share of generating capacity from the Bath County Station to its two parent companies. The remaining 60-percent interest in the Bath County Station is owned by an unaffiliated company, Dominion Virginia Electric and Power Company (Virginia Power). AGC’s 2002 total operating revenues were $64.1 million.

Monongahela (T&D). Monongahela’s T&D assets are included in our Delivery and Services segment. Monongahela operates its electricity T&D business, serving approximately 395,000 electric customers, under the trade name Allegheny Power. Monongahela transferred operational control over its transmission system to PJM Interconnection, L.L.C. (PJM), a regional transmission organization (RTO), in April 2002. See —Allegheny’s Competitive Actions—Distribution Companies—Participation in RTOs, below.

Monongahela also conducts a regulated natural gas T&D business, primarily through its Mountaineer subsidiary. Monongahela serves approximately 230,000 residential, commercial, industrial, and wholesale natural gas customers in West Virginia, and owns approximately 4,850 miles of natural gas distribution pipelines. During 2002, Monongahela sold or transported 63.7 billion cubic feet (Bcf) of natural gas. Mountaineer also includes Mountaineer Gas Services, Inc. (MGS), which operates natural gas-producing properties, natural gas-gathering facilities, and intrastate transmission pipelines and is engaged in the sale and marketing of natural gas in the Appalachian basin. MGS owns more than 300 natural gas wells and has a net revenue interest in about 100 additional wells.

Monongahela’s electric and natural gas service area covers approximately 13,000 square miles with a population of approximately 1,223,000. Monongahela’s 2002 total operating revenues were $917.0 million.

Potomac Edison was incorporated in Maryland in 1923 and incorporated in Virginia in 1974. It operates an electric T&D system in portions of Maryland, Virginia, and West Virginia under the trade name Allegheny Power. Potomac Edison transferred operational control over its transmission system to PJM effective April 2002. Potomac Edison serves approximately 428,000 electric customers in a service area of about 7,300 square miles with a population of approximately 933,000. Potomac Edison’s 2002 total operating revenues were $870.2 million.

In 2000, Potomac Edison transferred all of its generating assets, its interest in AGC, and its entitlement to capacity in OVEC to AE Supply pursuant to state legislation and regulatory authorizations.

West Penn was incorporated in Pennsylvania in 1916. It operates an electric T&D system in southwestern, north, and south-central Pennsylvania under the trade name Allegheny Power. West Penn transferred operational control over its transmission system to PJM in April 2002. West Penn serves approximately 693,000 electric customers in a service area of about 9,900 square miles with a population of approximately 1,486,000. West Penn’s 2002 total operating revenues were $1,153.1 million.

In 1999, West Penn transferred all of its generating assets, its interest in AGC, and its entitlement to capacity in OVEC to AE Supply pursuant to state legislation and regulatory authorizations.

Allegheny Ventures was incorporated in Delaware in 1994 to engage in activities such as telecommunications and unregulated energy-related projects. Allegheny Ventures has two principal subsidiaries:

Both ACC and AE Solutions are Delaware corporations, wholly-owned by Allegheny Ventures. ACC develops fiber-optic projects, including fiber and data services. AE Solutions manages energy-related projects. Allegheny Ventures’ 2002 total operating revenues were $648.3 million, which include revenues from Fellon-McCord & Associates, Inc. (Fellon-McCord) and Alliance Energy Services, LLC (Alliance Energy Services), which were sold on December 31, 2002.

Allegheny Energy Service Corporation (AESC) was incorporated in Maryland in 1963 as a service company for AE. Aside from a small number of employees obtained by AE Supply in 2001 as part of an acquisition of the Lincoln Generating Facility, AE, AE Supply, the Distribution Companies, AGC, Allegheny Ventures, and their subsidiaries have no employees. Their officers and, except as noted above, all personnel of Allegheny are employed by AESC. AESC’s employees provide all necessary services to AE, AE Supply, the Distribution Companies, AGC, Allegheny Ventures and their subsidiaries. Those companies reimburse AESC at cost for services provided by AESC’s employees. AESC had approximately 5,400 employees as of December 31, 2002, and approximately 5,300 employees as of September 15, 2003.

AE, AE Supply, Monongahela, Potomac Edison, West Penn, and AGC file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements (for AE), and other information, and any amendments thereto, with or to the U.S. Securities and Exchange Commission (SEC). You may read and copy any document we file with the SEC at the SEC’s public reference rooms at 450 Fifth Street, N.W., Washington, D.C. 20549, 233 Broadway, New York, New York 10279, and Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms. Such SEC filings are also available to the public from the SEC’s web site at http://www.sec.gov.

The annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, other information, and any amendments to those reports that AE, AE Supply, Monongahela, Potomac Edison, West Penn, and AGC file with or furnish to the SEC are available free of charge on AE’s web site at http://www.alleghenyenergy.com as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. AE’s web site and the information contained therein are not incorporated into this report.

In 2000, Allegheny’s goal was to transform its energy supply business, which it began to separate from its T&D business in 1999, into a national energy merchant. As of December 31, 2000, AE Supply owned or contractually controlled 6,609 MW of generating capacity. In 2001, Allegheny planned to continue to expand its generation asset base and become a leading national energy merchant in domestic retail and wholesale markets with offices and/or generating facilities in 15 states. AE Supply intended to add approximately 4,800 MW of additional generating capacity, either through acquisitions or construction of facilities. Allegheny’s business model for AE Supply assumed that a growing, liquid energy trading market would continue to develop, which would allow Allegheny to realize the value of new generation and meet attendant debt service obligations. Implicit in this assumption was that federal and state initiatives to promote the growth of competitive wholesale and retail power markets would continue.

In January 2001, AE Supply announced it had signed a definitive agreement to acquire the energy trading division of Merrill Lynch & Co., Inc. (Merrill Lynch). The acquisition was completed in March 2001 and was intended to enhance Allegheny’s energy marketing and trading operations. The focus of AE Supply’s trading shifted from asset-backed, short-term trading in and around its generating assets to the acquisition of long-dated structured transactions and associated hedges. These transactions significantly increased AE Supply’s cash requirements, which eventually strained its liquidity position.

Energy trading contracts generally require collateral postings from time to time between the counterparties based on the relative fair values of each party’s position. However, not all of AE Supply’s energy trading contracts require the posting of collateral with or by the counterparty. For example, its contract with the California Department of Water Resources (CDWR) did not require the CDWR to post collateral, while the power purchased by AE Supply from counterparties to hedge the CDWR contract generally required AE Supply to post collateral. As power prices fell from the high levels in early to mid-2001, AE Supply was required to post

significantly more collateral than it was holding. In addition, AE Supply hedged the on-peak positions of the CDWR contract through 2003 at market prices that were above the fixed contract price of $61 per MWh that AE Supply received from the CDWR. This created significant cash outflows for 2001, 2002, and 2003.

AE Supply also expanded its owned and controlled generating capacity in 2001 by nearly one-third, or more than 3,500 MW, in markets transitioning to competition throughout the United States. AE Supply primarily used debt to finance its growth. The expansion of the energy trading activities and generating capacity required a significant amount of capital. As a result, Allegheny’s equity to total capitalization decreased from 39.8 percent at December 31, 2000, to 26.85 percent at December 31, 2002. As described below, Allegheny’s financing authorizations under PUHCA are subject to AE and AE Supply’s meeting minimum equity to total capitalization ratio requirements.

AE had planned an initial public offering (IPO) of equity in AE Supply stock to finance its growth strategy. Early in 2001, there had been investor enthusiasm for offerings of merchant energy companies. Natural gas prices were soaring and the forward price of wholesale electricity was high. By mid-2001, however, consumer energy demand began to decrease and natural gas prices declined, causing wholesale energy prices to fall. In 2001, concern arose over the integrity and design of the California wholesale energy markets. By the end of 2001, these dramatic changes in market conditions and landscape led Allegheny to abandon the IPO strategy.

By 2002, energy market deregulation had been implemented in four of the five states served by the Distribution Companies, and AE Supply, with its low-cost generation assets, was believed to be well-positioned to benefit from a continuing deregulatory trend. AE Supply’s business strategy assumed a continuation of federal and state initiatives to promote the growth of competitive wholesale and retail power markets. However, events have caused the formerly prevailing deregulatory trend to stall and, in some cases, reverse. These events included Enron Corporation’s (Enron) bankruptcy and subsequent disclosures and issues concerning the California power market. Other energy companies had adopted strategies similar to Allegheny’s, and capacity was added to the merchant power market. In 2002, the additional capacity, along with weak economic conditions, led to a deepening of the lower-than-expected wholesale power prices within AE Supply’s primary markets that had begun in 2001. In addition, wholesale energy market liquidity dissipated in 2002. Many formerly active trading firms exited the energy trading market, and many of the remaining participants faced (and continue to face) deteriorating credit ratings and credit and liquidity issues. At the same time, several states suspended their retail competition programs, delayed the implementation of such programs, or announced that they would not pursue retail competition in the foreseeable future. As a result, the robust merchant power market and liquid energy trading market to which Allegheny had oriented its operations and corporate structure failed to materialize, and wholesale power prices dropped below forecasts. For further discussion, see —Regulatory Framework Affecting Allegheny—State Legislation and Regulatory Developments, below.

In December 2001, Nevada Power Company commenced proceedings to modify the terms of certain power supply arrangements with AE Supply. In February 2002, California state agencies brought actions to cancel AE Supply’s power supply contracts with CDWR. These proceedings challenged the validity and viability of significant assets and sources of cash flow.

In August 2002, Allegheny’s independent auditor, PricewaterhouseCoopers LLP (PwC), advised Allegheny that it noted certain matters involving internal controls that PwC considered to be material weaknesses, including matters with respect to AE Supply’s trading operations and related information systems. In the third quarter of 2002, AE initiated a comprehensive review of its financial information. During the pendency of this review, Allegheny was not able to file with the SEC its Forms 10-Q for the first and second quarters of 2003 and third quarter of 2002, its amended Forms 10-Q for first and second quarters of 2002, and its annual report on Form 10-K for the year ended December 31, 2002. See ITEM 14. CONTROLS AND PROCEDURES and Note 2 to AE’s consolidated financial statements for further information.

By October 2002, weaknesses in wholesale energy markets began to materially and adversely affect Allegheny’s liquidity. Rapid deterioration of the energy trading markets in 2002 required Allegheny to continually review its modeling techniques and assumptions regarding the value of energy trading positions. The value of its positions was also adversely affected by decreases in liquidity and volatility in the Western United States energy markets. It was ultimately determined that significant write-downs of such positions were necessary. In October 2002, AE’s and its subsidiaries’ credit ratings were downgraded to below investment grade. (See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information on Allegheny’s credit ratings.) The ability to enter into and maintain transactions within the energy trading markets is heavily dependent on a market participant’s credit rating. As a general matter, market participants rated below investment grade cannot enter into or maintain positions in the energy markets to hedge their physical delivery obligations absent credit support or the posting of collateral. The October 2002 ratings downgrades triggered collateral calls by Allegheny’s trading counterparties. AE Supply’s cash position did not permit the posting of requisite collateral and, in October 2002, AE Supply was in violation of covenants under certain trading contracts. The violations triggered breaches under the terms of AE’s, AE Supply’s, and AGC’s principal credit facilities. AE, AE Supply, and AGC were able to obtain successive temporary waivers to keep facilities in place pending debt restructuring. Weaker than expected operating results and the credit rating downgrades, together with the concerns regarding the energy trading market described above, also rendered it impossible to undertake an anticipated public equity financing by AE.

AE Supply’s access to capital was severely constrained by the fourth quarter of 2002. AE Supply continued to settle its trades as they came due, but needed to be very selective as to its collateral posting. Many counterparties, as a result, exercised their contractual right to terminate their trades with AE Supply, leaving AE Supply’s trading portfolio with unhedged positions. These unhedged positions were substantial and were a source of significant uncertainty regarding Allegheny’s forward cash position and financial results. AE Supply had sought to use the energy trading markets to lock in the long-term profitability of its portfolio of positions. AE Supply’s cash position and credit rating in the fourth quarter of 2002 did not permit it the flexibility to enter into significant new long-term trading arrangements, but rather required it to manage its exposures on a short-term basis. Due to collateral posting obligations that attached to most of AE Supply’s trading positions, and given its credit ratings, the volatility of AE Supply’s cash position has been generally reduced by the removal of trading positions from its portfolio. In 2003, AE has pursued a strategy of terminating or assigning trading positions where practicable.

As described below under —Allegheny’s Response, Allegheny has recently exited the Western United States power markets. In September 2003, Allegheny sold the CDWR contract and hedges associated with those contracts. These related hedges had maturities through 2011. Most of Allegheny’s remaining positions will expire by the end of 2006. The reduction in the average maturity of Allegheny’s trading positions will reduce volatility in Allegheny’s collateral posting obligations and the absolute size of potential collateral posting requirements associated with financial transactions. Terminations of groups of positions with zero value on an aggregate net mark-to-market basis have also been possible from time to time; however, where counterparty credit is below stable investment grade, assignment has been difficult or impracticable.

Allegheny’s liquidity position and financial results, combined with asset writedowns, have made raising capital complex and challenging. Allegheny’s capital raising activities are subject to constraints imposed by the covenants contained in the agreements governing outstanding indebtedness, including the borrowing facilities negotiated in February 2003, and in the indenture entered into in July 2003 in connection with AE’s issuance of convertible trust preferred securities. AE and AE Supply do not currently maintain the minimum equity ratio required as a condition of its key financing authorizations under PUHCA and, as a result, further financings are precluded absent SEC authorization. The process of obtaining required regulatory authorizations or lender consents has caused significant delays and imposed additional costs on asset sales and other capital raising transactions and has jeopardized the ability of Allegheny to enter into certain planned transactions.

The marketplace rules affecting Allegheny also changed markedly in 2002. In January 2002, the Federal Energy Regulatory Commission (FERC) authorized the Distribution Companies and PJM to proceed with

broadening the scope and regional configuration of PJM to include the Distribution Companies, via an arrangement known as PJM West, effective April 1, 2002. With the addition of our service area, PJM’s control area now extends over the states of Delaware, Maryland, and New Jersey, most of Pennsylvania and West Virginia and portions of Ohio and Virginia. The agreements establishing PJM West required us to adopt PJM’s transmission pricing methodology, including PJM’s congestion management system, and expanded PJM’s day-ahead and real-time energy markets to include PJM West. As a result, energy suppliers are now able to reach consumers anywhere within the expanded PJM market at a single transmission rate, instead of paying multiple transmission rates. The formation of PJM West expands AE Supply’s primary market. However, the Distribution Companies may in the future realize reduced revenues as a result of the elimination of transmission seams between Allegheny and PJM and revised congestion pricing mechanisms. Nevertheless, in 2002, and continuing through the end of the transition period established by the FERC, the Distribution Companies will continue to collect lost revenues through transitional mechanisms accepted by the FERC. At the end of the transition period, the reduction in revenues for the Distribution Companies in the aggregate could amount to more than $30 million annually. For a further discussion of the effect that the FERC’s policy has on the Allegheny companies, see —Regulatory Framework Affecting Allegheny—Federal Regulation, below.

Allegheny’s credit ratings and liquidity issues persisted into 2003. Allegheny has not reported interim financial information for the first or second quarter of 2003. Allegheny faces significant challenges in bringing required reporting up-to-date and making timely filings in the future. Internal control issues remain and need to be addressed. In addition, difficult market conditions and the effect of Allegheny’s weakened credit profile have had a continuing substantial adverse effect on 2003 operations, and it is anticipated that consolidated earnings and cash flow results, when reported, will be substantially below the levels indicated in the projections released by AE in February 2003, following its bank refinancing.

In June 2003, AE announced that its common equity ratio (common equity to total capitalization, including short-term debt), for PUHCA purposes, had fallen below the level required under its key SEC financing authorizations. Based upon preliminary 2003 data, it is estimated that AE’s equity ratio is below 28 percent, and the equity ratio at AE Supply is below 20 percent.

As a result, AE and AE Supply have had to, and will continue to be required to, obtain special ad hoc authorizations from the SEC to engage in financings, asset sales, and other activities critical to near-term viability. Absent such authorizations, Allegheny will have very limited flexibility to meet expected liquidity requirements or to address contingencies. The common equity ratio has fallen below its previously projected level due to several factors. First, AE Supply had to take substantial write-downs in connection with recognized reductions in trading position values to reflect then current market conditions and revised valuation techniques and assumptions. Second, further write-downs were triggered by the renegotiation of supply contracts and the cancellation of suspended generation projects. Finally, Allegheny’s financial performance and cash flows in 2003 have been, and continue to be, substantially weaker than earlier projected.

Forward natural gas and power prices increased significantly from the third quarter of 2002 through the second quarter of 2003, resulting in collateral requirements that have exceeded expectations by more than $100 million. In addition, these rising prices caused AE Supply to decide to prepay for approximately $45 million of natural gas and power supplies necessary as a hedge against its power delivery obligations during the summer of 2003. Counterparty terminations of trading contracts left AE Supply short of power during 2003, requiring shortfalls to be satisfied by spot market purchases at times when spot market prices were higher than expected. As a result of these developments, Allegheny’s liquidity continued to come under pressure through the summer of 2003 until many of the trading book restructuring activities discussed below could be implemented.

seek, consistent with regulatory constraints, to manage its business lines as an integrated whole. Implementing this strategy will be a significant challenge, in part, because of the continuing legacy of past transactions that have negatively impacted Allegheny’s operations and financial condition.

Allegheny has taken a number of recent actions to improve its financial condition and reorient its business, which have included:

Allegheny’s senior management was changed substantially in 2003 as Allegheny reoriented its business model and addressed the need to improve its financial condition.

In May 2003, Alan J. Noia retired as Chairman of the Board and Chief Executive Officer. On June 16, 2003, Paul J. Evanson was appointed Chairman of the Board of Directors and President of AE, and Chief Executive Officer of AE, Monongahela, Potomac Edison, West Penn, and AE Supply. Mr. Evanson formerly served as President of Florida Power & Light Company, FPL Group’s principal subsidiary, and as a director of FPL Group since 1995. Mr. Evanson succeeded Interim President and Chief Executive Officer Jay S. Pifer, who assumed this position in May 2003 upon the retirement of Mr. Noia. Mr. Pifer is currently serving as Chief Operating Officer of AE.

On July 7, 2003, Jeffrey D. Serkes was appointed Senior Vice President and Chief Financial Officer of AE and Vice President of Monongahela, Potomac Edison, West Penn, and AE Supply. Prior to his appointment, Mr. Serkes was President of JDS Opportunities, LLC. Before joining JDS Opportunities, Mr. Serkes was employed with IBM, most recently as Vice President, Finance, Sales and Distribution and previously as Vice President and Treasurer. Mr. Serkes succeeded Bruce E. Walenczyk, who retired effective June 1, 2003.

On July 28, 2003, David B. Hertzog was appointed Vice President and General Counsel of AE and Vice President of Monongahela, Potomac Edison, West Penn, and AE Supply. Prior to his appointment, Mr. Hertzog was a partner with Winston & Strawn in its New York office. Mr. Hertzog was a managing partner of Hertzog, Calamari & Gleason for 23 years prior to its merger with Winston & Strawn in 1999. Mr. Hertzog succeeded Thomas K. Henderson, who retired on August 1, 2003.

On August 25, 2003, Joseph H. Richardson was appointed President of Monongahela, Potomac Edison, and West Penn. Prior to his appointment, Mr. Richardson served as President of Global Energy Group, Inc., a company that develops energy efficiency technologies. Prior to that, he spent most of his career with Florida Power Corporation where he was President, Chief Executive Officer, and Chief Operating Officer.

On May 12, 2003, David C. Benson was named Interim Executive Vice President of AE Supply and, on August 1, 2003, Executive Vice President of AE Supply. Mr. Benson previously served as Vice President, Production for AE Supply. Michael P. Morrell, former president of AE Supply, retired on September 1, 2003.

Allegheny completed two key financing transactions in 2003 to improve its liquidity position.

Refinancing Principal Credit Facilities. On February 25, 2003, AE, AE Supply, Monongahela and West Penn entered into agreements (Borrowing Facilities) with various credit providers to refinance and restructure the bulk of their short-term debt. The Borrowing Facilities provided AE Supply with $420 million of immediate liquidity. The Borrowing Facilities also extended short-term debt maturities. AE and AE Supply will be required to make substantial amortization payments on the Borrowing Facility indebtedness in the fourth quarter of 2003 and in 2004.

Private Placement. On July 24, 2003, Allegheny raised $291 million ($275 million after deducting various fees and placement agents’ commissions) from the issuance to a special purpose finance subsidiary of AE of units comprised of $300 million principal amount of 11⁷/8% Notes due 2008 and warrants for the purchase of up to 25 million shares of AE’s common stock, exercisable at $12 per share. The warrants are mandatorily exercisable if AE’s common stock price equals or exceeds $15 per share over a specified averaging period occurring after June 15, 2006. The warrants are attached to the notes and may be exercised only through the tender of the notes. The finance subsidiary obtained the proceeds required to purchase the units by issuing $300 million total liquidation amount of its 11⁷/8% Mandatorily-Convertible Trust Preferred Securities to investors in a private placement. The preferred securities entitle the holders to distributions on a corresponding principal amount of notes and to direct the exercise of warrants attached to the notes in order to effect the conversion of the preferred securities into AE common stock. AE guarantees the finance subsidiary’s payment obligations on the preferred securities. In accordance with generally accepted accounting principles, Allegheny’s consolidated balance sheet will reflect the notes as long-term debt. The notes, and AE’s guarantee of the preferred securities, are subordinated only to indebtedness arising under the agreements governing certain of Allegheny’s indebtedness under the Borrowing Facilities.

Allegheny worked through 2003 to accomplish AE Supply’s effective exit from the Western United States power markets. Its positions based in the Western United States had been a substantial source of earnings and cash flow volatility and risk, and trading in these markets does not fit with Allegheny’s current strategy.

Renegotiation and Sale of CDWR Contract. In June 2003, AE Supply entered into a settlement agreement with the State of California to resolve the state’s litigation regarding its power supply contract with the CDWR. The terms of the settlement reduced the volume of power to be delivered from 2005-2011 and reduced the sale price of off-peak power to be delivered from 2004-2011, which in turn substantially reduced the value of the contract. On September 15, 2003, Allegheny closed the sale of the contract and associated hedge transactions, to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc., for approximately $354 million. Allegheny has applied $214 million of the sale proceeds to required payments under agreements entered into to terminate tolling agreements with Williams Energy Marketing and Trading Company (Williams) and Las Vegas Cogeneration II (LV Cogen), a unit of Black Hills Corporation, as described below. Allegheny will apply an additional $28 million of the proceeds to make required payments in March and September of 2004 under the agreement with Williams. Approximately $26 million will be held in a pledged account for the benefit of AE Supply’s creditors. This arrangement is intended to enhance AE Supply’s ability to refinance certain secured borrowings. Approximately $71 million of the sale proceeds was placed in escrow for the benefit of J. Aron & Company, pending Allegheny’s fulfillment of certain post-closing requirements. When the escrowed funds are released, approximately $50 million will be added to the pledged account and AE Supply will receive the balance. The remaining $15 million of sale proceeds will be used to partially offset certain of the hedges related to the CDWR contract and to pay fees and expenses associated with the transaction.

Agreement to Terminate Williams Toll. In July 2003, AE Supply entered into a conditional agreement with Williams to terminate its 1,000 MW tolling agreement with Williams. Under the agreement, AE Supply made an initial payment to Williams of approximately $2.4 million to satisfy certain amounts under a related hedge agreement. Allegheny made a $100 million payment to Williams after the close of the sale of the CDWR contract. Allegheny will make two payments of $14 million to Williams in March and September of 2004. The tolling agreement will terminate when the final $14 million payment is made.

Termination of LV Cogen Toll. In mid-September 2003, AE Supply terminated its 222 MW tolling agreement with LV Cogen. Allegheny made a $114 million termination payment to LV Cogen after the closing of the sale of the CDWR contract.

After completing these major transactions, Allegheny’s remaining trading exposures to the Western market will consist of several shorter-term trades that hedged the CDWR contract and several long-term hedges of the LV Cogen tolling agreement. Allegheny is seeking to unwind these remaining positions, totaling 400,000 MWh of net purchases through the end of 2003, and one million MWh of net purchases from 2004 through 2012.

Adoption of Asset-Based Trading Strategy. AE Supply is reorienting its trading operations from high-volume financial trading in national markets to asset optimization and hedging within its region. AE Supply is implementing this rebalancing over time as its liquidity allows. Effectively exiting the Western power markets, together with unwinding substantial non-core trading positions, has enabled AE Supply to reduce long-term trading-related cash outflows and collateral obligations. In the future, AE Supply will seek to concentrate its efforts in PJM, the Midwest, and Mid-Atlantic markets where it has a physical presence and greater market knowledge. Ultimately, AE Supply intends to conduct asset optimization and hedging activities with the primary objective of locking in cash flows associated with AE Supply’s portfolio of core physical generating and load positions.

Relocation of Trading Operations. AE Supply moved its energy marketing operations from New York to Monroeville, Pennsylvania on May 5, 2003 and has reduced its trading operations. This transition will result in ongoing cost savings and improve integration with AE Supply’s generation activity. The reduced staffing levels are intended to reflect the newly revised focus of the trading function. Management believes that both trading and marketing and generation operations can be enhanced by locating trading personnel closer to personnel managing AE Supply’s generating assets. Personnel involved in the separate functions can be cross-trained and will be better positioned to enhance the relationship between the two functions. (See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding charges incurred in connection with relocating the trading operations.)

In 2002, Allegheny announced that it was considering selling assets as part of an overall strategy to address its liquidity requirements. Allegheny has achieved the sale of its most significant assets with a nexus to the Western United States. Allegheny has also closed the sale of its interest in the Conemaugh Generating Station, as described below. Allegheny continues to consider the sale of additional assets, especially non-core assets.

Land Sales. Effective February 14, 2002, West Penn, through its subsidiary, West Virginia Power and Transmission Company, sold 12,000 acres of land in Canaan Valley, West Virginia, to the U.S. Fish & Wildlife Service for $16 million. Effective December 18, 2002, it also sold a 2,468-acre tract of land for $6.9 million and made a charitable contribution of a 740 acre tract in Canaan Valley, West Virginia, to Canaan Valley Institute.

Fellon-McCord and Alliance Energy Services, LLC. Effective December 31, 2002, AE sold Fellon-McCord, its natural gas and electricity consulting and management services firm, and Alliance Energy Services, LLC (Alliance Energy Services), a provider of natural gas supply and transportation services, to Constellation Energy Group for approximately $21.8 million.

Conemaugh Generating Station. On June 27, 2003, AE Supply completed the sale of its 83-MW share of the coal-fired Conemaugh Generating Station, located near Johnstown, Pennsylvania, to a subsidiary of UGI Corporation, (UGI), for approximately $46.3 million, which does not include a contingent amount of $5 million. This contingent amount could be received in full, in part, or not at all, depending upon AE Supply’s performance of certain post-closing obligations.

Allegheny has taken several actions to align its operations with its strategy and reduce its cost structure.

Termination of Non-Core Construction Activity. In 2002, AE Supply ceased construction and planning of various merchant generation projects to attempt to conserve cash and other resources and focus its resources on its core generating assets. (See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding charges incurred for the termination of generating projects.)

Restructuring of Operations. In July 2002, Allegheny announced a restructuring plan intended to strengthen its financial performance by, among other things, reducing its workforce. Allegheny has achieved workforce reductions of more than 10 percent through a voluntary Early Retirement Option (ERO) program and selected staff reductions. In 2002, approximately 600 eligible employees accepted the ERO program resulting in a charge of $82.6 million, before income taxes. Allegheny has essentially completed these planned workforce reductions. Allegheny will continue to take actions intended to reduce costs and improve productivity in all of its operations.

Suspension of Dividend. The Board of Directors of AE determined not to declare a dividend on AE’s common stock for the fourth quarter of 2002. Covenants contained in Allegheny’s new Borrowing Facilities entered into in February 2003, and in the indenture entered into in connection with the convertible trust preferred securities issuance in July 2003, as well as regulatory limitations under PUHCA, are expected to preclude AE from declaring or paying cash dividends for the foreseeable future.

Elimination of Preemptive Rights. On March 14, 2003, AE’s common stockholders approved an amendment to AE’s articles of incorporation eliminating common stockholders’ preemptive rights. The elimination of preemptive rights removed an obstacle to AE’s ability to privately place equity or convertible securities.

Comprehensive Accounting Review. Commencing in the third quarter of 2002, Allegheny undertook a comprehensive and extended review of its financial information and internal controls and procedures. This review included continuous efforts by Allegheny’s management and directors and extensive involvement of independent auditors and other outside professional service firms. Allegheny continues to address its controls environment and reporting procedures, as well as its SEC filing and other outstanding reporting obligations. See ITEM 14. CONTROLS AND PROCEDURES and Note 2 to AE’s consolidated financial statements for a detailed discussion.

In addition to historical information, this report contains a number of forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Words such as anticipate, expect, project, intend, plan, believe, and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. These include statements with respect to:

Forward-looking statements involve estimates, expectations, and projections and, as a result, are subject to risks and uncertainties. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

Factors that could cause actual results to differ materially include, among others, the following:

We are subject to a variety of significant risks in addition to the matters set forth under “Special Note Regarding Forward-Looking Statements” above. Risks applicable to us include:

Our susceptibility to certain risks could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile.

Because of AE Supply’s credit rating, it generally must post collateral to trading counterparties to the extent that its net obligations under energy trading transactions with a counterparty are in favor of the counterparty relative to the market. Likewise, many counterparties are required to post collateral in favor of AE Supply. However, because of AE Supply’s credit rating, AE Supply must place collateral received in a custodial account. Thus, this collateral cannot be used to post to other counterparties. AE’s and AE Supply’s liquidity positions have limited AE Supply’s ability to enter into transactions on a timely basis to hedge its open positions. As a result, it has had to reactively manage its open positions on a short-term basis in the volatile spot market. In addition, counterparties have terminated certain trading agreements with AE Supply that would have permitted AE Supply to maintain hedges against power delivery obligations or fuel purchase requirements. These circumstances leave AE and AE Supply highly vulnerable to shifts in market prices for energy and other commodities until such time as AE Supply is able to retire or hedge its open positions. AE Supply must also satisfy short positions in the volatile spot market, which has been more expensive than projected. As a result of these factors, our cash position and results of operations in recent periods have been subject to commodity market volatility to a greater extent than prior to the third quarter of 2002. If we are unable to meet ongoing collateral posting requirements or other cash delivery obligations, we may default on energy trading contracts, which may trigger defaults under our credit agreements and other contracts. If our cash and cash equivalent assets are not sufficient, after application to our cash delivery obligations under our commodity contract positions to meet our debt service obligations, we could default under our debt facilities.

We face significant obstacles to implementing our strategy of rebalancing our market positions to hedge our physical power supply commitments and resource requirements.

We are seeking to unwind commodity contracts that are not necessary to hedge our physical delivery obligations, with a view to refocusing AE Supply’s trading and marketing activities around core physical assets. We are facing substantial obstacles to implementing this strategy. Our lack of liquidity has rendered it difficult for us to eliminate unnecessary or cash draining positions. Our current credit rating and lack of liquidity have also led to reluctance on the part of counterparties to increase exposure to us, which has in turn complicated efforts to establish new hedged positions. Where a counterparty’s credit is below investment grade, assignment of our positions to third parties may be impracticable. Overall, market liquidity, particularly in long-term electricity and natural gas markets, has significantly declined over the past two years. Absent a return to more liquid levels, it may not be possible for AE Supply to hedge all of its open trading positions and retire unnecessary positions.

Our credit position has also rendered it difficult for us to hedge our power supply obligations and fuel requirements. Some trading counterparties have terminated trades with us that we entered into to hedge such obligations. In the absence of effective hedges for these purposes, we must satisfy power and fuel shortfalls in the spot markets, which are volatile and have been more costly than expected.

Even a balanced, asset-based portfolio would render us vulnerable to risks. Our risk management, wholesale marketing, fuel procurement and energy trading activities, including our decisions to enter into power sales agreements, rely on models that depend on judgments and assumptions regarding factors such as the future market prices and demand for electricity and other energy-related commodities. Even when our policies and procedures are followed and decisions are made based on these models, there may, nevertheless, be an adverse effect on our financial position and results of operations, if the judgments and assumptions underlying those models prove to be inaccurate.

Our ability to use hedging instruments to protect us from price and demand volatility will only be effective to the extent that we can rely on the performance of our trading counterparties. Market participant credit quality has been a pervasive concern in the energy industry for some time. We have been and continue to be exposed to counterparties that may not be willing or able to meet their contractual obligations.

AE Supply must obtain significant additional financing from outside sources in the near future.

AE Supply’s Borrowing Facilities (as defined below) require AE Supply to make a cash principal payment of $250 million by the end of December 2003, $200 million by the end of September 2004, and $150 million by the end of December 2004. AE Supply expects to make the December 2003 payment. For the remaining payment schedule, if AE Supply cannot raise the total principal amount in a timely manner, it would be in default under the Borrowing Facilities, which would also cause us to be in default under other contracts, including the indenture entered into in connection with our July 2003 issuance of convertible trust preferred securities. We are exploring refinancing amounts due under our Borrowing Facilities. However, there cannot be any assurance that any refinancing will actually occur.

There is a risk that AE Supply may not be able to obtain required financing in a timely manner. Aspects of the current situation that render obtaining financing difficult include:

As part of our plan to restore our liquidity, we may engage in further asset sales; however, market conditions and other factors limit the availability of this strategy.

We may seek to sell additional assets or businesses in order to improve our liquidity. Sale prices for energy assets and businesses have been and could remain weak due to prevailing conditions in the market for such assets and businesses. Asset sales under such conditions could result in the incurrence of substantial losses. The current state of the energy industry has resulted in an increased number of sellers of generating assets and has limited the number of potential buyers for generating assets. Buyers may also find it difficult to obtain financing to purchase salable assets.

Several factors specific to Allegheny have rendered asset sales particularly challenging. Allegheny is subject to constraints under PUHCA and in the covenants under the Borrowing Facilities, which have imposed delays and structuring complications on asset sale transactions. Potential buyers may be reluctant to enter into agreements to purchase assets from us if they believe that required consents and approvals will result in inordinate delays or uncertainties in the transaction process.

Covenants contained in our principal financing agreements restrict our operating, financing, and investing activities.

In February and March 2003, we entered into Borrowing Facilities in connection with the refinancing of the bulk of AE and AE Supply’s short-term indebtedness. The Borrowing Facilities include:

We also restructured $380 million of indebtedness incurred in connection with our previously-planned St. Joseph, Indiana project. Debt associated with the St. Joseph operating lease, in the form of A-Notes, was restructured and assumed by AE Supply. This debt is secured by substantially all the assets of AE Supply, except its new facility in Springdale, Pennsylvania. The secured portion of this debt bears an interest rate of 10.25 percent, and the unsecured portion bears interest at 13.0 percent. This debt matures in November 2007.

The Borrowing Facilities also included a $25 million unsecured facility at AE, which was retired in July 2003.

Because AE Supply was unable to secure all of the Borrowing Facilities before the end of July 2003, the interest rates applicable to the amounts not secured increased retroactively to February 2003 to a margin of 10.5 percent over the applicable LIBOR-based rate or designated money center bank’s base rate for the unsecured portion of the $987.7 million and $270.1 million facilities, and to an interest rate of 13.0 percent for the unsecured portion of the $380.0 million A-Note debt. The total amounts unsecured under the $987.7 million facility, $270.1 million facility and A-Note debt are approximately $94.3 million, $175.8 million and $36.3 million, respectively.

In July 2003, AE entered into an indenture in connection with the issuance of 300,000 convertible trust preferred securities. AE issued $300 million principal amount of notes under the indenture. The notes carry a coupon of 11⁷/8 percent and mature on June 15, 2008. The notes are convertible into up to 25 million shares of AE common stock, subject to anti-dilution adjustments.

The Borrowing Facilities and the indenture entered into in connection with the issuance of the convertible preferred securities contain restrictive covenants that limit our ability to:

AE Supply has pledged its assets to secure its obligations under the Borrowing Facilities. The terms of the Borrowing Facilities will limit our ability to make strategic decisions. Covenant restrictions limit our ability to access capital markets without using the proceeds to reduce the outstanding principal of the Borrowing Facilities. Our cash payment obligations and covenant restrictions will prevent us from pursuing a growth or acquisition strategy for several years. These obligations could also limit our ability to make capital expenditures, both for added capacity and existing facilities.

AE Supply borrowed $2,057.8 million under the Borrowing Facilities and restructured A-Note debt. Of that amount, $1,927.2 million is secured by either AE Supply’s new generating facility in Springdale, Pennsylvania, or substantially all of AE Supply’s other assets. The terms of the Borrowing Facilities will render it difficult for AE Supply to borrow additional funds.

Covenants contained in our principal financing agreements impose covenants relating to our financial performance and financial reporting.

AE is required to meet certain financial tests, as defined in the Borrowing Facilities, including:

Effective July 22, 2003, Allegheny was granted waivers from compliance with all of the above financial tests for the first and second quarters of 2003. Effective August 22, 2003, Allegheny received additional waivers of the financial tests for the third quarter of 2003. It is uncertain as to when AE will be able to meet its financial tests.

AE Supply must meet certain financial tests, as defined under the Borrowing Facilities, including:

Effective July 22, 2003, AE Supply was granted waivers from compliance with all of the above financial tests for the first and second quarters of 2003. Effective August 22, 2003, AE Supply received additional waivers of the financial tests for the third quarter of 2003. It is uncertain as to when AE Supply will be able to meet these tests.

AE and AE Supply and certain of their subsidiaries, including Monongahela and AGC, are also required to meet annual and quarterly reporting requirements under the terms of borrowing arrangements, including the Borrowing Facilities. AE and AE Supply have obtained waivers under the Borrowing Facilities from compliance with these covenants through September 2003 with respect to its 2002 annual reporting requirements and temporary waivers with respect to certain quarterly reporting requirements. Allegheny has several other debt agreements that require filings of quarterly and annual reports under the Securities Exchange Act of 1934. These debt agreements generally also require the obligor to file compliance certificates with the trustees under the agreements indicating that the obligor is in compliance with all of the covenants. On April 30, 2003, Allegheny provided certificates indicating that it was not in compliance with certain reporting obligations under certain first mortgage bonds and debentures. These covenant breaches are deemed defaults of the related indebtedness, as

well as defaults of indebtedness subject to cross-acceleration with such first mortgage bonds and debentures (including certain pollution control bonds and other indebtedness), for financial reporting purposes. To date, the debt holders have not provided Allegheny with any notices of default under the agreements. Such notices, if received, would allow Allegheny 30-60 days to cure noncompliance before the debt holders could accelerate the due date of the related debt. See Note 3 to the consolidated financial statements for further information regarding our compliance status under agreements governing our indebtedness.

The Borrowing Facilities require us to pay interest calculated at a spread over LIBOR or another designated rate, both variable rates. If interest rates rise, we will be required to meet higher debt service obligations. If our operational cash flows do not increase proportionately with interest rate increases, we may have difficulty meeting our debt service obligations.

Required payments on our substantial indebtedness will absorb a large portion of our cash flows and will limit our ability to raise capital for purposes other than debt repayment.

The substantial level of our indebtedness will require us to apply much of our cash flow to our principal and interest obligations. Our operations and other activities must be directed to ensuring that our cash position will be sufficient to satisfy these obligations in a timely manner. Under the terms of the Borrowing Facilities, we will be required to apply the proceeds of asset sales and securities issuances to repay the Borrowing Facilities. We must apply to our debt as follows:

The terms of the indenture entered into by AE in connection with the issuance of convertible trust preferred securities contains a covenant that requires AE and its regulated utility subsidiaries to apply the proceeds of certain asset sales to repay indebtedness under the indenture. This covenant would become effective in the event that the Borrowing Facilities were terminated, provided that AE had not entered into an analogous covenant under a credit facility entered into to refinance the Borrowing Facilities.

In connection with regulations governing the transition to market competition, Monongahela (with respect to its Ohio customers), Potomac Edison, and West Penn are required to provide electricity to retail customers who do not choose an alternate electricity generation supplier and to those who return to utility service from alternate suppliers. During the transition periods in the states in which it serves, each Distribution Company satisfies its provider-of-last-resort (PLR) obligation by sourcing power from AE Supply under a long-term power sales agreement. Our lack of liquidity may also render it difficult for us to derive the maximum value otherwise available in the market of energy produced above our PLR obligations, thereby reducing revenues realizable from operations.

Our liquidity position and resultant credit rating downgrades have adversely affected our ability to enter into long-term executory contracts, generally due to collateral posting requirements. This has made it difficult for us to enter into long-term supply and other arrangements. With fewer long-term supply contracts, we will have greater exposure to short-term market price volatility and availability constraints.

Provisions of Maryland law and PUHCA, and the terms of our constituent documents and of contracts we have entered into could deter unsolicited third-party acquisition offers and limit outside investment in us.

Provisions of AE’s bylaws and anti-takeover provisions of Maryland law could make it difficult for an unsolicited third party to acquire control of AE. The anti-takeover provisions of Maryland law discourage control share acquisitions, include fair price and freeze-out provisions, and endorse stockholder rights plans. As permitted by Maryland law, AE’s bylaws provide for a classified board, with board members serving staggered three-year terms. AESC has executed change in control agreements with key officers that contain provisions that may make it more expensive to effect a change in control and replace incumbent management. While the purpose of the staggered board is to prevent abusive takeover tactics and to protect stockholders’ investments in AE, it could have the effect of preventing or making more difficult an acquisition or change in control that shareholders, in their judgment, might have favored. Further, our subsidiaries are party to various contracts which are terminable upon an unsolicited or other change of control. Provisions of PUHCA may also require that an investor or acquiror obtain approval prior to acquiring a significant stake in us.

AE has a stockholder rights plan, which entitles existing stockholders to purchase shares of common stock at a substantial discount in the event of an acquisition of 15 percent or more of our outstanding common stock or an unsolicited tender offer for those shares. The Board of Directors of AE has voted to redeem the stockholder rights under the plan, but this redemption may not take place before required authorizations are obtained, including SEC authorization under PUHCA.

Covenants contained in the Borrowing Facilities, terms of the indenture entered into in connection with the issuance of convertible trust preferred securities, and regulatory limitations under PUHCA will preclude AE from paying dividends on its common stock for the foreseeable future. Certain institutions and other investors may not or do not purchase non-dividend-paying equity securities.

We may engage in further asset sales, which would expose us to attendant risks and liabilities.

We are exploring the option of selling selected assets, especially non-core assets. Risks commonly encountered in connection with asset sale activity include:

Adverse market conditions could reduce potential asset sale proceeds and could require that we link load commitments to generating assets as a buyer’s condition to purchasing our salable assets, thus depriving us of a long-term source of cash flow. Further sales of generating assets would also reduce AE Supply’s total generating capacity, which could compromise our ability to meet load requirements of the Distribution Companies or capitalize on future increases in commodity prices.

We are engaging in ongoing restructuring and cost-cutting efforts, which expose us to attendant risks.

In July 2002, as part of our cost-cutting efforts, we announced our intent to reduce our workforce of approximately 6,000 by approximately 10 percent. We achieved workforce reductions of approximately 10 percent through a voluntary ERO program, and selected staff reductions. The ERO program offered enhanced pension and medical benefits and required eligible employees to make an election. In 2002, we incurred a non-cash charge of $82.6 million before income taxes in connection with this program. We also offered a Staffing Reduction Separation Program (SRSP) for employees whose positions are being eliminated as part of the workforce reductions. We recorded a charge of $25.0 million related to the approximately 80 employees whose positions have been or are being eliminated. These workforce reductions are essentially complete. The reorganization of AE Supply’s energy trading division included the relocation of the trading operations and resulted in a charge of approximately $21.0 million, before income taxes, related to costs associated with the relocation. We may commence further efforts of this nature. In pursuing this strategy, we incur risks commonly encountered in connection with such a strategy, including:

In addition, we have sought to efficiently budget our maintenance resources for our generating and delivery facilities. If we underestimate required maintenance expenditures, we may run the risk of incurring an increased frequency of unplanned forced outages, which could ultimately lead to higher maintenance expenditures, increased operation at higher cost of previously marginal sources of in-house generation, or requiring that we purchase power from third parties to meet our supply obligations, and we may experience T&D reliability problems such as recurring outages, more significant effects from severe storms, and blackout situations.

Our internal controls and procedures have been substantially deficient, and we remain in the process of correcting internal control deficiencies.

In August 2002, Allegheny and its independent auditors recognized that Allegheny’s internal controls and procedures had material weaknesses. These material weaknesses led in part to the delay in the production of our audited financial statements for 2002, which rendered us unable to comply with the SEC’s requirements with respect to the timely filing of our 2002 annual report. We have not released quarterly financial statements, or filed required quarterly reports with the SEC, for the third quarter of 2002 or for the first or second quarters of 2003. We will restate our financial statements for the first and second quarters of 2002. Our independent auditors have advised us of material weaknesses noted during their audit of our 2002 financial statements. For further information concerning Allegheny’s internal controls and procedures, see ITEM 14. CONTROLS AND PROCEDURES and Note 2 to AE’s consolidated financial statements.

If we cannot rectify these material weaknesses through remedial measures and improvements to our systems and procedures, management may encounter difficulties in timely assessing business performance and identifying incipient strategic and oversight issues. Where adequate automated control systems are not in place, we will need to devote personnel resources to account verification and reconciliation. Management is currently focused on remedying internal control deficiencies, and this focus will require management from time to time to devote its attention away from other planning, oversight, and performance functions.

We have applied substantial resources at all relevant managerial levels for approximately one year toward the task of improving our internal control environment. These efforts, in which we have involved several external professional service firms, continue. We cannot provide assurances as to the timing of the completion of these efforts or estimates of the prospective costs of these efforts, either in dollar terms or in the form of management attention.

We are substantially changing our business model and other aspects of our business, which subjects us to risks and uncertainties.

Commencing in the second half of 2002 and continuing through 2003, we have reassessed our position within the energy industry, the business environment, and our relative strengths and weaknesses. In response, we have implemented substantial changes to our business model and other aspects of our business. For example, we have reoriented our trading operations, reduced the size of our workforce, sold assets, exited markets and engaged in significant financing transactions, among other changes. We have also made substantial changes to our senior management. Our circumstances in 2002 represented a substantial transformation from our historical integrated utility business model. Current and previous changes in our business model were prompted by internal decision making and by the changing regulatory and market environments.

We are in a state of transition, and additional changes to our business are being and will be, from time to time, considered as management seeks to restore our liquidity and place us on a sound strategic footing. These transitions have been, and will be, unavoidably disruptive to our established organizational culture and systems. In addition, consideration and planning of strategic changes focus management attention away from day-to-day execution. There can be no assurance that we will ultimately be successful in transitioning our business model.

The terms of AE Supply’s power sale agreements with the Distribution Companies could require AE Supply to sell power below its costs or prevailing market prices or require the Distribution Companies to purchase power at a price above which they can sell power.

In connection with regulations governing the transition to market competition, West Penn, Monongahela with respect to its Ohio customers, and Potomac Edison (together, the PLR Companies) are required to provide electricity at capped rates to retail customers who do not choose an alternate electricity generation supplier and to those who return to utility service from alternate suppliers. The PLR Companies’ capped rates may be below current market rates through the transition periods. We have structured our operations so that AE Supply owns the generating assets that were previously owned by the PLR Companies. The capped rates reflect the historical costs of operating and maintaining AE Supply’s generating assets. The PLR Companies satisfy their PLR obligations by sourcing power from AE Supply under long-term power sales agreements. Those agreements provide for the supply of a significant portion of the PLR Companies’ energy needs at the mandated capped rates with a specified remaining portion priced on the basis of market prices. The amount of supply priced at market rates increases over each contract term. Power to be supplied by AE Supply under these agreements amounts to the majority of AE Supply’s normal operating capacity. For a detailed discussion of retail restructuring under state laws, see —Fuel, Power and Resource Supply—The Delivery and Services Segment; and —Regulatory Framework Affecting Allegheny—State Legislation and Regulatory Developments, below.

These power supply agreements present risks for both AE Supply and the Distribution Companies. At times, AE Supply may not be able to earn as much as it otherwise could by selling power otherwise priced at capped rates into competitive wholesale markets. Conversely, the PLR Companies may at times pay market prices for a portion of their supply that exceed the amount they can charge retail customers for the power. Also, the demand for power required to meet the PLR contract obligations could exceed AE Supply’s available generation capacity, which may require AE Supply to buy power at prices that are higher than the sale price in the PLR contracts. Although AE Supply believes it currently owns or controls sufficient capacity to meet aggregate PLR contract demand, there may intermittently occur periods of peak demand that exceed AE Supply’s available capacity. These periods of peak demand often occur when the market price for power is very high. A shortage of available capacity could be further exacerbated by sales of AE Supply’s generating assets used to hedge those contractual obligations.

Should AE Supply’s cost of generation exceed the amounts to which it is entitled under the PLR contracts, for example, due to fuel price increases and increased environmental compliance costs, AE Supply would have to absorb the difference, absent regulatory relief. Similarly, if AE Supply is required to purchase power to meet the PLR obligations, it may not receive its marginal costs from the Distribution Companies. Even if AE Supply can charge the Distribution Companies prices reflecting higher market prices, those companies might not be able to pass the costs on to their retail customers while state retail rate freezes remain in effect. For a general discussion of market risks, see—Regulatory Framework Affecting Allegheny—State Legislation and Regulatory Developments, below.

Our business faces a number of risks that are common to the electric utility industry. Electrical power generation is generally a seasonal business. In many parts of the country, demand for electricity peaks during the hot summer months, with market prices also peaking at that time. In other areas, electricity demand peaks during the winter months. During periods of peak demand, the capacity of our generating facilities may be inadequate. Also, our annual results may depend disproportionately on our performance during the winter and summer. Adverse weather conditions in 2001 and 2002 pressured our operating results in those years.

Energy companies are subject to adverse publicity, which may render us vulnerable to negative regulatory and litigation outcomes.

The energy sector has been among the sectors of the economy that have been the subject of recent highly publicized allegations of misconduct. Adverse publicity of this nature may render legislatures, regulatory authorities, and tribunals less likely to view energy companies such as Allegheny in a favorable light and may cause us to be susceptible to adverse outcomes with respect to decisions by such bodies. The power outages that affected the Northeast and Midwest United States in August 2003 could exacerbate negative sentiment regarding the energy industry.

We are subject to risks related to the termination of competition transition periods.

AE Supply’s PLR contracts last through the transition periods in each of the affected states. As transition periods expire, generally, at varying periods over the next five years, AE Supply may not be able to enter into similar arrangements due to changes in wholesale commodity prices and/or AE Supply’s liquidity constraints. This would result in future earnings and cash flow volatility for AE Supply.

As the end of the transition periods draw closer in some states, consumer advocates and, in some cases, regulators have expressed concerns regarding consumers’ exposure to market conditions. Their concerns are based on the belief that competitive retail markets are not developing as expected, and customers will pay higher rates. Regulators or lawmakers could seek to address these concerns by extending the period during which the Distribution Companies are subject to capped rates for the provision of default service, which poses a risk to the Distribution Companies should the price paid for procuring default service after the originally established transition periods end exceed the capped rate during any extension. The Distribution Companies are seeking to identify opportunities to enhance market development and minimize consumers’ concerns. In Maryland and Ohio, these efforts have resulted in a plan to address post-transition default service through a competitive bidding process, which has been approved by the Maryland Public Service Commission (Maryland PSC). A similar plan has been filed by the Distribution Companies in Ohio, which is pending approval by the Public Utilities Commission of Ohio (PUCO). The Distribution Companies are also participating in state Commission-sponsored working groups in Pennsylvania and Virginia to develop a process for post-transition default service. For further discussion of these issues, see—Regulatory Framework Affecting Allegheny—State Legislation and Regulatory Developments, below.

We are regulated under PUHCA, which constrains our ability to engage in financing transactions and asset sales and limits subsidiary dividends.

All of the Allegheny companies are subject to regulation under PUHCA. PUHCA limits the dividends that our subsidiaries may pay to us from undistributed surplus. In addition, PUHCA requires that we obtain prior approval from the SEC in order to raise financing, purchase or sell utility assets, or merge or consolidate with other companies. These constraints could impede our ability to obtain financing in a timely manner, to obtain financing on favorable terms, or to pursue other business opportunities. PUHCA also limits our range of business operations and ability to affiliate with other public utilities, such as by means of merger or acquisition.

Shifting federal and state regulatory policies impose risks on our operating and capital structure.

Regarding provision of power at wholesale and retail levels, respectively, the Allegheny companies are regulated by both the FERC and state public service commissions. As a result, we may be subject to conflicting regulatory policies that may adversely affect our ability to participate fully in competitive power markets. Moreover, these regulatory policies are continuing to evolve as a result of various legislative and regulatory initiatives regarding deregulation, regulation, or restructuring of the energy industry, including deregulation of

the production and sales of electricity. We may also see additional regulatory action taken by state or federal regulators as a result of the August 14, 2003 blackout. Any such new requirements could lead to increased operating expenses and capital expenditures, which cannot be predicted at this time.

Recently, a number of states have moved away from electricity choice at the retail level by delaying the implementation of retail competition or rejecting it outright. Some states, including Virginia, that have retail competition are informally contemplating re-regulating retail markets. However, we cannot predict to what extent these efforts will be successful, nor can we predict whether or to what extent they will be duplicated in other states. Thus, one of the most significant risks we face is choosing the correct business strategy to respond to these evolving policies. Allegheny believes that the previously approved transfer of certain generating assets to AE Supply, which is a FERC-regulated company, as well as Allegheny’s participation in PJM West, establishes significant impediments to state re-regulation of AE Supply’s generation. For a further discussion, see —Regulatory Framework Affecting Allegheny—Federal Regulation.

Delays, discontinuations, or reversals of electricity market restructurings in the markets in which we operate, or may operate in the future, could have a material adverse effect on our results of operations and financial condition. For example, the Virginia General Assembly enacted legislation in 2003 precluding incumbent electric utility companies such as Potomac Edison from transferring ownership or control of, or responsibility to operate, any portion of a transmission system located in Virginia prior to July 1, 2004. The effect on Potomac Edison, which has already joined PJM, is unclear. However, the legislation is expected to slow the entry of American Electric Power (AEP) and Dominion Virginia Power into PJM, which will hinder the expansion of the PJM market. At a minimum, Virginia’s actions (and similar actions by other states) raise uncertainty concerning the continued development of competitive power markets. Given Allegheny’s multi-state operations and asset base, re-regulation of restructured obligations could prove intricate and time consuming and could lead to complications within Allegheny’s capital structure.

Regulatorily-mandated restructuring may increase our costs by preventing us from obtaining the full benefits of integrated utility operations.

Changes to our corporate organization to comply with new FERC requirements could increase our administrative costs. The success of our business depends, in part, on the economic efficiencies of integrated and coordinated utility operations among our electric transmission, distribution, wholesale marketing, and retail service businesses. We have historically received benefits from operating in a vertically integrated manner, for example, by sharing administrative services and personnel among our businesses. We are regulated by the FERC, which has adopted rules that require electric utilities to separate electric transmission from wholesale marketing activities. The FERC requires employees with operational responsibility for transmission and reliability services to function independently from operating employees engaged in wholesale and unbundled retail generation service marketing activities. The FERC currently permits senior officers and directors to have ultimate decision-making authority for both electric transmission and wholesale marketing businesses. The FERC has, however, proposed to require transmission operating employees to function independently. If this proposal is implemented, we could be required to maintain duplicative management and administrative services.

We may be unable to take advantage of important financial incentives offered by regulators.

Regulatory agencies sometimes provide utilities financial incentives to engage in favored activities and transactions. For example, the FERC recently issued a proposed policy statement to provide financial incentives to utilities for the construction of new transmission facilities or to transfer control over their transmission systems to independent entities such as RTOs. Although we believe that the Distribution Companies’ decision to transfer control over their transmission systems to PJM effective April 1, 2002 makes them eligible for the financial incentives the FERC is considering, we cannot predict whether they will actually receive these incentives or other incentives that may become available. Moreover, if we do receive such incentives, they may not be fully recoverable due to state retail rate freezes, or other factors.

We may realize reduced margins on our transmission operations relative to historical results due to our participation in PJM.

In order to comply with the FERC requirements designed to open access to transmission assets, we turned over functional control of our transmission facilities to PJM, via the PJM West arrangement, on April 1, 2002. Our historical transmission margins exceeded the margins we would realize if we derived transmission facility revenue solely from the base open access tariff rates that PJM charges. We have obtained the FERC’s approval to collect surcharges to recover the difference in the near term, but it is possible that we may not fully recover our authorized surcharges for the duration of the transition period. For a further discussion of the financial impact of our participation in PJM, see—Regulatory Framework Affecting Allegheny—Federal Legislation, Competition, and RTOs, below.

The FERC’s efforts to create and expand large Regional Transmission Organizations (RTOs) provide both risks and opportunities for our business.

The FERC has strongly encouraged public utilities to join large RTOs like PJM and has encouraged these entities to expand and to reduce or eliminate barriers to the trade of electricity with other RTOs. As part of this effort, the FERC has favored the elimination of charges for transmission service through, or out of, an RTO, with the cost for service paid instead by customers in the RTO where the power is consumed. The purpose of this policy is to promote generation competition within and between RTOs. There can be no assurance, however, that the trend of regionalizing power distribution across larger geographic areas will continue. There has been an ongoing debate regarding whether RTOs improve or compromise grid reliability. The power outages that affected the Northeast and Midwest in August 2003 have been cited by both sides in that debate.

The continued expansion of PJM presents the Distribution Companies with significant risks and opportunities. Incorporating new utilities like American Electric Power Service Corporation, Dayton Power and Light Company, and Commonwealth Edison Company (together, the New PJM Companies) into PJM may reduce the cost of transmission by eliminating the need to pay transmission charges to multiple utilities. Harmonizing scheduling practices and other tariff terms and conditions will reduce or eliminate non-price barriers to competition across a broader region. These changes may benefit the Distribution Companies by reducing the cost of buying power to serve their customers. On the other hand, these changes may adversely affect the Distribution Companies’ recovery of their transmission cost of service due to the loss of their proportionate share of charges to export power from PJM. Effective when they joined PJM on April 1, 2002, the FERC allowed the Distribution Companies to recover the transmission revenues they lost through a transitional surcharge. Other parties who join PJM in the future may seek to alter, reduce, or eliminate this surcharge. If they are successful, the Distribution Companies may be adversely affected. For a further discussion, see—Regulatory Framework Affecting Allegheny—Federal Legislation, Competition, and RTOs, below.

In addition, expanding PJM may increase opportunities for AE Supply to sell the output of its generation in new markets. Conversely, other generation owners may more economically compete for power sales in AE Supply’s traditional markets. We are unable to predict whether we will be able to compete effectively as RTOs expand and evolve. We do not know whether markets will continue to be accessible, especially if some states choose to delay or repeal retail access programs. It is also possible that inefficiencies may emerge as markets expand that may impair our ability to compete. For a further discussion, see—Regulatory Framework Affecting Allegheny—Federal Legislation, Competition, and RTOs, below.

Further, the expansion of PJM to include new companies may affect the cost of transmission service that Allegheny requires in ways that are difficult to predict.

PJM uses a locational marginal pricing (LMP) method to price both generation and end use customer demand at a particular time and location on the electricity transmission network. LMP recognizes that the marginal price of electricity may be different at different locations on the system and at different times.

Differences in prices between two locations in the region at the same time reflect physical limitations in the transmission lines to move power across the system. These limits are referred to as transmission congestion. In concept, when there is enough transmission capacity to get power from the cheapest source of generation to all potential buyers on the system, there is no congestion and there would be only one price throughout the region. When there is congestion, such as may occur on a hot summer day, the most economical generators may not be able to reach all of their potential buyers.

Predicting when transmission congestion will occur, and how much of an impact it will have on prices, can be difficult. The prediction is influenced by factors such as weather, transmission line or generator outages, and the transmission schedules of customers taking service from the RTO and even utilities in neighboring regions. End use customers using congested lines are required to pay congestion charges based on the difference of LMP at separate locations. End use customers can manage the risk that the transmission system will be congested by requesting hedge contracts called financial transmission rights (FTRs), which pay the contract holder the LMP difference between two pre-selected points on the transmission system. If the FTR holder accurately predicts the MW quantity of FTRs it will need along a particular transmission path, the payments it receives from the RTO will offset the congestion charges it is required to pay to transmit power on that path. FTRs are allocated by PJM at no cost to end use customers. Buyers of electricity must purchase FTRs from PJM, although buyers may be awarded FTRs if the buyer has paid for the construction of transmission facilities that increase the capacity of the system.

Expanding PJM to include new utilities will bring new transmission lines and generators into the PJM region. As a result, consumers in PJM will have access to new suppliers that may be less expensive than generators currently serving them, and transmitting power from these generators may cause power flows across the transmission system to change, which in turn could cause congestion on individual transmission lines to change—potentially significantly—from congestion patterns observed in the past. To the extent we do not successfully predict these changes, we may not request the right amount of FTRs, which could increase our costs.

Changes to rules relating to power plant construction could compromise the value of our generating assets under development or expansion.

The FERC recently issued a Final Rule on Standardization of Generator Interconnection Agreements and Procedures. In regional markets like PJM, the rule makes generators like AE Supply responsible for the full cost of transmission system upgrades that would not have been necessary “but for” their interconnection. Generators may also receive certain FTRs that may defray the cost of network upgrades in whole or in part. The rule also provides that new owners of a proposed generating project can succeed to the queue position in the transmission network upgrade study process held by the original project owner. Queue position means place in line. PJM and other transmission providers normally study how new generators will impact the transmission system in the order of when each request was submitted, and queue position often influences interconnection rights and costs associated with transmission network upgrades. The costs of any particular generating project could change substantially depending on what queue position the project holds. Certain parties have argued that upon the sale of a project, the new owner should be placed at the end of the transmission system impact study queue, potentially subjecting the project to increased interconnection costs.

The rule remains subject to requests for rehearing and continued appeals. Depending on the final outcome of the rule, AE Supply’s proposed facilities undergoing construction or upgrade could be adversely affected.

The capital-intensive nature of our business exposes us to risks from natural catastrophes and terrorism.

Much of the value of our business consists of our portfolio of unique fixed power generation and transmission assets. Our ability to conduct our operations depends on the integrity of these assets. Although we have taken and will continue to take reasonable precautions to safeguard these assets, there can be no assurance that they will not face damage or disruptions due to natural disasters. In addition, in the current geopolitical climate, there is an enhanced concern regarding the risks of terrorism throughout the economy. Insurance coverage may not cover or may inadequately cover risks of this nature.

Our facilities are subject to unplanned outages and significant maintenance requirements.

The operation of power generation, transmission, and distribution facilities involves many risks, including the breakdown or failure of electrical generating or other equipment, fuel interruption, and performance below expected levels of output or efficiency. If our facilities operate below expectations, we may lose revenues or have increased expenses, including replacement power costs. A significant portion of our facilities was originally constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures on our part to keep operating at peak efficiency or availability and is likely to require periodic upgrades and improvement.

We are involved in several important litigation proceedings that could result, individually or in the aggregate, in the imposition of significant cash awards against us or in impairment of the value of significant assets.

We are the object of several suits seeking substantial damage awards against us. Among these suits are shareholder and benefit plan participant suits, suits by California ratepayers and taxpayers, and a suit brought by Merrill Lynch and affiliated parties alleging breach of contract. We are also involved in defending against claims for damages against us due to our alleged misconduct, and challenging the validity of various substantial power sales contracts. Further information regarding these legal proceedings, as well as other matters, is provided in ITEM 3. LEGAL PROCEEDINGS. We may also be subject in the future to litigation based on asserted or unasserted claims. We cannot predict the outcome of any of these proceedings or other matters, or of future litigation against us based on asserted or unasserted claims. Adverse outcomes in these proceedings and other matters, or in future litigation based on asserted or unasserted claims, could result in the imposition of substantial cash damage awards against us, in the decrease in the value of substantial assets, and the loss of sources of significant cash flow.

We are involved in shareholder suits and other litigation and are a subject of agency investigations in connection with our energy trading business.

In addition to litigation with Merrill Lynch, we are involved in other actions related to the energy trading business. We are the target of putative class action suits by shareholders and by participants in our employee benefit plans that assert claims against us relating to our involvement in the energy trading business and to statements made by us concerning our business. We are involved in arbitrations against terminated employees who were active in the energy trading business. We have responded to subpoenas from the SEC and Commodity Futures Trading Commission (CFTC) directed to us.

Our subsidiaries are and may become subject to legal claims arising from the presence of asbestos or other regulated substances at certain of our facilities.

The Distribution Companies have been named as defendants in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are still present and may in the future continue to be located at Allegheny-owned facilities where suitable alternative materials are not available. We believe, however, that any remaining asbestos at any given Allegheny-owned facility is contained. Allegheny believes that it uses and stores all hazardous substances in a safe and lawful manner. However, asbestos and other hazardous substances are currently used and will continue to be used at Allegheny-owned facilities, which could result in actions being brought against AE Supply that would claim exposure to asbestos or other hazardous substances. A recent U.S. Supreme Court decision could have the effect of increasing potential damage awards in asbestos suits. Additional discussion of the pending litigation appears in this report under ITEM 3. LEGAL PROCEEDINGS.

Covenants contained in the Borrowing Facilities restrict our ability to enter into litigation settlements in excess of $25 million. As a result, we may be required to proceed with litigation even if we would elect to attempt to settle matters in the absence of the restriction.

AE Supply relies on power transmission facilities that it does not own or control. If these facilities do not provide it with adequate transmission capacity, AE Supply may not be able to deliver its wholesale electric power to its customers.

AE Supply depends on some T&D facilities owned and operated by both the Distribution Companies and other utilities and power companies to deliver the electricity it sells. This dependence exposes AE Supply to a variety of risks. If transmission is disrupted or transmission capacity is inadequate, AE Supply may not be able to sell and deliver all of its products. If AE Supply fails to schedule the delivery of electric energy correctly, it may face substantial penalties under the transmission provider’s tariff. If a region’s power transmission infrastructure is inadequate, AE Supply’s recovery of costs and profits may be limited. The FERC has proposed pricing structures to encourage the expansion of transmission infrastructure. Implementation of the proposed incentives is not assured, and no assurance can be given that the proposed incentives would serve as an adequate incentive to trigger significant investment in transmission network expansion. If regulators unexpectedly adopt restrictive transmission price regulation, transmission companies may not have sufficient incentives to invest in the expansion of transmission infrastructure. Conversely, AE Supply may suffer a competitive disadvantage if regulatory policies favor transmission expansion over generation expansion to alleviate grid congestion. The power outages that occurred in the Northeast, Midwest, and in Canada on August 14, 2003 could lead to further regulatory or legislative initiatives at the federal or state level regarding transmission and distribution reliability and expansion. We are unable to predict the policies that may be pursued or the effect policy changes may have on the transmission of electricity.

AE Supply and its customers depend upon access to the transmission grid to deliver electricity from generators to consumers. If there is insufficient transmission capacity, or if transmitting utilities do not provide AE Supply or its customers with fair and timely access to the transmission system, AE Supply may lose opportunities to sell its products. We cannot predict whether these circumstances will occur, or if they do, how significant the impact may be on AE Supply.

Our costs to comply with environmental laws are significant, and the cost of compliance with future environmental laws could adversely affect our cash flow and profitability.

Our operations are subject to extensive federal, state, and local environmental statutes, rules, and regulations relating to air quality, water quality, waste management, natural resources, site remediation, and health and safety. Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees, and permits at all of our facilities.

These expenditures have been significant in the past and we expect that they will increase in the future. Costs of compliance with environmental regulations, particularly air emission regulations, could have a material adverse effect on our industry, our business, our results of operations, and financial condition. This is especially true if emission limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated, or the number and types of assets we operate increase. We plan to incur substantial costs to install new emissions control equipment, and may be required to upgrade existing equipment, purchase emissions allowances, or reduce operations.

Applicable standards under the EPA’s New Source Review (NSR) initiatives are in flux. Under the Clean Air Act of 1970 (Clean Air Act), the modification of certain existing facilities (rather than performance of routine maintenance) could cause the facilities to be subject to far more stringent NSR standards applicable to new facilities. The EPA has taken the view that many companies, including many energy producers, have been modifying sources in connection with work believed by the companies to be routine maintenance under the statute and rules. The EPA and state agencies have successfully pursued NSR claims against energy producers and other companies and have required the expenditure of billions of dollars of emissions-related capital upgrades as a result. A recent judicial decision involving a subsidiary of FirstEnergy Corporation could adversely affect industry-wide environmental compliance costs. A recent settlement agreement between the EPA and Dominion Resources, Inc. also has adverse implications under NSR for the compliance costs of energy industry participants, such as Allegheny. However, the recent preliminary judicial decision in a case involving Duke Energy, and the final Routine Maintenance, Repair and Replacement rule (RMRR) recently released by the EPA, are more consistent with the energy industry’s historical compliance approach. The EPA has requested information from Allegheny in connection with its NSR initiative.

Most of our contracts with customers do not permit us to automatically recover additional capital and other costs incurred to comply with new environmental regulations. As a result, to the extent these costs are incurred prior to the expiration of these contracts, these costs could adversely affect our financial performance.

Risks inherent in the process of obtaining required environmental approvals could adversely affect our ability to operate current facilities or site future projects.

Energy companies such as Allegheny are subject to the risk that it may be difficult or impracticable to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining or renewing any required environmental regulatory approval or if we fail to obtain or comply with any such approval, the affected facilities could be delayed in becoming operational, could be temporarily closed, or otherwise subjected to capacity limitations, or subjected to additional costs. Further, at some of our older facilities, it may be uneconomical for us to install the necessary equipment, which may lead us to shut down or reduce the operations at certain individual generating units, resulting in a loss of capacity and possible significant environmental and other closure costs. Environmental and other regulations render it difficult and time-consuming to site new generation and transmission and distribution projects.

Future changes in environmental laws and regulations could cause us to incur significant costs or delays.

New environmental laws and regulations affecting our operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to our facilities or us. For example, the laws governing nitrogen oxides (NO_x) and sulfur dioxide (SO₂) emissions from coal-burning plants could be

interpreted by federal and state authorities in a manner that could subject some of our facilities to New Source Review under the Clean Air Act and result in limitations on these emissions that are substantially more stringent than those currently in effect. Our compliance strategy, although reasonably based on the information available to us today, may not successfully address the relevant standards and interpretations of the future. As a result, we may be required to materially increase all manner of our compliance expenditures or accelerate the timing of the capital portion of those expenditures.

The EPA is developing new policies concerning protection of endangered species and sediment contamination, based on its interpretation of the Clean Water Act (CWA). The scope and extent of any resulting environmental regulations and their effect on our operations is unknown. The EPA has also announced its intention to review rules related to the regulation of mercury emissions. Rules in this regard could have a material adverse effect on our ability to economically produce electricity from coal.

If we fail to comply with environmental laws and regulations, we may have to pay significant fines or incur significant capital expenditures.

If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, our failure may result in the assessment of civil or criminal liability, fines against us, and the need to expend significant, additional capital to comply. Recent lawsuits by the EPA and various states highlight the environmental risks related to generating facilities, in general, and coal-fired generating facilities, in particular. For example, the Attorneys General of New York and Connecticut notified us in 1999 of their intent to commence civil actions against us for alleged violations of the Clean Air Act or CAAA. If these actions were filed and if they were resolved against us, substantial modifications of our existing coal-fired power plants would be required. Similar actions may be commenced by other governmental authorities in the future.

In addition, a number of our coal-fired facilities have been the subject of a formal request for information from the EPA concerning New Source Review Requirements under the Clean Air Act. Similar requests to other companies have often been followed by enforcement actions. If an enforcement proceeding or litigation in connection with this request or in connection with any proceeding for non-compliance with environmental laws were commenced and resolved against us, we could be required to invest significantly in new emission control equipment, accelerate the timing of capital expenditures, pay penalties, and/or halt operations. Moreover, our results of operations and financial position could suffer due to the consequent distraction of management and the expense of ongoing litigation. Other parties have settled similar actions against them.

We could incur additional substantial liabilities for environmental remediation.

Like other companies engaged in power generation, our operations involve the handling and use of hazardous materials and the generation of wastes. A risk of environmental contamination is inherent in many of our activities, and we could be required to investigate and remediate properties in the event of a release to the environment or the discovery of contamination. We are subject to certain environmental laws, such as the federal Superfund law, that can impose liability for the entire cost of cleaning up a site, regardless of fault, upon certain statutorily defined parties. These include current and former owners or operators of a contaminated site and companies that send wastes to a site that becomes contaminated. Many of our sites have been operated for a number of years and could require remediation in the future if contamination is discovered or if operations cease at a facility.

We may undertake future asset sales, including generating assets. Following a sale, we intend to transfer future environmental liability to the new owner. However, it is possible that if future contamination occurs at these sites or is discovered from prior years’ operations, we might be required to participate in remediation efforts.

Allegheny’s revenues are derived primarily from generation and marketing revenues and delivery and services revenues, which include, regulated electric sales and revenues, regulated natural gas sales and revenues, and unregulated services revenues. Generation and marketing revenues totaled $945.3 million, $1,928.1 million and $1,436.7 million in 2002, 2001, and 2000, respectively. Regulated electric revenues totaled $2,490.2 million, $2,395.0 million, and $2,303.4 million in 2002, 2001, and 2000, respectively.

Regulated natural gas revenues totaled $221.6 million, $235.1 million, and $103.6 million in 2002, 2001, and 2000, respectively. Unregulated services revenues totaled $643.5 million, $139.5 million, and $22.6 million in 2002, 2001, and 2000, respectively.

See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional details regarding Allegheny’s revenues.

Allegheny’s generation and marketing revenues decreased 51.0 percent from 2001 to 2002, primarily due to weak wholesale energy markets nationwide and increased unrealized losses on commodity contracts due to market conditions.

Allegheny’s regulated kilowatt-hour (kWh) sales increased 2.9 percent from 2001 to 2002 as a result of increases of 4.8 percent, 4.6 percent, and 1.2 percent in residential, commercial, and industrial sales, respectively, and a decrease of 3.9 percent in wholesale and other sales. Allegheny’s regulated electric revenues increased 4.0 percent from 2001 to 2002 due to increases of 5.0 percent, 7.3 percent, 4.1 percent in residential, commercial,

and industrial revenues, respectively, and a decrease of 40.4 percent in wholesale and other revenues. (See ITEM 1. BUSINESS—Rate Matters and ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.)

Allegheny’s all-time Peak Load was 8,437 MW on January 23, 2003. Allegheny’s 2002 Peak Load was 8,301 MW on July 22, 2002. Allegheny’s Load includes regulated load.

Allegheny’s 2002 regulated electric revenues were derived as follows: Pennsylvania, 43.8 percent; West Virginia, 28.8 percent; Maryland, 18.9 percent; Virginia, 5.9 percent; and Ohio, 2.6 percent (residential, 42.2 percent; commercial, 23.9 percent; industrial, 32.3 percent; and wholesale and other, 1.6 percent).

Monongahela’s regulated kWh sales increased 3.6 percent from 2001 to 2002 as a result of increases of 7.0 percent, 3.6 percent, 1.6 percent, and 9.3 percent in residential, commercial, industrial, and wholesale and other sales, respectively. Monongahela’s regulated electric revenues increased 3.2 percent from 2001 to 2002 as a result of increases of 5.6 percent, 2.9 percent, and 1.7 in residential, commercial, and industrial revenues, respectively, and a decrease of 23.9 percent in wholesale and other revenues.

Monongahela’s 2002 regulated electric revenues represented 24.8 percent of Allegheny’s 2002 regulated electric revenues. Monongahela’s 2002 regulated electric revenues were derived as follows: West Virginia, 89.5 percent, and Ohio, 10.5 percent (residential, 39.7 percent; commercial, 24.0 percent; industrial, 35.4 percent; and wholesale and other, 0.9 percent).

Potomac Edison’s regulated kWh sales increased 3.4 percent from 2001 to 2002 as a result of increases of 6.1 percent, 5.6 percent, and 1.1 percent in residential, commercial, and industrial sales, respectively, and a decrease of 4.2 percent in wholesale and other sales. Potomac Edison’s regulated electric revenues increased 2.4 percent from 2001 to 2002 as a result of increases of 4.0 percent, 9.0 percent, and 2.6 percent in residential, commercial, and industrial revenues, respectively, and a decrease of 49.6 percent in wholesale and other revenues.

Potomac Edison’s all-time Peak Load was 3,091 MW on January 23, 2003. Potomac Edison’s 2002 Peak Load was 2,725 MW on August 2, 2002.

Potomac Edison’s 2002 regulated electric revenues represented 31.4 percent of Allegheny’s 2002 regulated electric revenues. Potomac Edison’s 2002 electric revenues were derived as follows: Maryland, 60.2 percent; West Virginia, 20.9 percent; and Virginia, 18.9 percent; (residential, 46.0 percent; commercial, 23.1 percent; industrial, 28.9 percent; and wholesale and other, 2.0 percent). Potomac Edison’s regulated electric revenues from one industrial customer, the Eastalco Aluminum Company (Eastalco) near Frederick, Maryland, totaled less than ten percent of its total regulated electric revenues, but represented 19.2 percent of its 2002 MWh sales to customers.

West Penn’s regulated kWh sales increased 2.1 percent from 2001 to 2002 as a result of increases of 2.7 percent, 4.5 percent, and 1.0 percent in residential, commercial, and industrial sales, respectively, and a decrease of 6.9 percent in wholesale and other sales. West Penn’s regulated electric revenues increased 5.5 percent from 2001 to 2002 as a result of increases of 5.5 percent, 8.7 percent, and 6.6 percent in residential, commercial, and industrial revenues, respectively, and a decrease of 34.3 percent in wholesale and other revenues.

West Penn’s all-time Peak Load was 3,677 MW on August 6, 2001. West Penn’s 2002 Peak Load was 3,582 MW on August 14, 2002.

West Penn’s 2002 regulated electric revenues represented 43.8 percent of Allegheny’s 2002 regulated electric revenues. All of West Penn’s 2002 regulated electric revenues were derived from Pennsylvania (residential, 41.0 percent; commercial, 24.4 percent; industrial, 33.0 percent; and wholesale and other, 1.6 percent).

Allegheny’s regulated natural gas Bcf sales decreased 0.3 percent from 2001 to 2002 as a result of decreases of 6.4 percent, 27.6 percent, 57.1 percent, and 62.5 percent in residential, commercial, industrial, and wholesale and other sales, respectively, and an increase of 16.9 percent in transportation and other sales. Allegheny’s regulated 2002 natural gas revenues decreased 5.7 percent from 2001 to 2002 as a result of decreases of 18.3 percent, 56.1 percent, and 56.1 percent in commercial, industrial, and wholesale and other revenues, respectively, and increases of 2.3 percent and 31.3 percent in residential and transportation and other revenues, respectively.

Allegheny’s 2002 regulated natural gas Bcf sales were derived as follows: residential, 27.6 percent; commercial, 14.0 percent; industrial, 0.4 percent; wholesale, 0.5 percent; and transportation and other, 57.5 percent. Allegheny’s 2002 regulated natural gas revenues were derived as follows: residential, 64.2 percent; commercial, 29.4 percent; industrial, 0.8 percent; wholesale, 0.8 percent; and transportation and other, 4.8 percent. West Virginia Power (WVP) and Mountaineer accounted for 4.4 percent and 95.6 percent of total regulated Bcf sales, respectively. Mountaineer accounted for all transportation sales. All of Allegheny’s 2002 regulated natural gas revenues were derived from West Virginia.

Included in the table and discussion above are amounts related to unregulated natural gas sales and revenues. Total unregulated sales of natural gas were 1.8 Bcf and 2.4 Bcf in 2002 and 2001, respectively. These sales represented revenues of $0.5 million and $0.7 million in 2002 and 2001, respectively. All unregulated sales and revenue reflect the elimination of intercompany amounts.

Allegheny’s unregulated services revenues increased 361.6 percent from 2001 to 2002, primarily due to revenues for AE Solutions’ agreement to provide seven natural gas-fired turbine generators to the Southern Mississippi Electric Power Association (SMEPA) and revenues from Alliance Energy Services, which was acquired by Allegheny Ventures on November 1, 2001.

The table below shows construction and environmental control expenditures for Allegheny in 2002, 2003, and 2004.

The Delivery and Services segment’s construction expenditures include projects to upgrade distribution lines and substations, as well as transmission and subtransmission systems enhancements. The Generation and Marketing segment’s construction expenditures include projects at generating stations for environmental control upgrades, to remediate or prevent equipment failure and to create new generation capacity.

The Generation and Marketing Segment (including Monongahela’s West Virginia jurisdictional generating assets)

During 2002 and 2003, the Generation and Marketing segment completed certain projects and also discontinued other planned projects.

Springdale, Pennsylvania. AE Supply completed construction of a 540-MW combined-cycle generating plant in Springdale, Pennsylvania, with a commercial operation date of July 21, 2003. This combined-cycle facility includes two natural gas-fired combustion turbines and one steam turbine.

Buchanan County, Virginia. In June 2002, AE Supply completed construction and placed in service an 86-MW simple-cycle natural gas combustion turbine facility in Buchanan County, Virginia. This facility is owned by Buchanan Generation, LLC, an equal partnership of CONSOL Energy, Inc., and Buchanan Energy Company of Virginia, LLC, a wholly-owned subsidiary of AE Supply. AE Supply operates and dispatches 100 percent of its generation.

Harrison Power Station, West Virginia. During 2002, generating capacity at Harrison Power Station increased by 11 MW, from 1,950 MW to 1,961 MW, due to efficiency upgrades of one of the steam turbines. During 2003, generating capacity at a second Harrison unit increased by 11 MW increasing the total station output to 1,972 MW. These generation increases were based on initial steam turbine test results.

AE Supply ceased construction or planning of several generating projects in 2002, all in response to market conditions, including overcapacity and lower wholesale power prices, and to conserve liquidity. The following are among the planned or commenced projects that were discontinued:

La Paz County, Arizona. AE Supply has decided not to construct a previously planned 1,080-MW natural gas-fired generating facility in La Paz County, Arizona, for which it had previously acquired land and obtained Arizona Corporation Commission approval.

St. Joseph County, Indiana. In January 2001, AE Supply announced plans to construct a 630-MW natural gas-fired merchant generating facility in St. Joseph County, Indiana, approximately 10 miles west of South Bend. AE Supply suspended construction of this project in 2002.

Brooklyn Navy Yard Barge. AE Supply has withdrawn from this 79-MW barge-mounted generating facility project and is seeking to terminate the agreement with its joint development partner.

Rock Springs, Maryland. AE Supply has withdrawn from this simple-cycle gas turbine project, in which it was a minority participant with an approximately 350-MW ownership share in the 1,050-MW project.

See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding charges for discontinued generating projects.

While meeting the FERC and certain state regulatory requirements, the Distribution Companies also must meet RTO requirements since the responsibility for planning major transmission systems rests with the new independent authority. The Distribution Companies do not expect their affiliation with PJM West to result in major near-term system expansion.

The following table shows Allegheny’s nominal maximum operational generating capacity as of December 31, 2002, based on said capacity of each unit. All of the generating capacity is part of the Generation and Marketing segment owned by AE, AE Supply, Monongahela, or AGC. Monongahela’s owned capacity totaled 2,117 MW, of which 1,896 MW (89.6 percent) are coal-fired and 221 MW (10.4 percent) are pumped-storage. The term pumped-storage refers to the Bath County station, which stores energy for use principally during peak load hours by pumping water from a lower to an upper reservoir, generally during off-peak hours. During the generating cycle, power is produced by water falling from the upper to the lower reservoir through turbine generators.

AE Supply’s owned capacity (including AGC) as of December 31, 2002, totaled 8,924 MW, of which 6,006 MW (67.3 percent) are coal-fired, 2,039 MW (22.8 percent) are natural gas-fired, 797 MW (8.9 percent) are pumped-storage and hydroelectric, and 82 MW (1 percent) are oil-fired.

In May 2001, AE Supply completed the acquisition of three natural gas-fired generating facilities in Illinois, Indiana, and Tennessee. The facilities have a total capacity of 1,710 MW.

As of December 31, 2002, AE Supply had 1,000 MW of natural gas-fired contracted capacity, as well as access to an additional 44 MW of natural gas-fired capacity through the Hunlock Creek Facility, and three MW of hydroelectric capacity through Green Valley Hydro, LLC, a subsidiarary of AE (Green Valley Hydro). As of January 2003, AE Supply had an additional 222 MW of natural gas fired contracted capacity.

AE also holds a 12.5-percent equity stake in and is a sponsoring company of OVEC. OVEC is owned by 10 electric utility companies, and its power participation benefits are afforded to approximately 12 sponsoring companies. Currently, AE Supply and Monongahela have the benefits of a nine-percent and a 3.5-percent interest, respectively, in OVEC. They have an entitlement to capacity and energy in excess of certain OVEC customer loads. Those loads currently are almost totally dormant. As a consequence, nearly all of the OVEC capacity and energy is surplus and AE Supply and Monongahela receive a combined 12.5-percent share of that surplus, with individual apportionments of approximately 202 MW and 78 MW, respectively, for use toward supply requirements and other purposes. Power is supplied back to the sponsors under a contract that expires March 12, 2006.

In July 2003, AE Supply completed construction of a 540-MW combined-cycle facility in Springdale, Pennsylvania. The project is now in commercial operation.

In June 2003, AE Supply completed the sale of its 83-MW share of the coal-fired Conemaugh Generating Station, located near Johnstown, Pennsylvania.

AE Supply has undertaken asset sales in 2003 and, in order to enhance liquidity, could seek to market additional power generating assets.

The following table shows nominal maximum operational generating capacity owned by Allegheny as of December 31, 2002, or acquired under the Public Utility Regulatory Policies Act of 1978 (PURPA) contracts:

The following table sets forth the existing miles of tower and pole T&D lines and the number of substations of the Distribution Companies and AGC as of December 31, 2002:

The Distribution Companies’ transmission network has 12 extra-high-voltage (EHV—345kV and above) and 31 lower-voltage interconnections with neighboring utility systems.

The Distribution Companies own coal reserves estimated to contain about 125 million tons of higher sulfur coal recoverable by deep mining. There are no present plans to mine these reserves and, in view of the present economic conditions, the Distribution Companies are evaluating several options related to the sale or lease of the reserves. Such options may not be available to the Distribution Companies on favorable terms, if at all.

In 2002, generating stations owned by AE, AE Supply, and Monongahela consumed approximately 18.1 million tons of local mid- to high-sulfur content coal. Of that amount, 49 percent was used in stations equipped with scrubbers (8.8 million tons). The use of desulfurization equipment and the cleaning and blending of coal make burning local coal practical. In 2002, almost 100 percent of the coal received at these stations came from mines in West Virginia, Pennsylvania, Maryland, Illinois, and Ohio. None of the Allegheny companies mine or clean any coal. All raw, clean, or washed coal from suppliers is purchased as necessary to meet station requirements.

In 2002, AE, AE Supply, and Monongahela had long-term arrangements (i.e., terms of 12 months or longer) in place to purchase up to approximately 17.7 million tons of coal. Allegheny purchases coal from a limited number of suppliers. In 2002, AE, AE Supply and Monongahela purchased approximately 11.3 million tons of coal (61 percent of coal used) from various local mines owned by subsidiary companies of one coal company. Long-term arrangements (i.e., terms of 12 months or longer) are in effect to provide for up to approximately 17.2 million tons of coal in 2003. AE, Monongahela, and AE Supply will depend on short-term arrangements and spot purchases for their remaining requirements.

For the year 2002, the cost per equivalent ton of coal consumed was $29.58. For 2001 and 2000, the average cost per equivalent ton of coal consumed was $27.42 and $26.73, respectively. This average cost per equivalent ton includes primary and auxiliary fuels. The 2002 average cost increase resulted from a significant increase in 2001 market prices during which time a considerable portion of 2002’s fuel supply was purchased.

In 2002, natural gas-fired generation owned by AE and AE Supply used approximately 7.55 Bcf of natural gas. The natural gas was purchased either through long-term natural gas supply agreements or in the spot market. AE Supply purchases natural gas services to supply its natural gas-fired facilities, including agreements for transportation, storage, and supply, which allow AE Supply to find the most economic options to serve its facilities. AE Supply currently has one index based natural gas supply agreement, which is in effect until May 2006.

In addition, one of AE Supply’s subsidiaries has a month-to-month natural gas agreement in place. The natural gas provided under this agreement is either used at the Buchanan County, Virginia facility or re-marketed by AE Supply. This supplier provided 4.6 percent of the total natural gas used by AE Supply for generation in 2002. See also a discussion of Kern River and El Paso pipeline contracts under —Allegheny’s Competitive Actions—Certain Purchase and Transportation Projects, below.

Allegheny substantially restructured its corporate organization in response to the electric utility deregulation within its service area between 1999 and 2001. The Distribution Companies, with the exception of Monongahela with respect to its West Virginia jurisdictional generating assets, do not produce their own power. Monongahela transferred a portion of its generating assets relative to its Ohio and FERC jurisdictional generating assets, including a portion of its ownership interest in AGC and OVEC, to AE Supply in 2001. In 2000, Potomac Edison transferred substantially all of its generating assets to AE Supply. West Penn transferred all of its generating assets to AE Supply in 1999. The Distribution Companies’ generation asset transfers included, in the case of Potomac Edison and West Penn, entitlement to OVEC capacity and their entire ownership interest in AGC.

The Distribution Companies retain the obligation to provide electricity to customers who do not retain an alternate electricity generation supplier during the deregulation transition period. The transition periods vary across Allegheny’s service area and by state.

These transition periods could be altered by legislative or, in some cases, regulatory actions.

AE Supply has the contractual obligation to provide power to the Distribution Companies during the current relevant state deregulation transition periods under the terms of power supply agreements with the Distribution Companies. AE Supply also leases generating capacity to Potomac Edison to serve customers in Potomac Edison’s West Virginia service territory. Sales under the power sales agreements AE Supply has with West Penn, Monongahela with respect to its Ohio customers and Potomac Edison currently consume a majority of the normal operating capacity of AE Supply’s generating assets that were previously owned by the Distribution Companies. These agreements have a fixed price as well as a market-based pricing component. These components may have little or no relationship to the cost of supplying this power. This means that AE Supply currently absorbs a portion of the risk of fuel price increases and increased costs of environmental compliance since AE Supply is unable to automatically pass on such costs to the Distribution Companies.

The Distribution Companies purchase power from AE Supply to satisfy their respective PLR obligations. The purchases are made under the terms of power sales agreements with AE Supply which will terminate as set

forth in the chart below. When these agreements terminate, the Distribution Companies will be unable to rely on a dedicated supply of power from AE Supply at the current contract prices to meet their respective power supply requirements. The arrangements to serve the load of the Distribution Companies have not been determined and are subject to legislative and regulatory actions within the states of Pennsylvania and Virginia. In Maryland, settlement negotiations regarding the provision of default service in the post transition period have concluded and have resulted in a settlement agreement that prescribes a wholesale bidding process to procure market-based full requirements service for end use customers. A final state commission order on this settlement is expected in late September 2003, with the bid solicitation process beginning October 1, 2003. With respect to Ohio, Monongahela is undertaking a wholesale bidding process, similar to that in Maryland, to procure market-based full requirements service for industrial and commercial end use customers, beginning January 1, 2004, for eligible customers. However, contract awards and the subsequent retail rates are subject to state regulatory approval.

A portion of the PLR obligations for the Distribution Companies is satisfied by PURPA contract purchases. The remainder of the power to meet the PLR obligations of the Distribution Companies is purchased from AE Supply. The table below shows the percentage of power for each jurisdictional set of customers of the total power supply purchased by the Distribution Companies from AE Supply in 2002:

Monongahela’s regulated natural gas sales operations are carried out through Mountaineer and its Monongahela divisions. West Virginia is in the path of major natural gas supply routes from the Gulf of Mexico to the Northeast, and Monongahela has direct access to the Columbia Gas Transmission Corporation (Columbia Gas) and the Tennessee Gas Pipeline (Tennessee) interstate pipeline systems. Monongahela’s principal natural gas requirements are supplied from wells located in Appalachia and the Gulf of Mexico producing basins. Monongahela’s ownership of MGS provides direct access to a portion of Monongahela’s total annual natural gas needs (less than 10 percent). A small part of MGS’ output is sold to third parties. Approximately 75-80 percent of Monongahela’s natural gas supply requirements are purchased on a forward basis (up to 12 months), with the remainder, including MGS production, purchased on a one-year or more forward basis. The current price of natural gas is high in relation to historical prices, and Monongahela has sought to satisfy supply requirements under relatively short-term arrangements.

The following table indicates the volume of natural gas purchased and percentage of total volume of natural gas purchased, with respect to Monongahela’s largest suppliers for the 12 months ended December 31, 2002:

Allegheny’s liquidity issues, together with natural gas price spikes, have required Monongahela to prepay for future natural gas deliveries during 2003. Monongahela believes that it will obtain access to sufficient natural gas supplies to meet its anticipated requirements. However, liquidity issues have resulted in Monongahela being denied by a number of its former suppliers of the ability to purchase any volumes on a forward basis.

Natural gas purchased from producers or suppliers in the Gulf Coast producing basin/region is transported through the interstate pipeline systems of Columbia Gulf and Columbia Gas to Monongahela’s local distribution facilities in West Virginia.

To ensure continuous, uninterrupted service to its customers, Mountaineer has in place long-term transportation and storage service agreements with Columbia Gas and Columbia Gulf. These contracts cover a wide range of transportation services and volumes, ranging from firm transportation service to no-notice service and storage with such contracts expiring on October 31, 2004. Mountaineer has the right to renew its contracts under right-of-first refusal procedures set forth in the pipeline companies’ tariffs. Under both Mountaineer’s and WVP’s Purchased Gas Adjustment clauses (PGA), purchased gas costs including transportation and storage services, if prudently incurred, are recovered from the respective companies’ customers.

Typically, large commercial and industrial end-users of natural gas use natural gas sales and/or transportation contracts for load management purposes. Under such contracts, these users purchase and/or transport natural gas with the understanding that they may be forced to shut down their use of natural gas or

switch to alternate sources of energy during times when the natural gas is needed for higher priority customers of the utility serving the end-user such as schools and hospitals, or interruptible transportation on the transporting pipeline is curtailed (limited/restricted). In addition, during times of extraordinary supply problems, curtailments of deliveries to these classes of customers (typically large industrial customers) with firm interstate transportation contracts may be necessary, but only in accordance with guidelines established by appropriate federal and state regulatory agencies.

Since July 1999, Mountaineer has served many of these types of customers, some of which are capable of using alternate fuels as an energy source at their respective facilities. In 2002, Mountaineer did not have to interrupt these customers because of supply or transportation capacity scarcity or curtailments.

On October 10, 2001, the West Virginia PSC approved an interim decrease in the PGA rate for natural gas customers of Monongahela, effective with bills rendered on and after December 4, 2001 through November 30, 2002 (total revenue decrease for the 12-month period of $5 million or 15.3 percent). This approval became final on December 25, 2001. The reduced PGA rate is the result of changes in the market price Monongahela pays for natural gas. This decrease in natural gas cost recovery revenues has no effect on earnings because it was implemented via the PGA mechanism. Under the PGA mechanism, differences between revenues received for energy costs and actual energy costs are deferred until the next annual PGA proceeding when energy rates are adjusted to return or recover previous overrecoveries or underrecoveries, respectively.

On October 9, 2002, the West Virginia PSC approved an interim decrease in the PGA rate for natural gas customers of Monongahela, effective with bills rendered on or after December 4, 2002. This interim decrease was primarily due to previous overrecoveries. On March 24, 2003, the West Virginia PSC issued a Recommended Decision approving revised rates as filed (total estimated annual revenue decrease over the 2001-2002 PGA of $3.5 million or 13.2 percent). Higher natural gas market prices occurred this winter as a result of a combination of factors: increased demand, resulting from colder-than-normal temperatures; increased industrial demand; lower natural gas storage levels; and a downturn in natural gas-directed drilling activity in 2002. The decrease in PGA rates resulted from previous overrecoveries, which more than offset the increase in natural gas costs. The revised rates became effective with bills rendered on or after May 13, 2003.

On October 9, 2002, the West Virginia PSC approved an interim decrease in the PGA rate for Mountaineer customers, effective with bills rendered on or after December 4, 2002. This interim decrease resulted from refunding of previous overrecoveries, partially offset by minor increases in the wholesale commodity prices. On March 28, 2003, the West Virginia PSC issued a Recommended Decision approving revised increased rates submitted in a settlement agreement filed on January 21, 2003 (total annual revenue increase over the 2001-2002 PGA of $6.35 million or 3.3 percent). As stated in the preceding paragraph, higher natural gas market prices occurred this winter as a result of a number of factors. The revised rates became effective with bills rendered on or after April 17, 2003. The decision became final on April 17, 2003.

On August 1, 2003, Monongahela and Mountaineer Gas filed for PGA rate increases of 53 percent and 39.9 percent respectively, to be effective for a 12-month period beginning with service rendered on and after November 1, 2003. The increased PGA rates are the result of increased market prices Monongahela and Mountaineer pay for natural gas and the removal of a credit for a previously deferred balance. A stipulation was approved on September 11, 2003 reflecting interim PGA rate increases over the final rates approved for the 2002-2003 PGA period of 40.9 percent and 32 percent for Monongahela and Mountaineer Gas, respectively, to be effective with service rendered on and after October 2, 2003. The West Virginia PSC ordered that a final decision be issued by March 29, 2004.

On January 17, 2003, the West Virginia PSC issued an order granting movement of WVP electric customers to Monongahela tariffs, effective January 1, 2003. This order is in compliance with the West Virginia PSC’s directive, issued in a December 9, 1999 order, to move all former WVP customers to the Monongahela tariff in January 2003. The movement of customers results in an overall decrease in revenue to Monongahela of approximately $1.6 million per year. Although most of the former WVP customers received rate decreases, there is a small percentage of customers who will incur rate increases, and provisions have been made to address the gradual move to Monongahela rates for this selected group of customers. Monongahela has been ordered to not apply the three-percent Temporary Customer Choice Credit, provided in its tariff, to former WVP medium- and large-sized commercial and industrial customers. Monongahela will allocate the monies generated by non-application of the Temporary Customer Choice Credit to a fund that will be used by Monongahela to moderate the effect of the rate increases that will result from the movement of former WVP customers to Monongahela’s tariff, so that no customer will receive a rate increase greater than seven percent a year.

On November 7, 2001, the Maryland PSC approved the Power Sales Agreement between Potomac Edison and AE Supply, the winning bidder, covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2002, through December 31, 2004. The AES Warrior Run cogeneration project was developed under PURPA and achieved commercial operation on February 10, 2000. Under the terms of the Maryland deregulation plan approved in 1999, the revenues from the sale of the AES Warrior Run output are used to offset the capacity and energy costs that Potomac Edison pays to the AES Warrior Run cogeneration project before determining amounts to be recovered from Maryland customers.

Effective with bills rendered on or after January 8, 2002, there was a decrease in distribution rates for Maryland customers. This decrease or Customer Choice Credit is a result of implementing the rate reductions called for by a settlement agreement approved by the Maryland PSC in December 1999. The Customer Choice Credit will remain in effect until a total of $72.8 million (approximately $10.4 million annually) has been credited to residential customers and a total of $10.5 million (approximately $1.5 million annually) has been credited to commercial and industrial customers. Additionally, since the time the Maryland PSC approved the rate reductions outlined above, the environmental surcharge has increased, and an electric universal service surcharge has been introduced, both of which must be recovered under Potomac Edison’s distribution rate cap. Accordingly, distribution rates have been further reduced by $3 million from the previously approved rates. The distribution rate cap for all customers is effective from 2002 through 2004.

The Pennsylvania Department of Revenue increased the Gross Receipts Tax rate from 4.4 percent to 5.9 percent for electric distribution companies in the state, including West Penn. The new rate was effective January 1, 2002. On August 8, 2002, the Pennsylvania Public Utility Commission (Pennsylvania PUC) approved West Penn’s request to recover these increased tax charges by means of a State Tax Adjustment Surcharge (STAS) added to customers’ bills. On December 19, 2002, the Pennsylvania PUC approved West Penn’s request to include the previously approved surcharge in West Penn’s base rate for its 2003 tax liability, effective January 1, 2003.

In 2002, Pennsylvania also reduced the series of rate reductions in the Capital Stock and Franchise Tax (also recovered via STAS). For the year 2002, the Capital Stock and Franchise tax was increased to 7.24 mills from 6.49 mills, resulting in additional tax expense of approximately $0.3 million. On July 11, 2002, West Penn filed a petition to reflect the change and to continue to defer the STAS underrecovery as a regulatory asset for future recovery. The Pennsylvania PUC allowed West Penn to defer the amount of its STAS undercollection.

AGC’s rates are set by a formula filed with and previously accepted by the FERC. Under this formula, the only component that can change is the return on equity (ROE). Pursuant to a settlement agreement filed with the FERC on April 4, 1996, AGC’s ROE was set at 11 percent for 1996 and will continue at that rate until the time any affected party requests and the FERC grants a change. No party has requested any change.

The interstate transmission services and wholesale power sales of the Distribution Companies and AE Supply are regulated by the FERC under the Federal Power Act (FPA). The Distribution Companies’ local distribution service and sales at the retail level are subject to state regulation. The statutory and regulatory framework affecting these companies has evolved significantly over the past decade, and these changes have exposed the companies to significant new risks and opportunities.

AE and all of its subsidiaries are also subject to the broad jurisdiction of the SEC under PUHCA. The Distribution Companies are regulated as to substantially all of their operations by regulatory commissions in the states in which they operate. In addition, Allegheny’s communications subsidiary, ACC, is subject, to a limited extent, to the jurisdiction of the Federal Communications Commission and state communications regulatory commissions. Allegheny is subject to numerous other local, state, and federal laws, regulations, and rules.

The FPA gives the FERC broad authority to regulate public utilities such as AE Supply and the Distribution Companies that own or operate facilities used for the transmission or sale at wholesale of electric power in interstate commerce. Under the FPA, the FERC regulates the rates, terms, and conditions of wholesale power sales and transmission services offered by public utilities, among other things. Historically, the FERC used cost of service regulation to determine whether utility rates satisfied the FPA’s just and reasonable standard. In the late 1980s, however, the FERC began to allow firms engaged in wholesale power sales to sell at negotiated prices, which led to the development of competitive power markets.

The national Energy Policy Act of 1992 (EPACT) provided significant incentives for the restructuring of the electric utility industry to promote competition in wholesale power sales by giving the FERC new authority to order electric utilities to provide third parties with access to their transmission systems and by encouraging investments in exempt wholesale generators (EWG) that engage exclusively in wholesale power sales.

In 1996, the FERC issued Order No. 888 to promote electric competition by requiring all public utilities operating interstate transmission facilities to: (1) file non-discriminatory open access transmission tariffs, and (2) offer wholesale power sales and transmission services as separate products. Order No. 888 also required public utilities: (1) to take transmission service under the same open access tariff as their customers, (2) to state separate rates for wholesale generation, transmission, and ancillary services, and (3) when making wholesale power sales, to rely on the same electronic information network that their transmission customers rely on to obtain information about the utility transmission system. Order No. 889, which was issued at the same time as Order No. 888, imposed standards of conduct governing communications between the utility transmission and wholesale power service groups to prevent utilities from giving their power marketing arms preferential access to transmission system information. Order No. 889 also required utilities to establish electronic communication networks, called OASIS, to provide existing and potential customers the same access to transmission information as the utilities’ power marketing groups.

Public utilities nationwide, including the Distribution Companies, responded to the FERC’s requirements in Order Nos. 888 and 889 by filing open access transmission tariffs and separating their wholesale power sales businesses from their transmission businesses. A number of states, including Maryland, Ohio, Pennsylvania, and Virginia, adopted retail access legislation which permitted utilities to transfer their generating assets to affiliated companies or third parties. Similar to many other utilities, the Distribution Companies restructured their businesses between 1996 and 2001 in Maryland, Ohio, Pennsylvania, and Virginia to comply with retail restructuring requirements in those states by, among other things, transferring generating assets serving

customers in those states to AE Supply. According to the FERC, market restructuring, both regionally and nationally, contributed to a threefold increase in wholesale power market trading activity during the 1990s. For a further discussion, see—State Legislation and Regulatory Developments, below.

In December 1999, the FERC issued Order No. 2000 to promote the further development of wholesale market competition. Order No. 2000 encouraged all public utilities that own or operate jurisdictional transmission assets to voluntarily transfer control over their transmission assets to RTOs and required the utilities to file detailed plans to do so. On March 15, 2001, the Distribution Companies filed a plan with the FERC to transfer functional control over their transmission system to PJM. The plan was approved by the FERC on January 30, 2002, and the Distribution Companies became members of PJM effective April 1, 2002.

On July 31, 2002, the FERC issued a notice of proposed rulemaking which would address the FERC’s lingering concerns about alleged unduly discriminatory practices in the energy industry by requiring transmission-owning public utilities to offer standardized flexible transmission service and to create a level playing field for all participants in wholesale power markets. The rule proposes, among other things, (1) to make participation in RTOs (also called independent transmission providers (ITPs) in the proposed rule) mandatory, rather than voluntary as under Order No. 2000, (2) to require ITPs to administer day-ahead and real-time spot energy markets, (3) to establish market-based methods to manage transmission congestion using locational marginal pricing, (4) to establish procedures to ensure the long-term adequacy of transmission, generation, and demand-side resources, and (5) to establish procedures to monitor and mitigate the abuse of market power in competitive wholesale markets. The proposed rule’s most controversial features include the FERC’s claim to have jurisdiction over the transmission component of utility bundled retail power sales, the proposed requirement that all public utilities join ITPs by a certain date, and its proposal that service to retail customers should not receive a preference over other users of the transmission system.

Hundreds of comments were filed with the FERC in response to its proposed rule, with some supporting various features of the rule and others opposing the proposed changes. Allegheny filed comments which were generally supportive, but suggested certain improvements to the rule. On April 23, 2003, the FERC issued a White Paper called the Wholesale Power Market Platform in response to the comments. The White Paper indicates the FERC’s willingness to make certain modifications to the proposed rule, most notably to allow greater flexibility in the timing of when public utilities must join ITPs, and to give states a greater role in planning new transmission system expansions and how the costs will be recovered. There is some uncertainty whether Congress will permit the proposed rule to take effect. The Energy Policy Act of 2003 as passed by the U.S. House of Representatives contains a provision that would require the FERC to delay implementation of the proposed rule changes until 2005. The Senate passed a bill that does not include this condition, and both bills are now in conference with final action expected this fall. For a further discussion, see —Federal Initiatives, below.

Important developments over the past three years have significantly influenced the legislative and policy initiatives discussed above. Beginning in the summer of 2000, unusual weather, supply imbalances, fuel price increases, market imperfections, and allegations of improper trading practices by some market participants contributed to extreme price increases and volatility in California’s wholesale power markets. These circumstances eventually unsettled power markets throughout the Western United States and triggered numerous legal proceedings at the FERC, at the state level, and before Congress. Similar, though less dramatic, price volatility affected power markets in the East, including PJM, New York, and New England. Markets responded to these price increases by increasing generating capacity through new construction and delayed plant retirements.

In 2002, markets returned to historically normal price ranges as the economy slowed, generating capacity increased, fuel prices fell, and demand declined. The changing market pressured many wholesale power trading firms when market prices fell below forecasts, resulting in reduced revenues, declining credit quality and,

ultimately, a decline in wholesale market trading activity. Some firms responded by curtailing trading activities or exiting the market altogether. Enron’s bankruptcy in the fall of 2001 and disclosures concerning its trading practices contributed to concerns by regulators and market participants that wholesale power markets had serious flaws that needed to be addressed. Investigations in 2002 by the FERC, CFTC, and Department of Justice (DOJ) of so-called round-trip trading practices at certain companies, followed by several additional utility bankruptcy petitions in 2003, have further contributed to this perception.

In the past year, a number of states have moved away from electricity choice at the retail level by delaying the implementation of retail competition or rejecting it outright. Some states that have retail competition, including Virginia, are considering re-regulating retail markets. Allegheny cannot predict to what extent these efforts will be successful, nor can it predict whether or to what extent they will be duplicated in other states.

As the foregoing discussion indicates, changes to date with respect to electric competition have significantly affected the nature of the electric industry and the manner in which its participants conduct their business. These changes make it very difficult to develop a long-term business model. Delays, discontinuations, or reversals of electricity market restructurings in the markets in which the Distribution Companies, AE Supply, and their affiliates operate, or may operate in the future, could have a material adverse effect on their results of operations and financial condition.

PUHCA, originally enacted in 1935 and as subsequently amended, imposes financial and operational conditions and restrictions on many aspects of a registered holding company system’s business. PUHCA restricts a registered holding company system from expanding into other businesses by prohibiting it from engaging in activities that are not functionally related to its core business and also requires registered holding company systems to confine themselves to a single integrated public utility system. Most importantly, in light of Allegheny’s liquidity issues, PUHCA requires pre-approval from the SEC for, among other things, the issuance of debt or equity securities, and for the sale or acquisition of utility assets. The PUHCA approval process introduces significant lead times into routine transactions under normal circumstances. Lead times to obtain authorizations can be from six to nine months. The SEC, in certain matters, also requires state approvals as a condition to authorizations, even though such approvals might not be required under applicable state laws. In certain instances, such as transactions involving designations of assets as EWGs (which exempts the designated assets from continuing PUHCA jurisdiction), the SEC has expanded the jurisdiction of state commissions by requiring that the applicant company obtain a letter from each state in which any of its affiliates operates certifying that state’s approval. This introduces further lead times and uncertainties into the transaction planning process. Many of Allegheny’s competitors are not regulated under PUHCA and, therefore, do not face such constraints.

Additionally, under PUHCA, the SEC has imposed debt to equity ratios on jurisdictional utilities, thus imposing additional operating constraints not imposed on non-jurisdictional utilities. Allegheny’s current equity ratio is below the level required under its current financing authorizations, and this circumstance has required us to obtain additional authorizations.

Under PURPA, electric utility companies such as the Distribution Companies are required to interconnect with, provide back-up electric service to, and purchase electric capacity and energy from qualifying small power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by the FERC. The rates to be paid for electric energy purchased from such qualifying facilities are established by the appropriate state public service commission or legislature.

The Distribution Companies have committed to purchase 479 MW of qualifying PURPA capacity. Payments for PURPA capacity and energy pursuant to these contracts in 2002 totaled approximately $205 million, before amortization of West Penn’s adverse power purchase commitment. The average cost to the Distribution Companies of these power purchases was 5.61 cents/kWh. The Distribution Companies are currently authorized to recover substantially all of these costs in their retail rates.

It is possible that the Distribution Companies’ obligations to purchase power from qualified PURPA projects in the future may exceed amounts they are authorized to recover from their customers, which could result in losses related to the PURPA contracts.

Congress did not enact any significant energy-related legislation in 2002. In 2003, the House and Senate passed their versions of an energy bill. A House-Senate conference to reconcile the two bills has begun and is planned to conclude this fall with a compromise bill being reported back to both chambers for approval. If passed, the legislation would then go to the President to be signed into law. Both bills currently include provisions repealing PUHCA, Allegheny’s chief legislative issue; however, under the pending legislation, the subject matter of many aspects of the SEC’s authority over subject companies would be transferred to the FERC. Allegheny continues to advocate the repeal of PUHCA and Section 210 of PURPA on the grounds that these statutes are obsolete and anticompetitive, and that PURPA results in utility customers paying above-market prices for power.

Maryland’s adoption of electric industry restructuring legislation in 1999 gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation suppliers. In 2000, Potomac Edison transferred its Maryland jurisdictional generating assets at book value to AE Supply. It retained its T&D assets. Potomac Edison’s T&D rates are capped through 2004, and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates). Potomac Edison has the responsibility as the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver. AE Supply has entered into long-term power sales agreements with Potomac Edison to provide the amount of electricity, up to its PLR retail load (and for certain wholesale contracts), that Potomac Edison may demand during the Maryland transition period, which lasts through December 31, 2004, for commercial and industrial customers and December 31, 2008, for residential customers.

AE Supply is not actively marketing to retail customers in Maryland at this time.

The Maryland PSC in 2000 issued a restrictive order imposing standards of conduct for transactions between Maryland utilities and their affiliates. Among other things, the order restricted sharing of utility employees with affiliates and announced the Maryland PSC’s intent to consider the imposition of a royalty fee to compensate the utility for the use by an affiliate of the utility’s name and/or logo and for other intangible or unquantified benefits. Potomac Edison, along with substantially all of Maryland’s natural gas and electric utilities, filed a petition for judicial review of the restrictive order. After a series of judicial and legislative actions, the Maryland PSC’s order was reversed on procedural grounds. Potomac Edison and the other Maryland natural gas and electric utilities believe that the Maryland PSC’s previous, less restrictive code of conduct is currently in effect in Maryland pending further Maryland PSC action. This code of conduct is similar to those adopted in other jurisdictions and should not create operational constraints. On August 6, 2003, the Maryland PSC began a process of soliciting comments on a new code of conduct proposal.

In December 2001, the Maryland PSC directed electric utilities and interested parties to commence meetings on the status of the provision of default service following the expiration of the various electric companies’ transition periods. As a result of these discussions, the parties, with one exception, filed a settlement agreement with the Maryland PSC, which has been approved. As a result, Potomac Edison will provide PLR service or “standard offer service,” to residential customers through December 31, 2012, and provide standard offer service to other commercial and industrial customers for various periods running as late as December 31, 2008. Wholesale electric supply services necessary to serve these loads (after the expiration of the transition period and before the expiration of the settlement period) would be procured through a competitive bid process. Potomac Edison would be allowed to recover its costs for the services through an administrative charge, including a rate-of-return and taxes. Additional proceedings at the Maryland PSC to implement the settlement agreement are ongoing.

On August 15, 2002, the Maryland PSC opened a case file to consider a complaint by Eastalco against Potomac Edison. In its complaint, Eastalco seeks to continue special contract rates currently in effect until the end of 2004. Potomac Edison exercised provisions of the special contract allowing termination of the special contract rates. The hearing examiner issued a proposed order in favor of Eastalco. Potomac Edison commenced an appeal of the proposed order. On March 7, 2003, Potomac Edison and Eastalco jointly filed an amendment to their electric service agreement with the Maryland PSC which was accepted, resolving the dispute. The terms of the settlement increased the contract rate effective April 1, 2003 and extended the contract term to the end of 2005.

The Ohio General Assembly adopted legislation in 1999 to restructure its electric utility industry and provide retail electric customers the right to choose their electricity generation supplier, starting a transition to market rates. Monongahela’s transition period, or market development period, for large industrial, commercial, and street lighting customers ends December 31, 2003, and the transition period for residential and small commercial customers ends December 31, 2005. Ohio’s residential customers were granted a five-percent reduction in the generation portion of their rates by the legislation for the duration of the market development period. Monongahela has filed a plan to provide standard offer service for its large industrial, commercial, and street lighting customers beyond December 31, 2003, via a competitive bid process similar to the plan approved in Maryland. Monongahela has requested approvals from the PUCO by November 1, 2003, to permit the bid process to be completed for supplies beginning January 1, 2004.

The PUCO issued an order in July 2003, which authorized Monongahela to solicit wholesale bids for generation to serve its industrial, large commercial and street lighting customers. Monongahela issued a Request for Proposal in August 2003, and the bids are due in October 2003. Monongahela will then submit the retail rates resulting from the winning bids to the PUCO for approval.

Under the related regulatory transition plan, Monongahela transferred its Ohio jurisdictional generating assets to AE Supply at net book value in June 2001. Monongahela retained its T&D assets. Monongahela’s T&D rates are capped through 2003 for large commercial customers, industrial customers and street lighting customers, and through 2005 for all other customers, and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates). Monongahela has the responsibility as the provider-of-last-resort for customers who do not choose an alternate supplier or whose alternate supplier does not deliver.

The Electricity Generation Customer Choice and Competition Act (Customer Choice Act) gave all retail electricity customers in Pennsylvania the right to choose their electricity generation supplier as of January 2, 2000. Under the legislation and a subsequent restructuring settlement approved by the Pennsylvania PUC, West Penn transferred its generating assets to AE Supply at book value. The T&D assets are currently owned by West Penn and are subject to traditional regulated utility ratemaking (i.e., cost-based rates). As part of West Penn’s restructuring settlement, West Penn is subject to rate caps on its T&D rates through December 31, 2005, and on its generation rates through December 31, 2008. As directed by the Customer Choice Act, the Pennsylvania PUC is in the process of promulgating rules for PLR service after the transition period ends.

West Penn retains the responsibility as the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver. Pursuant to power sales agreements, AE Supply provides West Penn with the amount of electricity, up to West Penn’s PLR retail load (and for certain wholesale contracts), that West Penn may demand throughout the Pennsylvania transition period.

AE Supply is licensed as an electricity generation supplier, but is not now actively marketing to retail customers in Pennsylvania.

The Virginia State Corporation Commission (Virginia SCC) and its staff continue to evaluate the development of the competitive retail market and have expressed concerns to the Legislative Transition Task Force (LTTF) over the lack of a developing retail market. In an ongoing effort and in reaction to the Virginia SCC’s concerns, the LTTF continues to solicit feedback from the market participants in Virginia. Potomac Edison has provided comments in response to the LTTF’s current and past requests. Potomac Edison has offered a potential solution to enhance market development which received some consideration, but has not been formally pursued by the Virginia SCC or the LTTF.

The Virginia Electric Utility Restructuring Act of 1999 provided for a transition to the choice of electric suppliers for Virginia customers. As of January 1, 2002, Potomac Edison retail electric customers in Virginia have the right to choose their electricity generation supplier.

Potomac Edison transferred all of its Virginia jurisdictional generating assets except certain small hydro facilities to AE Supply in 2000. The hydro facilities were transferred later that year to an affiliate, Green Valley Hydro. The T&D assets are currently owned by Potomac Edison. Potomac Edison’s T&D rates are currently capped through July 1, 2007, however, Potomac Edison will have a one-time opportunity to request a rate adjustment after January 1, 2004, and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates). Potomac Edison has the responsibility as the PLR for those customers of Potomac Edison who do not choose an alternate supplier or whose alternate supplier does not deliver. Pursuant to a long-term power sales agreement, AE Supply provides Potomac Edison with the amount of electricity, up to Potomac Edison’s PLR retail load (and for a certain wholesale contract), that Potomac Edison may demand during the transition period. Virginia’s transition period is anticipated to end on July 1, 2007.

On December 21, 2001, the Virginia SCC approved Phase II of Potomac Edison’s functional separation, providing for unbundled rates, certain internal controls relating to compliance with code of conduct separation requirements, recovery of certain fees in connection with competitive service providers, and other matters.

On July 24, 2001, Potomac Edison filed an application with the Virginia SCC to transfer management and control of its transmission facilities to PJM, under an arrangement known as PJM West. On July 12, 2002, the Virginia SCC staff issued a report observing that Potomac Edison’s application met each of Virginia SCC’s rules for electric utilities to join an RTO. The Virginia SCC has yet to issue a decision on the application. Additionally, the Virginia General Assembly, in its 2003 legislative session, enacted a bill precluding electric utility companies such as Potomac Edison from transferring ownership or control of, or responsibility to operate, any portion of any transmission system located in the Commonwealth prior to July 1, 2004. The effect of this legislation on Potomac Edison and the other Virginia electric company that joined PJM is unclear. Potomac Edison’s transfer of operational control over its transmission facilities to PJM was approved by the FERC on January 30, 2002, and became effective on April 1, 2002.

AE Supply did not renew its Virginia competitive retail electric service provider’s license and allowed it to expire in 2002. AE Supply had no Virginia retail customers in 2002.

In March 1998, the West Virginia Legislature passed legislation directing the West Virginia PSC to determine whether retail electric competition was in the best interests of West Virginia and its citizens. The West Virginia PSC opened a case to investigate retail competition, and submitted an electric restructuring plan to the Legislature for approval. The plan would have introduced full retail competition on January 1, 2001. The Legislature approved the plan but withheld implementation until necessary tax modifications were implemented. The tax modifications were never enacted and the West Virginia PSC has dismissed the electric restructuring proceeding.

In May 2000, Potomac Edison and Monongahela filed an application to transfer their West Virginia generating assets to AE Supply, which the West Virginia PSC approved for Potomac Edison and requested that Monongahela file a separate petition. Potomac Edison’s West Virginia generating assets were transferred in 2000. In August 2000, Monongahela filed a petition seeking the West Virginia PSC’s approval to transfer its West Virginia jurisdictional generating assets to AE Supply. The West Virginia PSC never acted on the Monongahela portion of the petition and Monongahela has agreed to withdraw its petition.

As a result of these developments and the advice of outside counsel, Allegheny has concluded that retail competition and the deregulation of generation is no longer likely in West Virginia. See Note 14 to AE’s consolidated financial statements, for a discussion of the financial reporting effects of this conclusion.

An agreement has been reached and a stipulation was filed in July 2003 with the West Virginia PSC on issues related to the Potomac Edison and Monongahela generating asset transfers, including the amount transferred to AE Supply representing Ohio’s allocated share of Monongahela’s generation. The stipulation also includes a Power Supply Agreement to meet the West Virginia PSC conditions of Potomac Edison’s generation asset transfer to AE Supply, PSC confirmation of EWG status, approval of a potential exchange of like kind generation assets, and an agreement that no party may file a rate case prior to January 1, 2005.

As of December 31, 2002, AE Supply owned or contractually controlled 9,924 MW in the Eastern, Midwestern, and Western regions of the United States, including the contractual right to call up to 1,000 MW in California. On June 26, 2003, AE Supply closed the sale of its 83-MW interest in the Conemaugh power station. On July 31, 2003, it signed a definitive agreement to terminate its rights to call on the California capacity, subject to required termination payments. AE Supply will make this payment in three installments beginning on September 18, 2003. For a further discussion, see—Contractual Rights, Long-Term Purchases and Sales, below. In addition, on July 21, 2003, AE Supply placed three new 180 MW generating units into commercial operation at new facilities in Springdale, Pennsylvania. Accordingly, AE Supply currently owns or controls 9,381 MW of generating capacity. AE Supply manages all of its generating assets as an integrated portfolio with its risk management, wholesale marketing, fuel procurement, and asset optimization activities.

In 2002, Allegheny joined PJM West, and AE Supply reoriented its focus to its core generation business. AE Supply reduced its trading operations and, in 2003, moved its trading operations from New York to Monroeville, Pennsylvania. AE Supply is seeking to concentrate activities to hold positions in support of its generating assets in regions and markets where it has a generating presence. AE Supply is also marketing selected, non-core assets, primarily located outside of the PJM market, including, among other things, the sale of the CDWR contract and associated hedges mentioned below, with a view to generating cash for the reduction of debt.

AE Supply’s focus on being a regional, asset-backed market participant will position Allegheny to compete more effectively in the changing energy markets. Refocusing on its core physical asset base will enable AE Supply to take maximum advantage of its substantial physical presence, operational expertise, and knowledge of regional markets. However, AE and AE Supply’s liquidity positions have rendered portfolio rebalancing difficult, and no assurance can be given that the intended rebalancing will occur. Selling and/or unwinding non-core trading positions will reduce current and follow-on collateral obligations, thereby enhancing AE Supply’s ongoing working capital position. However, AE Supply’s ability to exit such non-core trading positions is subject to Allegheny’s liquidity position, and no assurance can be given that this strategy can be executed in a timely fashion.

PLR Contracts. Pursuant to long-term power sales agreements, AE Supply provides the Distribution Companies with generation service during retail competition transition periods in Pennsylvania, Maryland, Ohio, and Virginia. Under these agreements, AE Supply provides the Distribution Companies with the amount of electricity, up to their PLR retail load and, in certain instances, wholesale load obligations, which they may demand during the transition periods in their states. These agreements under peak load conditions represent a significant portion of the normal operating capacity of AE Supply’s generating assets that were previously owned by Monongahela, Potomac Edison, and West Penn. AE Supply’s power sales agreements with West Penn and Monongahela, with respect to its Ohio customers, and Potomac Edison with respect to its Maryland and Virginia customers have a fixed price, as well as a market-based pricing component. As the amount of electricity AE Supply must deliver under these agreements at fixed rates decreases during the transition periods described above, the amount of electricity that is subject to market prices escalates each year. The transition to market prices will be phased in for the Distribution Companies at different times through 2008, depending upon the state and the customer class.

Exelon Toll. AE Supply entered into a long-term tolling agreement to provide Exelon with the right to call up to 664 MW of capacity and fuel conversion services based on the normal seasonal operating capacity of AE Supply’s Lincoln Generating Facility in Illinois. This contract began in June 2003 and will expire in May 2011.

Under the terms of this agreement, Exelon pays AE Supply fixed monthly capacity payments for the contractual right to call on capacity and energy. This sale was made to hedge the capacity associated with the Lincoln Generating Facility.

Municipal Supply Contracts. AE Supply is the electricity generation supplier for eight boroughs in New Jersey that own and operate electric utilities as departments of municipal governments. These contracts were entered into as part of AE Supply’s previous retail marketing efforts, which have since been concluded. The multi-year contracts, which will supply 150 MW of electricity in the aggregate to the boroughs, began in June 2002 and will run through 2004.

Dominion Energy Marketing. On March 22, 2002, AE Supply entered into a long-term agreement with Dominion Energy Marketing, Inc. The multi-year contract, which provides for the financial settlement of 80 MW of on-peak energy in the New York Independent System Operator and 75 MW of capacity credits, began in August 2002 and will run through July 2009. This transaction was entered into to hedge AE Supply’s exposure under a planned New York barge generation project and tolling agreement. AE Supply has since sought to terminate the agreement relating to the New York barge generation project.

CDWR Contract. In 2001, AE Supply entered into a power sale contract through 2011 with CDWR to hedge certain long-term power purchase commitments included in the assets of Merrill Lynch’s energy trading business, which AE Supply acquired in March 2001. Under this agreement, AE Supply committed to supply the CDWR with annual contract volumes that varied from 150 MW to 500 MW through December 2004. For the last seven years of the contract, the contract volume was fixed at 1,000 MW. AE Supply began delivering power under this agreement in March 2001. The contract contained a fixed price of $61 per megawatt-hour (MWh). In 2002, agencies of the State of California initiated legal processes in an attempt to abrogate the power sale agreements. On June 10, 2003, AE Supply and CDWR agreed to renegotiated terms and conditions. The litigation and subsequent settlement agreement is discussed in this report under ITEM 3. LEGAL PROCEEDINGS. The renegotiated contract reduced the price for off-peak hour power supply and reduced the contract volumes (from 1,000 MW to 750-800 MW from 2005 - 2011). The modifications substantially reduced the value of the contract.

In September 2003, Allegheny sold the contracts, and associated hedge transactions, to J. Aron & Company for approximately $354 million. See—Recent Events—Allegheny’s Response, above for a further description of the sale.

BGE Supply Contract. AE Supply was party to a contract with BGE, under which AE Supply was to provide BGE with 10 percent of BGE’s PLR obligations from July 2003 through June 2006. This amount was estimated to range from 200 MW to 530 MW per year. In June 2003, AE Supply negotiated an agreement to transfer the entire contract, and its related power purchase hedges with BGE, to Constellation Power Source for a net cash outflow, including reduction of collateral previously posted with BGE, of approximately $2.5 million. The FERC approved the transaction on June 24, 2003, and it closed on June 26, 2003.

AE Supply entered into the agreements described below as part of the implementation of its previous business model to grow AE Supply’s portfolio, including in the Western United States. As noted below, Allegheny has terminated certain of these transactions and is evaluating the potential to unwind certain of the remaining commitments.

Dominion Transmission Transportation Contract. AE Supply has a long-term agreement with Dominion Transmission, Inc., for the transportation of natural gas starting June 1, 2003, under a tariff approved by the FERC. This agreement provides for the firm transportation of 95,000 MMBtu of natural gas per day through May 31, 2013, from Oakford, Westmoreland County, Pennsylvania to Springdale, Pennsylvania. This transportation agreement was purchased for natural gas deliveries at AE Supply’s new combined-cycle plant in Springdale, Pennsylvania.

Equitable Gas Transportation Contract. AE Supply has a long-term agreement with Equitable Gas Company, a division of Equitable Resources, Inc., for the transportation of natural gas, starting March 11, 2003, under a tariff approved by the FERC. This agreement provides for firm transportation of 90,000 MMBtu of natural gas per day through December 31, 2012, from Equitable Gas Company (Greene County, Pennsylvania) to Hatfield’s Ferry Power Station. This transportation agreement was purchased for anticipated natural gas deliveries associated with natural gas reburn opportunities at the Hatfield’s Ferry Power Station in Pennsylvania. Natural gas reburn provides another alternative for AE Supply to reduce NO_x emissions at Hatfield’s Ferry Power Station by using natural gas, when economical relative to other NO_x management activities, instead of coal for a portion of the generating station’s anticipated fuel requirements.

Williams Toll. AE Supply and Williams were parties to a tolling agreement under which AE Supply had a long-term contractual right to call on a daily basis up to 1,000 MW of natural gas-fired generating capacity in California through May 2018. Monthly fixed-price capacity payments were to be made to Williams for these contractual rights. When AE Supply exercised these contractual rights, additional payments were to be made to Williams based on predetermined natural gas-to-electricity conversion rates. The tolling agreement with Williams was purchased as part of AE Supply’s acquisition of the energy trading business from Merrill Lynch in March 2001. In July 2003, AE Supply entered into a conditional agreement with Williams to terminate the tolling agreement. Under the agreement, AE Supply made an initial payment to Williams of approximately $2.4 million to satisfy certain amounts under a related hedge agreement. Under the terms of the termination agreement, Allegheny paid to Williams $100 million on September 18, 2003 after the closing of its sale of the CDWR contract. Allegheny is also required to make two payments of $14 million to Williams, in March and September of 2004. The tolling agreement will terminate when the final $14-million payment is made.

LV Cogen Toll. In May 2001, AE Supply entered into a 15-year agreement with LV Cogen to control 222 MW of generation capacity from a natural gas-fired, combined-cycle generating facility in Las Vegas, Nevada. This facility began operation in January 2003. The tolling agreement with LV Cogen was entered into to complement AE Supply’s overall position in the Western United States. In August 2003, AE Supply entered into an agreement to terminate its tolling agreement with LV Cogen. Under the agreement, Allegheny made a $114-million payment to the LV Cogen on September 22, 2003 after the closing of its sale of the CDWR contract.

El Paso Transportation Contract. AE Supply currently has a long-term agreement with El Paso Natural Gas Company (El Paso) for the transportation of natural gas that began June 1, 2001, under tariffs approved by the FERC. This agreement provides for the firm transportation of gas from western Texas and northern New Mexico to the southern California border and was purchased for anticipated natural gas deliveries at the LaPaz combined-cycle generating facility in Arizona, a project which has since been cancelled by AE Supply. AE Supply has released this capacity to a third party on a short-term basis, for which it is receiving payments to partially offset the remaining capacity charges.

Kern River Transportation Contract. AE Supply has a long-term agreement with Kern River for the transportation of natural gas, starting May 1, 2003, under a tariff approved by the FERC. This agreement provides for firm transportation of 45,122 Mcf of natural gas per day through April 30, 2018, from Opal, Wyoming, to southern California. This transportation agreement was purchased for anticipated natural gas deliveries into southern California and at the LV Cogen combined-cycle generating facility in Nevada.

All of the Distribution Companies’ Ohio, Maryland, Pennsylvania, and Virginia customers have the ability to choose their electricity generation suppliers. In 2002, approximately 0 percent, 0 percent, and 0.2 percent of Monongahela, Potomac Edison, and West Penn’s respective regulated customer base were customers of competing electricity generation suppliers. The corresponding percentages in 2001 were approximately 0 percent, 0 percent, and 0.2 percent for Monongahela, Potomac Edison, and West Penn, respectively.

The Distribution Companies recognize revenue from power transmission in addition to distribution. To the extent a competitor supplies power along the transmission grid of a distribution company, the distribution company will assess a delivery charge. The Distribution Companies have ceded operational control over their transmission assets to PJM. It is not expected that this change in control will adversely affect grid reliability or lead to short-term increases in capital expenditures related to transmission assets. PJM’s control of the grid is intended to limit or eliminate pricing advantages related to grid control.

On March 15, 2001, the Distribution Companies proposed to comply with the FERC’s requirement in Order 2000 by joining PJM through the PJM West arrangement. The filing represented a collaboration between the Distribution Companies, PJM, and numerous stakeholders. The Distribution Companies and PJM asked the FERC to confirm that PJM West satisfies the FERC’s requirements for an RTO as set forth in Order 2000. For a further discussion, see—Regulatory Framework Affecting Allegheny—Federal Initiatives, above.

The Distribution Companies also asked the FERC to accept certain transmission rate surcharges so that the Distribution Companies would not suffer a loss in revenues when PJM West became operational and to recover certain PJM West start-up costs. This included a transmission revenue neutrality charge, which allows the Distribution Companies to collect $85 million of revenues through 2004 that would otherwise have been lost as a result of joining PJM, as well as start-up costs associated with the integration of the Distribution Companies into the PJM market. Collection of the revenue neutrality charge and start-up costs will continue until such time as the full $85 million has been recovered. The Distribution Companies also adopted PJM’s transmission pricing methodology, including PJM’s congestion management system. In addition, PJM expanded its day-ahead and real-time energy markets to include PJM West. As a result, energy suppliers are now able to reach consumers anywhere within the expanded PJM/PJM West market at a single transmission rate under the PJM open access tariff. On January 30, 2002, the FERC authorized the Distribution Companies and PJM to proceed with PJM West. On April 1, 2002, the Distribution Companies turned functional control of their transmission facilities over to PJM, via the PJM West arrangement. The FERC subsequently issued an order accepting the Distribution Companies’ offer of settlement on July 23, 2002, which resolved all issues concerning the Distribution Companies’ revenue neutrality surcharge. Accordingly, the Distribution Companies are authorized to recover the revenue neutrality surcharge as described above.

The PJM West region is continuing to expand to include the New PJM Companies. The Distribution Companies were involved in transmission rate negotiations with the New and existing PJM Companies (New PJM Footprint) to ensure that the revenue neutrality provisions and PJM West start-up costs granted by the FERC would continue to be recovered. The Distribution Companies, PJM, and the New PJM Companies filed an agreement with the FERC, which included a rate mechanism to protect the Distribution Companies against this risk of lost transmission revenues by modifying the revenue neutrality charge. On April 1, 2003, the FERC accepted the filings of the New PJM Companies to join PJM, effective as of the date of the transfer of control of facilities to PJM. The rates were suspended for a nominal period and are the subject of ongoing settlement negotiations.

The Distribution Companies are involved in transmission rate negotiations to eliminate transmission charges for transactions between the Midwest Independent System Operator (MISO) and the New PJM Footprint, as ordered by the FERC to begin on November 1, 2003. The Distribution Companies are again involved to ensure that the revenue neutrality provisions and PJM West start-up costs granted by the FERC will continue to be recovered. The FERC allowed the parties the ability to file for a transitional rate mechanism to collect lost revenues for up to two years, which is being negotiated between the parties. Allegheny is reviewing all options, while considering other activities and initiatives within PJM, to fully recover its transmission revenue requirement in future years. It is expected that a rate filing will be a part of that process. PJM and the MISO published a paper on a congestion management seams issue that addresses coordination of seams between the New PJM Footprint and the MISO. PJM and the MISO are also currently negotiating a Joint Operating Agreement to address Inter-regional Coordination and plan to investigate the issues surrounding the expanded market.

Allegheny, through the operations of Monongahela, is also active in the regulated natural gas business. AE’s 2002 revenues from its regulated natural gas operations amounted to less than 10 percent of its total 2002 consolidated operating revenues. Beginning in 1992, the FERC required pipeline operators to separate the cost of the transported natural gas from the cost of the transportation service and to provide comparable transportation service to all shippers whether they purchased natural gas from the pipeline operator or from another natural gas seller. As a result, Monongahela’s natural gas division and subsidiary local distribution company, Mountaineer, are required to obtain their natural gas supplies directly from producers and marketers and arrange for a pipeline to transport this natural gas to Monongahela’s facilities in West Virginia. In addition, residential unbundling at the state level is well under way nationwide and may provide the opportunity for small commercial firms and residential customers to purchase their own natural gas supplies in a competitive market. Mountaineer has been an open access transporter under its state tariff since the mid-1980s, allowing residential, commercial, industrial, and wholesale customers to acquire their own natural gas supplies and requiring Mountaineer to transport the natural gas to these customers. More recently, the FERC expanded opportunities for firm holders of pipeline capacity to resell or release their capacity to other shippers and required pipeline operators to permit shippers to use flexible receipt and delivery points. In 2000, the FERC issued Order 637 to provide pipeline shippers with the right to segment or sub-divide their capacity entitlements for their own use or for release to replacement shippers, eliminate the price cap on released pipeline capacity, clarify the rights of shippers to take service at secondary delivery points, and establish new rules for managing shipper imbalances on the pipelines.

Mountaineer has been a very active participant in the capacity release market on two interstate pipeline systems: Columbia Gulf Transmission Company and Columbia Gas Transmission Corporation. Releasing capacity allows Mountaineer to defray pipeline demand charges. Conversely, the increased service flexibility available to all shippers may increase the demand for pipeline capacity, potentially making it more costly for Mountaineer to access additional capacity to serve new customers.

In 1990, the New York Mercantile Exchange (NYMEX) established a natural gas futures market. While neither Mountaineer nor Monongahela purchase contracts directly from NYMEX, many of their contracts are based on NYMEX prices. If NYMEX prices for natural gas futures increase, Mountaineer’s and Monongahela’s financial results could be adversely affected if they are unable or otherwise not permitted to recover reconciling rates from their customers.

Allegheny Ventures engages in unregulated activities such as telecommunications and unregulated energy-related projects. Allegheny Ventures has two principal subsidiaries, ACC and AE Solutions. ACC develops fiber-optic projects, including fiber and data services, and AE Solutions manages energy-related projects.

Neither AE Supply nor any of the other registrants employs directly any employees, other than a small number of employees retained by AE Supply who are associated with the Lincoln Generating Facility, which AE Supply acquired in 2001. All of the registrant’s officers and employees are employed by AESC. As of September 15, 2003, AESC employed approximately 5,300 employees. Approximately 1,570 of these employees are subject to collective bargaining arrangements. Approximately 80 percent of the unionized employees are at the Distribution Companies and approximately 20 percent are at AE’s other subsidiaries. Approximately 1,110 employees are represented by System Local 102 of the Utility Workers Union of America (UWUA). There are approximately 80 employees represented by other locals of the UWUA; approximately 190 are represented by locals of the Paper, Allied-Industrial, Chemical, and Energy Workers International Union; and approximately 190 are represented by locals of the International Brotherhood of Electrical Workers. The current collective bargaining arrangements expire at various dates from the first quarter of 2005 to the last quarter of 2007. Each of the registrants believes that current relations between it and its unionized and non-unionized employees are satisfactory.

The operations of the Allegheny-owned facilities, including generating stations, are subject to regulation as to air and water quality, hazardous and solid waste disposal, and other environmental matters by various federal, state, and local authorities.

The cost of meeting known environmental standards is provided in —Construction and Other Capital Expenditures, above. Additional legislation or regulatory control requirements have been proposed and, if enacted, will require modifying, supplementing, or replacing equipment at existing stations at substantial additional cost.

Allegheny currently meets applicable standards as to particulate emissions at its power stations through high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, and, at times, reduction of output. From time to time, minor excursions of stack emission opacity, that are normal to fossil fuel operations, are experienced and are accommodated by the regulatory process.

Allegheny meets current emission standards as to SO₂by the use of scrubbers, the burning of low-sulfur coal, the purchase of cleaned coal to lower the sulfur content, and the blending of low-sulfur with higher sulfur coal.

The CAAA, among other things, require an annual reduction in total utility emissions within the United States of NO_xand SO₂. In an effort to introduce market forces into pollution control, the CAAA created SO₂ emission allowances. Each allowance is an authorization to emit one ton of SO₂ into the atmosphere. Subject to regulatory limitations, allowances may be sold or banked for future use or sale. Allegheny has received allowances each year since the enactment of the CAAA. As part of its compliance strategy, Allegheny continues to study, and, where appropriate, participate in the allowance market, making sales or purchases of allowances or participating in allowance transactions.

Allegheny estimates that its banked allowances will allow it to economically comply with SO₂ limits through 2004 and possibly beyond. Studies are ongoing to evaluate cost-effective options to comply with SO₂ limits, including those available in connection with the emission allowance trading market. Burner modifications at most of the Allegheny-operated stations satisfy the NO_x emission reduction requirements for the acid rain (Title IV) provisions of the CAAA. Additional NO_x reductions, which require Selective Catalytic Reduction and/or other combustion or post-combustion control technologies, have been mandated in Maryland, Pennsylvania, and West Virginia for ozone nonattainment reasons.

The EPA has issued a NO_x State Implementation Plan (SIP) call rule that requires the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Maryland, Pennsylvania, and West Virginia, beginning in May 2003. Allegheny’s compliance with such stringent regulations has required and will require the installation of expensive post-combustion control technologies on most of its power stations. During 2000, Pennsylvania and Maryland promulgated final rules to implement the EPA’s NO_x SIP call requirements, beginning in May 2003. During 2001, the West Virginia Department of Environmental Protection issued a final rule to implement the EPA’s NO_x SIP call requirements, beginning in May 2004. The EPA approved the West Virginia SIP in July of 2002. The EPA’s NO_x SIP call had been subject to litigation but, in 2000, the D.C. Circuit Court of Appeals issued a decision that upheld the regulation. The court issued a subsequent order that postponed the initial compliance date of the NO_x SIP call from May 2003 to May 2004. Maryland and Pennsylvania did not delay the May 2003 implementation dates of their respective SIP, nor are they legally required to do so. AE Supply and Monongahela are in the process of installing NO_x controls to meet the Pennsylvania, Maryland, and West Virginia SIP. These NO_x controls include the installation of Selective Catalytic Reduction at Harrison Power Station and Pleasants Power Station. The NO_xCompliance Plan was established on a system-wide basis much the same as was the SO₂ Compliance Plan. The overcompliance at Harrison and Pleasants Power Stations permit excess NO_x emissions at other AE stations. AE also has the option to purchase, in some cases, alternate fuels, NO_x allowances, or power on the market, if needed, to supplement our compliance strategy. AE Supply and Monongahela expects to be in compliance with NO_x limits established by the SIP.

From time to time, Allegheny is required to engage in substantial site-specific modifications to generating assets in response to federal or state regulatory action. Although they may be reactivated at any time, proceedings with respect to specific generation facilities in Pennsylvania and West Virginia have been dormant for many years. Capital outlays necessary to meet regulatory requirements can be substantial.

In August 2000, AE received a letter from the EPA under its NSR initiative requiring it to provide information and documentation relevant to the operation and maintenance of 10 electric generating stations. AE Supply and Monongahela own these electric generating stations. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements. For further information about this inquiry, see ITEM 3. LEGAL PROCEEDINGS—Clean Air Act and CAAA Matters.

The EPA promulgated revisions to particulate matter and ozone standards in July 1997. Litigation over the revised particulate matter and ozone standards has recently been resolved and these requirements could impose substantial costs on Allegheny. Allegheny does not anticipate final regulations before 2008-2009. The EPA has also promulgated final regional haze regulations to improve visibility in national parks and wilderness areas, which is currently under litigation. The effect on Allegheny of these standards or regulations is unknown at this time, but could be substantial.

In December 2000, the EPA made a determination for the regulatory controls of power plant mercury emissions. The regulatory determination did not include any recommendations regarding the level or timing of reductions. However, the EPA plans to finalize a maximum achievable control technology standard by December 2004. Based on this schedule, it is unlikely implementation of mercury controls would be required before 2007-2008.

The Kyoto Protocol, signed by the Clinton Administration, but not ratified by the U.S. Senate, would require drastic reductions in greenhouse gas emissions in the United States in response to the perceived threat of global warming. If ratified and implemented, this treaty would likely require extensive mitigation efforts on the part of Allegheny to reduce greenhouse gas emissions at electric generating plants and would raise considerable uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generating facilities. While the Bush Administration has rejected the Kyoto Protocol, other developed countries in the world are expected to ratify it and abide by its terms, beginning in 2008. The Bush Administration has proposed voluntary programs to reduce greenhouse gas intensity over the next decade, and various legislative proposals are under consideration at the federal and state level.

Allegheny has taken voluntary steps to address the issue of global climate change. It has signed a Memorandum of Understanding (for the years 1995 to 2000) with the U.S. Department of Energy to participate in the Climate Challenge. As part of this agreement, Allegheny has supported the Climate Challenge initiatives in cooperation with other companies through the Edison Electric Institute and continues to explore alternatives, including a carbon sequestration through a pilot project to revegetate a former surface mine site in western Pennsylvania. The ultimate outcome of the global climate change debate and the Kyoto Protocol could have a significant effect on the industry in general and, on Allegheny, in particular.

Allegheny also participates in an active climate-related research program and is responsive to the voluntary guidelines suggested in EPACT that are directed toward reducing, controlling, avoiding, and sequestering greenhouse gases. Examples of these efforts include commercial-scale projects to use biomass as a renewable fuel source at two of Allegheny’s coal-fired power stations. Allegheny has taken steps to reduce greenhouse gases and help stimulate a business climate that encourages improved efficiency, performance, electrical loss reductions, and cost effectiveness.

During the 107^th Congress, President Bush’s Clear Skies Initiative was introduced in both the U.S. House of Representatives and Senate. The legislation is intended to eliminate Title IV of the CAAA and replace it with provisions designed to take a comprehensive and integrated approach to air emissions regulation. The legislation was reintroduced in the 108^th Congress. The Clear Skies Initiative and expected alternative legislation are likely to be the focus of committee action on multi-emission legislation. The Clear Skies Initiative does not include carbon reductions, but focuses on SO₂, NO_x, and mercury. Hearings on multi-emissions legislation have been held in both the Senate and the House, but subsequent legislative activity, if any, is uncertain.

Under the National Pollutant Discharge Elimination System (NPDES), permits for all of Allegheny’s stations and disposal sites are in place and all facilities are generally in compliance with all permit terms, conditions, and effluent limitations other than as described in “Penalties and Noncompliance” below. However, as permits are renewed, more stringent permit limitations are often applied. To date, Allegheny has either successfully developed and scientifically justified to the satisfaction of the regulatory agencies, alternate site-specific water quality criteria or has installed passive constructed wetland treatment technology, thus avoiding significant capital costs and potential liabilities of advanced wastewater treatment. However, there is significant activity at the federal level on CWA issues. The results of several pending long-term initiatives could cause Allegheny and its customers to incur material and substantial costs.

There are pending rulemakings, for example, regarding the Total Maximum Daily Load (TMDL) Program, water quality standards, antidegradation review, human health and aquatic life water quality criteria, mixing zones, and CWA Section 316(b) Cooling Water Intake Structure. In addition, the EPA is developing new policies concerning protection of endangered species under the CWA and imposition of new CWA requirements to address sediment and biological water quality criteria contamination. The outcome of these rulemakings will fundamentally change the traditional water quality management program from a chemical-specific control of

point sources to comprehensive and integrated watershed management. This regulatory shift will result in more restrictions on facility discharges, as well as nonpoint source runoff, resulting from land use practices such as agriculture and forestry, and will ultimately address water quality impairment caused by atmospheric deposition.

Over the past several years, TMDLs have become a significant issue. Consent orders in West Virginia and Pennsylvania require development and implementation of waste loads for point sources and load allocations for nonpoint sources on numerous waterbodies not currently meeting water quality standards within a relatively short time frame (12 years). Because of the scientific complexity of the issue, paucity of water quality data, resource limitations of the state agencies, and political considerations, it is likely that resulting TMDLs will require a disproportionate reduction in point source versus nonpoint source discharges. The direct result of the TMDLs will be further reductions in the amount of pollutants permitted to be discharged by Allegheny-owned power stations located on water quality-impaired rivers. TMDLs can adversely affect Allegheny by prohibiting new or increased discharges and curtailing the wastewater discharges of its industrial customers.

The EPA intends to make revisions to the TMDL rule or may revise the currently effective regulations, implementing the TMDL program to achieve the goals of the CWA. Currently, the regulations that the EPA promulgated in 1985 and amended in 1992 remain in effect for the TMDL program. It is likely that water quality trading provisions will be incorporated into any new TMDL rule as a means to assist states in more cost-effective implementation of TMDLs. The full effect of the rule on Allegheny and its customers will not be known until the final rule is promulgated and the states complete TMDL development and implementation on impaired waters over the next 15 years. The states continue to develop TMDLs under the existing rule, and Allegheny is working with a number of watershed TMDL stakeholder groups, state agencies, and the EPA to ensure development of sound and equitable TMDLs.

Current initiatives regarding rules applicable to cooling water intake structures are of concern to Allegheny.

The CWA requires that cooling water intake structures reflect the best technology available for minimizing adverse environmental effects. The EPA is subject to a consent decree, which requires it to implement rules in this area in three phases:

1. Phase I applies to new facilities that employ a cooling water intake structure. The Phase I final rule was published in December 2001;

2. Phase II pertains to existing utilities and nonutility power producers that currently employ a cooling water intake structure and whose flow exceeds a minimum threshold. A proposed rule was published in the Federal Register on April 9, 2002, with final action to be taken by February 16, 2004; and

3. Phase III will govern existing facilities that employ a cooling water intake structure not covered by the Phase II rule (pulp and paper, chemical plants) and whose intake flow exceeds a minimum threshold that will be determined by the EPA. The proposal is due by November 1, 2004, with final action on June 1, 2006.

The Phase I new facility rule applies to all new generation companies that began construction after January 18, 2002. It requires cooling towers for all new power plants in addition to limits on intake velocity, percentage of the waterbody used, and, in most cases, additional intake screens or other protective measures which are largely unspecified and may include fine-mesh screens, wedgewire screens, or fabric barriers, along with extensive site-specific study and monitoring requirements. If the proposal stands, new facilities will suffer severe siting restrictions and will be subject to costly environmental studies and time delays to accomplish the studies. Moreover, the precedent-setting effect that the new facility rule would have on existing facilities could be significant, potentially requiring additional environmental studies and possibly even the installation of cooling towers on those facilities that are shown to be causing an adverse environmental effect. Specific units could be

forced to accept overall flow volume and velocity restrictions in water usage that could lead to derating units and undesirable energy supply reductions.

Due to the concerns stated above, as well as the precedent-setting potential of the forthcoming existing facility rule, the Utility Water Act Group filed a petition for review of the new facility rule with the D.C. Circuit Court of Appeals. Several environmental groups also filed suit on the rule in the Second Circuit Court of Appeals. Because multiple parties have brought litigation on the same rule, the lawsuit will be consolidated in one of the circuit courts.

The proposed Phase II rule applies to all existing facilities with cooling water intakes that withdraw more than 50 million gallons of water a day. The rule would require subject facilities to reduce impingement mortality (when fish become stuck on the cooling water intake screens) by 80-95 percent and, for most plants (except facilities on lakes or a few plants on very large rivers or with low utilization), reduce entrainment of fish (the smaller aquatic life that passes through the screens and enters the system) by 60-90 percent. This new regulation is one-size-fits-all and will impact all power plants with once-through cooling. The reduction is from a calculated baseline, which is based on a plant with an intake capacity commensurate with a once-through cooling water system and with no impingement and/or entrainment reduction controls. If one can demonstrate that the costs of meeting these reduction standards is significantly greater, compared to the benefits, or to the costs the EPA assumed in the rule making, then a site-specific analysis may be performed rather than installing reduction technologies. In any event, when applying for a permit a Comprehensive Demonstration Study must be conducted and at least two years of monitoring data collected to verify the full-scale performance of the proposed or implemented technologies. Allegheny would be required to perform these studies at a minimum of six of its power plants. Depending on requirements in the final regulation and the findings of the Demonstration Studies, cooling towers and other mechanical means of reducing impingement/entrainment may also be required. Three of the plants are owned solely by AE Supply and three are jointly owned by AE Supply and Monongahela.

In 2001, the Pennsylvania Department of Environmental Protection (PADEP) issued a draft NPDES permit for Mitchell Power Station. The draft permit proposed to drastically lower the facility’s thermal discharge limits. Cost estimates to achieve compliance with the proposed thermal limitations could be significant depending on final limitations and installation costs. These costs would be incurred over a minimum of two years. Extensive comments were filed questioning the legality of the limits. The PADEP has yet to respond to Allegheny’s comments or issue the final permit. Until then, Mitchell will continue to operate under the requirements of its current NPDES Permit.

The EPA lowered the maximum contaminant level (MCL) drinking water standard for arsenic from 50 to 10 micrograms per liter (ug/l). Because arsenic is a naturally occurring trace element present in the Earth’s crust, as well as in coal and coal combustion products, and because MCLs are used in other regulatory programs (such as groundwater protection, hazardous waste classification, and brownfield cleanup programs), Allegheny may incur increased compliance costs as these regulatory programs adopt the new standard. The full effect of this action on Allegheny will not be known until it is determined how the various federal and/or state regulatory programs implement the new standard.

The EPA promulgated new Spill Prevention Control and Countermeasures (SPCC) regulations, which became effective August 16, 2002. The timeline for compliance with the new SPCC regulations requires that all plans be amended by August 17, 2004, and implemented as soon as possible, but not later than February 18, 2005. SPCC regulations establish procedures, methods, and equipment to prevent the discharge of oil from nontransportation-related facilities into or upon the navigable waters of the United States. Navigable waters include all types of waterways such as lakes, streams, and rivers, as well as areas such as wetlands, ponds, and tributaries. These regulations will affect all Allegheny-owned facilities to varying degrees.

Pursuant to the Resource Conservation and Recovery Act of 1976 and the Hazardous and Solid Waste Management Amendments of 1984, the EPA regulates the disposal of hazardous and solid waste materials. Maryland, Ohio, Pennsylvania, Virginia, and West Virginia have also enacted hazardous and solid waste management regulations that are as stringent as or more stringent than the corresponding EPA regulations.

Allegheny is in a continual process of either permitting new or repermitting existing disposal capacity to meet future disposal needs. All disposal facilities are currently operated in material compliance with their permits.

In addition to using coal combustion by-products (CCBs) in various power plant applications such as scrubber by-product stabilization at the Harrison and Mitchell Power Stations, AE Supply on its own behalf and on behalf of Monongahela continues to expand its efforts to market CCBs for beneficial applications, thereby reducing landfill requirements. In 2002, AE Supply and Monongahela received approximately $1 million from the external sale and use of approximately 725,000 tons of fly ash, 225,000 tons of bottom ash, 19,000 tons of boiler slag, and 515,000 tons of flue-gas desulfurization (FGD) material. These CCBs were beneficially used in applications such as cement replacement in ready-mix concrete, anti-skid materials, grit blasting material, mine reclamation, mine subsidence, structural fills, and grouting of mines and oil wells. In addition, AE Supply and Monongahela built a processing plant that converts the FGD by-product from the Pleasants Power Station into a commercial grade synthetic gypsum material that is used in the manufacture of wallboard. This process significantly reduced the amount of the by-product going to an impoundment.

From time to time, the registrants are assessed penalties for noncompliance with applicable air and water quality and waste discharge laws and regulations. In addition, the registrants may elect or be required to undertake remedial actions, which can result in substantial costs. During 2002, Allegheny facilities violated NPDES permit requirements 51 times. Regulators may assess fines or other penalties or remedial measures. Each registrant is of the belief that no pending penalty assessments or asserted required remediation efforts applicable to the registrant will result in material costs to the registrant. The West Virginia Division of Air Quality issued two Notice of Violation/Cease and Desist Orders, dated August 5, 2002 and September 12, 2002, for opacity violations at Pleasants Power Station. An opacity study was conducted and a final report, dated May 2003, was submitted to the agency for its review. No further action regarding this issue has been taken. In addition, there have occasionally been particulate fallout incidents at Pleasants Power Station. Although measures have been taken to correct the problem, it may eventually become necessary to close the scrubber bypass and construct a new stack, resulting in a significant capital expenditure for AE Supply and Monongahela, joint owners of the station. See ITEM 3. LEGAL PROCEEDINGS for a description of litigation involving environmental laws and regulations.

Beginning in 2003, AE’s research and development activity is conducted exclusively by AE Supply in support of AE, AE Supply, Monongahela, and AGC’s power generation activities (that is, the Generation and Marketing segment). Historically, research and development was also undertaken on behalf of the Distribution Companies in support of their generation activities, however, the Distribution Companies’ generating assets (other than Monongahela’s West Virginia jurisdictional generating assets) have been transferred to AE Supply. The Distribution Companies and AE Supply collectively spent $7.2 million in 2002, $7.1 million in 2001, and $6.4 million in 2000 for research programs. Of these amounts, $5.1 million, $4.5 million, and $4.8 million were for Electric Power Research Institute (EPRI) dues in 2002, 2001, and 2000, respectively. EPRI is an industry-

sponsored research and development institution. AE Supply plans to spend approximately $.7 million for research in 2003. The Distribution Companies do not anticipate spending any significant amount on research in 2003. Allegheny’s EPRI membership has been suspended for 2003. In addition to EPRI support, in-house research conducted by AE Supply in 2002 concentrated on technology-based issues such as products and services for environmental control, generating unit performance, alternative fuels, clean coal technology developments, combustion turbine monitoring, operator training, environmental effects and regulatory issues, future generation technologies, use of CCBs, clean power technology (which includes both power quality technology and distributed generation technology for customers), delivery systems equipment, and sustainable energy technologies.

Research is also being directed to address major issues for AE Supply and the entire electric industry. These include issues relating to greenhouse gas emissions, waste disposal and discharges to land, water and air, renewable energy resources, fuel cells, new combustion turbines, and new product development venture opportunities. The use of biomass for co-firing is being developed at two Allegheny power stations by directly firing sawdust. The use of biomass results in lower emissions of NO_x, SO₂, particulate matter, and greenhouse gases. Research is being conducted to determine whether biomass can be used in existing power stations as a renewable energy resource at a competitive production cost.

Substantially all of the properties of Monongahela and Potomac Edison are held subject to the lien of indentures securing their first mortgage bonds. Certain of the properties and other assets of AE Supply, as well as of Monongahela, that were financed by solid waste disposal and pollution control notes are subject to liens securing the obligations under those notes. Substantially all of AE Supply’s properties are subject to liens of various relative priorities securing debt obligations, consisting of approximately $1.4 billion of bank debt and $344 million of notes that were restructured in February 2003. In addition, AE Supply’s new generating facilities in Springdale, Pennsylvania are subject to liens securing bank obligations of approximately $270 million. In many cases, the properties of Monongahela, Potomac Edison, West Penn, and AE Supply may be subject to certain reservations, minor encumbrances, and title defects which do not materially interfere with their use. The indenture, under which AGC’s unsecured debentures are issued, prohibits AGC, with certain limited exceptions, from incurring or permitting liens to exist on any of its properties or assets unless the debentures are contemporaneously secured equally and ratably with all other indebtedness secured by the lien. T&D lines, in substantial part, some substations and switching stations, and some ancillary facilities at power stations are on lands of others, in some cases by sufferance but, in most instances, pursuant to leases, easements, rights-of-way, permits, or other arrangements, many of which have not been recorded and some of which are not evidenced by formal grants. In some cases, no examination of titles has been made as to lands on which T&D lines and substations are located. Each of the Distribution Companies possess the power of eminent domain with respect to its public utility operations.

Provided under ITEM 1. BUSINESS—Electric Facilities and elsewhere throughout ITEM 1. are descriptions of Allegheny’s operating properties. Allegheny’s principal Corporate Headquarters is located in Hagerstown, Maryland, in a building that is owned by Potomac Edison. Allegheny also has corporate centers located in Greensburg, Pennsylvania and Fairmont, West Virginia, in buildings owned by West Penn and Monongahela, respectively. AE Supply’s corporate offices are leased and located in Monroeville, Pennsylvania. Additional ancillary offices exist throughout the Distribution Companies’ service territory.

MGS owns more than 300 natural gas wells, and has net revenue interest in about 100 additional wells, located throughout West Virginia, and has active leaseholds that cover more than 86,000 acres. In addition to its production assets, MGS owns approximately 125 miles of high-pressure transmission facilities running from Jackson County, West Virginia, west to Huntington (Cabell County), West Virginia, where it terminates at various delivery locations into the facilities of Mountaineer, Columbia Gas, and the industrial plant facilities of various industrial end-users, and approximately 400 miles of gathering lines located in the same general vicinity.

In March and April 2001 AE Supply entered into two 10-year power sales agreements pursuant to a master power purchase and sale agreement (together, the CDWR contract) with CDWR, the electricity buyer for the State of California. The CDWR contract constituted one of Allegheny’s key assets. In February 2002, the California Public Utilities Commission (California PUC) and the California Electricity Oversight Board (CAEOB) filed complaints with the FERC seeking to abrogate the contracts. In January 2003, the CDWR filed a lawsuit in California Superior Court alleging that AE Supply breached the contracts, and seeking a judicial determination that the contracts were terminated along with monetary damages.

On June 10, 2003, AE Supply and CDWR entered into a settlement agreement with renegotiated terms and conditions of the CDWR contract. The settlement reduces the off-peak power prices payable by CDWR under the contract from $61 per MWh from 2004 to 2011 to $60 in 2004, $59 in 2005 and $58 in 2006 through 2011. The settlement terms also reduce the volume of power to be purchased from 1,000 MW from 2005-2011 to 750 MW in 2005 and 800 from 2006 through 2011. The renegotiated contract also states that the parties waive all rights to challenge the validity of the agreement or whether it is just and reasonable for its duration. These modifications significantly reduced the value of the CDWR contract, in the range of $160-$190 million. The terms of the settlement also provide that the California PUC and CAEOB agree to drop their complaints against AE Supply at the FERC, and CDWR and the California Attorney General agree to drop their lawsuit filed in California Superior Court. The parties agreed that all litigation would be withdrawn with prejudice.

The settlement agreement has been approved by the CPUC. The FERC issued an order approving the settlement on July 11, 2003. On August 15, 2003, the CDWR filed a notice of entry of dismissal with prejudice with the California Superior Court in Sacramento, and the clerk of the court entered the dismissal as requested.

Nine related putative class action lawsuits against AE Supply, and more than two dozen other named defendant power suppliers were filed in various California superior courts during 2002. These class action suits were removed to federal court and transferred to the U.S. District Court for the Southern District of California. Eight of the suits were commenced by consumers of wholesale electricity in California. The ninth, Millar v. Allegheny Energy Supply Co., et al., was filed on behalf of California taxpayers. The complaints allege, among other things, that AE Supply and the other defendant power suppliers violated California’s antitrust statute and the California unfair business practices statute by allegedly manipulating the California electricity market over a period of years. The suits also challenge the validity of various long-term power contracts with the state of California, including the CDWR contract.

On August 25, 2003, AE Supply’s motion to dismiss seven of the eight consumer class actions with prejudice was granted by the U.S. District Court. AE Supply has not been served in the eighth consumer class action, Kurtz v. Duke Energy Trading and Marketing, LLC. This case is still pending in the U.S. District Court. The allegations in this complaint are substantively identical to those in the dismissed actions.

The District Court separately granted plaintiffs’ motion to remand in the taxpayer action, Millar, on June 8, 2003. AE Supply and the other defendants plan to file a demurrer as soon as plaintiffs file a notice of return to California superior court. AE Supply cannot predict the outcome of this suit.

In May of 2002, a California state legislator brought a claim on behalf of California taxpayers against AE Supply and 30 other power suppliers, as well as Vikram Budhraja, a contract negotiator for CDWR. The suit,

styled as McClintock v. Budhraja, et al. and brought in California Superior Court in Los Angeles County, alleges, among other things, that Budhraja had a conflict of interest during negotiations. AE Supply has not been served in this action. Plaintiffs seek a judicial declaration that the energy contracts are void and unenforceable as a matter of law, as well as judicial intervention to prohibit further performance on the energy contracts by any defendant. AE Supply continues to monitor the status of the Kurtz and Budhraja lawsuits.

On December 7, 2001, Nevada Power Company (NPC) filed a complaint with the FERC against AE Supply, which sought FERC action to modify prices payable to AE Supply under three trade confirmations dated December 4, 2000, January 16, 2001, and February 7, 2001 between Merrill Lynch and NPC and entered into under the Western Systems Power Pool Master Agreement. The transactions related to power sales during 2002. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with AE Supply under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers.

A hearing was held before a FERC administrative law judge (ALJ) in late 2002. On December 19, 2002, the ALJ issued findings that no contract modification is warranted on the grounds that dysfunctional California spot markets did not have an adverse effect on the contract prices. The ALJ determined in favor of the plaintiffs that AE Supply, rather than Merrill Lynch, was a proper subject of NPC’s complaint.

On June 26, 2003, the FERC affirmed the ALJ’s preliminary findings and issued an order upholding the long-term contracts negotiated between NPC and AE Supply. The FERC did not render a decision on whether AE Supply was a legitimate party in interest to the three trade confirmations at issue.

Numerous parties, including the Public Utility District No. 1 of Snohomish County, Washington, have filed Requests for Rehearing of the FERC’s June 26 order. AE Supply, as part of the Respondent’s Group, filed a “Limited Request for Clarification or, in the Alternative, for Rehearing” of the FERC’s order. Also, on July 3, 2003 Snohomish County filed an appeal of the FERC’s June 26 order with the U.S. Court of Appeals for the Ninth Circuit. On July 30, 2003, the FERC filed a motion with the Ninth Circuit to, among other things, dismiss Snohomish’s petition for review as “incurably premature.” On August 18, 2003, AE Supply filed a Motion to Intervene Out-of-Time in that proceeding. AE Supply cannot predict the outcome of this matter.

On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together Sierra/Nevada), initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, Merrill). The complaint alleged that Allegheny and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (Nevada PUC) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada asserted three causes of action against Allegheny arising from the alleged fraudulent conduct. These include: (1) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages, (2) conspiracy, and (3) violations of the Nevada state RICO Act. Sierra/Nevada filed an amended complaint on May 30, 2003 in which they assert a fourth cause of action against Allegheny for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys fees. Under the RICO count, Sierra/Nevada seeks in excess of $850 million.

AE and AE Supply filed motions to dismiss the complaints on May 6, 2003 and June 23, 2003. Sierra/Nevada filed an opposition on July 21, 2003. AE and AE Supply filed a reply to Sierra/Nevada’s opposition on August 11, 2003. AE and AE Supply cannot predict the outcome of this suit.

AE and AE Supply entered into an asset purchase agreement with Merrill Lynch and affiliated parties in 2001 under which AE and AE Supply purchased Merrill Lynch’s energy marketing and trading business for approximately $489 million and an equity interest in AE Supply of nearly two percent. The asset purchase agreement provides that Merrill Lynch would have the right to require AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest calculated from March 16, 2001, in the event that certain conditions were not met.

On September 24, 2002, Merrill Lynch filed a complaint against AE in the U.S. District Court for the Southern District of New York, alleging that AE breached the asset purchase agreement by failing to repurchase the equity interest in AE Supply from Merrill Lynch and seeking damages in excess of $125 million.

On September 25, 2002, AE and AE Supply commenced an action against Merrill Lynch in the Supreme Court of the State of New York for the County of New York. The complaint in that lawsuit alleges that Merrill Lynch fraudulently induced AE to enter into the purchase agreement and that Merrill Lynch breached certain representations and warranties contained in the purchase agreement. The lawsuit sought damages in excess of $605 million, among other relief.

On October 23, 2002, AE filed a motion to stay Merrill Lynch’s federal court action in favor of AE and AE’s action in New York state court. On May 29, 2003, the U.S. District Court for the Southern District of New York denied AE’s motion to stay Merrill Lynch’s action and ordered that AE and AE Supply assert their claims against Merrill Lynch, which were initially brought in New York State court as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply dismissed the New York State action and, on June 13, 2003, filed counterclaims against Merrill Lynch in the United States District Court for the Southern District of New York. The counterclaims allege that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims seek damages in excess of $605 million and rescission of the agreement, among other relief. Merrill Lynch has moved to dismiss the counterclaims. On August 29, 2003, AE and AE Supply filed amended counterclaims that, among other things, add a claim against Merrill Lynch for negligent misrepresentation, and have opposed the motion to dismiss. AE and AE Supply cannot predict the outcome of this suit.

From October 2002 through December 2002, plaintiffs claiming to represent purchasers of AE’s securities filed 14 putative class-action lawsuits against AE and several of its former senior managers in U.S. District Courts for the Southern District of New York and the District of Maryland. The complaints allege that AE and senior management violated federal securities laws when AE purchased Merrill Lynch’s energy marketing and trading business with the knowledge that the business was built on illegal wash or round-trip trades with Enron, which the complaints allege artificially inflated trading revenue, volume and growth. The complaints assert that AE’s fortunes fell when Enron’s collapse exposed what plaintiffs claim were illegal trades in the energy markets. The complaints do not specify requested relief.

In February and March 2003, two putative class action lawsuits were filed against AE in U.S. District Courts for the Southern District of New York and the District of Maryland. The suits allege that AE and a senior manager violated the Employee Retirement Income Security Act of 1974 (ERISA) by: (1) failing to provide complete and accurate information to plan beneficiaries regarding the energy trading business, among other things; (2) failing to diversify plan assets; (3) failing to monitor investment alternatives; (4) failing to avoid conflicts of interest; and (5) violating fiduciary duties.

In June 2003, a shareholder derivative action was filed against AE’s Board of Directors and several current and former senior managers in the Supreme Court of the State of New York for the County of New York. The suit alleges that the Board and senior management breached fiduciary duties to AE that have exposed AE to the securities class-action lawsuits.

Both the securities cases and the ERISA cases have been transferred to the District of Maryland for coordinated or consolidated pre-trial proceedings. The derivative action has been stayed pending the commencement of discovery in the securities cases. AE has not yet answered the complaints. AE cannot predict the outcome of this matter.

As of September 19, 2003, Monongahela has been named as a defendant, along with multiple other corporate defendants, in asbestos complaints filed on behalf of 5,624 plaintiffs, with each complaint naming one or more plaintiffs. The suits have been brought primarily in state courts in West Virginia, particularly in the Circuit Courts of Brooke, Hancock, Harrison, Kanawha, Marshall, Mason, Monongalia, Pleasants, and Putnam counties. Suits regarding alleged asbestos exposure at Allegheny-owned facilities began to be brought in the early 1990s, and new suits continue to be filed. Potomac Edison and West Penn have been named as defendants along with multiple other defendants in approximately one-half of those cases.

Because these cases are filed in a “shotgun” format, in which multiple plaintiffs file claims against multiple defendants in the same case, it is currently impossible to determine the actual number of cases in which plaintiffs make claims against the Distribution Companies. Based upon past experience and available data, it may be estimated that about one-third of the total number of cases filed actually involve claims against any or all of the Distribution Companies. All complaints allege that the plaintiffs sustained unspecified injuries resulting from claimed exposure to asbestos in various generating plants and other industrial facilities operated by the various defendants, although all plaintiffs do not claim exposure at facilities operated by all defendants. With very few exceptions, plaintiffs claiming exposure at stations operated by the Distribution Companies were employed by third-party contractors, not by the Distribution Companies. Generally, the operating legal presumption provides that an employee may recover damages against his or her direct employer through a worker’s compensation claim, but not a tort claim. Three plaintiffs are known to be either present or former employees of Monongahela, but have asserted that they are nonetheless eligible to assert tort suits. Each plaintiff generally seeks compensatory and punitive damages against all defendants in amounts of up to $1 million and $3 million, respectively. In those cases which include a spousal claim for loss of consortium, damages are generally sought against all defendants in an amount of up to an additional $1 million.

The majority of cases against the Distribution Companies have previously been dismissed or settled for an amount less than the anticipated cost of defense. While the Distribution Companies believe that all of the cases are without merit, they cannot predict the outcome nor are they able to predict whether additional cases will be filed. A recent U.S. Supreme Court decision could have the effect of increasing the value of asbestos claims. Settlement values could also be affected by federal legislation currently being drafted.

On March 4, 1994, the Distribution Companies received notice that the EPA had identified them as potentially responsible parties (PRPs) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site. Initially approximately 175 PRPs were involved, however, the current number of active PRPs is approximately 80. The costs of remediation will be shared by all responsible parties. In 1999, a PRP group that included the Distribution Companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30 million. A final determination has not been made for the Distribution Companies’ share of the remediation costs. However, at this time, it is estimated that the effect on the Distribution Companies will not be material.

On April 11, 2002, Mountaineer received a request for information from the EPA under the jurisdiction of the CERCLA, regarding a Superfund site in West Virginia. A final determination regarding Mountaineer’s responsibility at the site has not been made. However, based on available information, AE believes Mountaineer, at most, would be considered a de minimis responsible party.

On June 14, 2002, AE received a request for information from the PADEP, under the jurisdiction of the Pennsylvania Hazardous Sites Cleanup Act of 1988, regarding potential cleanup activities at a Pennsylvania site. A final determination regarding AE’s responsibility at the site has not been determined.

The Attorneys General of New York and Connecticut, in letters dated September 15, 1999, and November 3, 1999, respectively, notified AE of their intent to commence civil actions against AE and/or its subsidiaries alleging violations at the Fort Martin Power Station under the Clean Air Act, which requires power plants that make major modifications to comply with the same New Source Review emission standards applicable to new power plants. Other governmental agencies may commence similar actions in the future. Fort Martin Power Station is located in West Virginia and is now jointly owned by AE Supply and Monongahela. Both Attorneys General stated their intent to seek injunctive relief and penalties. In addition, the Attorney General of the State of New York indicated that he may 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, AE and its subsidiaries are not able to determine what effect, if any, these actions may have on them.

In August 2000, AE received a letter from the EPA requiring it to provide information and documentation relevant to the operation and maintenance of the following 10 electric generating stations, collectively including 22 generating units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island. AE Supply and Monongahela own these electric generating stations. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the new source review standards, which can require the installation of additional air pollution control equipment upon the major modification of an existing facility. Responsive submissions were made during 2000 and 2001. In July 2002, AE received a follow-up letter from the EPA requesting clarifying information. AE provided responsive information.

those standards. Section 114 information requests concerning facility modifications are often followed by enforcement actions. The EPA contacted AE and requested a meeting, which was held on July 16, 2003. Additional meetings will likely be scheduled in the next few months. At this time, AE is not able to determine what effect the EPA’s inquiry may have on its operations. If new source review standards are applied to AE generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. However, the recent preliminary judicial decision in the EPA vs. Duke energy case, as well as the final Routine Maintenance, Repair and Replacement Rule recently released by the EPA, are more consistent with the energy industry’s historical compliance approach. Therefore, at this time, AE and its subsidiaries are not able to determine the effect these actions may have on them with regard to compliance costs.

In June 2000, Monongahela was contacted by the EPA and the Environmental Enforcement Section of the DOJ concerning the release of approximately 19,000 gallons of non-polychlorinated biphenyl (PCB) oil into the environment, following the catastrophic failure of a transformer at Monongahela’s Belmont substation. Monongahela informed the federal agencies that it had been working in conjunction with the West Virginia Division of Environmental Protection regarding site cleanup and remediation. Monongahela reached an agreement with the EPA through the DOJ resolving the agency’s concerns in November 2001. The U.S. District Court for the Northern District of West Virginia accepted the consent decree, which the parties entered in February 2002. Monongahela agreed to install additional piping and oil containment facilities and pumps at the substation to prevent any oil which may leak from the equipment from leaving the property, and this work was completed in 2002. In addition, Monongahela paid a civil penalty in the amount of $252,000 on March 13, 2002.

Allegheny Energy Supply Gleason Generating Facility, LLC, a subsidiary of AE Supply, is the defendant in suits brought in the Circuit Court for Weakley County, Tennessee, by residents living in the vicinity of the generating facility in Gleason, Tennessee. The original suit was filed on September 16, 2002. AE Supply purchased the peaking facility in 2001. The plaintiffs are asserting claims based on trespass and/or nuisance, claiming personal injury and property damage as a result of noise from the generating facility during operation. They seek a restraining order with respect to the operation of the plant and damages of $200 million.

The Gleason Facility has demanded indemnification and a defense from Siemens Westinghouse, the manufacturer of the turbines used in the facility, pursuant to the terms of the equipment purchase agreement. On October 17, 2002, Siemens Westinghouse filed a request for a declaratory judgment in the Court of Common Pleas of Allegheny County, Pennsylvania, seeking a declaration that the prior owner released Siemens Westinghouse from this liability through a release executed after Allegheny purchased the Gleason facility.

AE has also undertaken property purchases and other mitigation measures. AE cannot predict the outcome of this suit or whether it will be able to recover amounts from Siemens Westinghouse.

On October 9, October 25, and November 5, 2002, AE received subpoenas from the SEC. The subpoenas principally concerned: (1) the departure of Daniel L. Gordon, the former head of energy trading for AE Supply; (2) AE’s litigation with Merrill Lynch; (3) AE Supply’s valuation and management of its trading business; (4) AE’s November 4, 2002, press release concerning its financial statements; (5) the departure of AE’s and its subsidiaries’ Controller, Thomas Kloc, in June 2002; and (6) AE’s acquisition of power plants from Enron. AE and AE Supply responded to the subpoenas.

On October 2, 2002 and January 15, 2003, AE and AE Supply received subpoenas from the CFTC for documents relating to natural gas and electricity trading. AE and AE Supply responded to the subpoenas.

On May 9, 2003, Enron Power Marketing, Inc. (EPMI), a Chapter 11 debtor, commenced an adversary proceeding against AE Supply in its bankruptcy case that is pending in the U.S. Bankruptcy Court for the Southern District of New York. The complaint alleges that AE Supply owes EPMI (1) $27,646,725 for accounts receivable due and owing for energy delivered prior to the commencement of EPMI’s bankruptcy case, and (2) $8,250,000 in cash collateral previously posted by EPMI to AE Supply, less any amounts owed to AE Supply as a result of EPMI’s default under a master trading agreement entered into between the parties and certain transactions arising thereunder. By the complaint, EPMI also seeks certain declaratory relief, including a declaration that the arbitration provision found in the master trading agreement is unenforceable. On August 1, 2003, AE Supply filed an answer asserting affirmative defenses. AE Supply cannot predict the outcome of this matter.

The registrants are from time to time involved in litigation and other legal disputes in the ordinary course of business. Each registrant is of the belief that there are no other legal proceedings which could materially impair its operations or materially or adversely affect its financial condition.

No matters were submitted to a vote of AE’s security holders during the fourth quarter of 2002. No other registrants submitted any matters to a vote of security holders during the fourth quarter of 2002.

At the annual meeting of AE’s shareholders held on May 9, 2002, votes were taken for: (1) the election of directors; (2) the approval of the appointment of PwC as independent accountants; (3) a shareholder proposal regarding a stockholder rights plan; (4) a shareholder proposal regarding “global warming”; (5) a shareholder proposal regarding “audit services”; (6) a shareholder proposal regarding “reincorporation”; (7) a shareholder proposal regarding “EEOC Information”; (8) a shareholder proposal regarding “golden parachutes”; and (9) a shareholder proposal regarding annual election of all directors. The total number of votes cast in the election for directors was 108,588,554 with the following results:

The shareholders approved the appointment of AE’s independent accountants. The shareholders also approved the shareholder statements regarding the stockholder rights plan and the annual election of directors referenced above. They did not approve the shareholder proposals regarding global warming, audit services, reincorporation, Equal Employment Opportunity Commission information, or golden parachutes.

AGC. At the annual meeting of AGC shareholders held on February 25, 2003, votes were taken for the election of directors. The total number of votes cast was 1,000 with all votes being cast for the election of the following directors: Paul M. Barbas, Richard J. Gagliardi, Thomas K. Henderson, Michael P. Morrell, Alan J. Noia, Jay S. Pifer, and Bruce E. Walenczyk. Messrs. Gagliardi, Henderson, Morrell, Noia, and Walenczyk all retired in 2003. Mr. Barbas resigned in 2003.

AE. At a special meeting of AE stockholders convened on March 7, 2003, and adjourned, and then reconvened, and completed on March 14, 2003, a vote was taken on a proposal to amend AE’s Charter to eliminate the preemptive rights of stockholders. Approval of the proposal required the affirmative vote by a majority of the outstanding shares entitled to vote. The total number of shares present was 80,810,756, with the following results:

A majority of the outstanding shares entitled to vote were voted in favor of the proposal to amend the Charter to eliminate preemptive rights of stockholders, and the Charter was so amended.

West Penn. At the annual meeting of West Penn shareholders held on April 16, 2003, votes were taken for the election of directors. The total number of votes cast was 24,361,586, with all votes being cast for the election of the following directors: Paul M. Barbas, Richard J. Gagliardi, Thomas K. Henderson, Michael P. Morrell, Alan J. Noia, Jay S. Pifer, and Bruce E. Walenczyk. Messrs. Gagliardi, Henderson, Morrell, Noia, and Walenczyk all retired in 2003. Mr. Barbas resigned in 2003.

Potomac Edison. At the annual meeting of Potomac Edison shareholders held on April 23, 2003, votes were taken for the election of directors. The total number of votes cast was 22,385,000, with all votes being cast for the election of the following directors: Paul M. Barbas, Richard J. Gagliardi, Thomas K. Henderson, Michael P. Morrell, Alan J. Noia, Jay S. Pifer, and Bruce E. Walenczyk. Messrs. Gagliardi, Henderson, Morrell, Noia, and Walenczyk all retired in 2003. Mr. Barbas resigned in 2003.

AE’s common stock is actively traded. There is no trading market for the equity securities of AE Supply, AGC, Monongahela, Potomac Edison, or West Penn.

“AYE” is the trading symbol of the common stock of AE on the New York, Chicago, and Pacific Stock Exchanges. As of September 15, 2003, there were 32,862 holders of record of AE’s common stock.

The table below shows the dividends paid and the high and low sale prices of the common stock for the periods indicated:

The Board of Directors of AE did not declare a dividend for the fourth quarter of 2002. The terms of AE’s Borrowing Facilities put in place in February 2003, and the indenture entered into in connection with the convertible preferred securities issuance in July 2003, do not permit the payment of dividends. AE is also subject to regulatory constraints concerning dividend declarations, including PUHCA, which precludes the payment of dividends by a company with negative retained earnings.

The high and low prices from January 1, 2003 through September 15, 2003 were $10.30 and $4.82. The last reported sale on that date was $9.43.

Pursuant to a Stockholder Protection Rights Agreement, shares of AE common stock include associated share purchase rights (Rights). On July 10, 2003, the Board of Directors voted to redeem the Rights. Such redemption may not take place until AE receives all required authorizations, including under PUHCA.

AE owns approximately 98 percent of the membership interests in AE Supply. On August 28, 2002, AE Supply declared a distribution to members of $100 million, of which $98 million was distributed to AE, and the balance of which has not been distributed. AE Supply made no distributions to members during 2001.

Monongahela and AE Supply own approximately 23 percent and 77 percent, respectively, of the shares of AGC. AGC paid dividends of $7 million, $3.5 million, and $3.5 million on June 28, September 30, and December 5, 2002, respectively, to its shareholders. AGC paid dividends of $8 million on each of March 30, June 29, September 28, and December 28, 2001.

AE owns 100 percent of the common shares of Monongahela. Monongahela paid dividends of approximately $12.5 million, $4.5 million, $4.8 million, and $50 million on March 29, June 28, September 30, and November 22, 2002, respectively. Monongahela paid dividends of approximately $6.2 million, $22.2 million, $24.3 million, and $45.2 million on March 30, June 29, September 28, and December 28, 2001, respectively.

AE owns 100 percent of the common shares of Potomac Edison. Potomac Edison paid dividends of approximately $6.3 million, $6.3 million, and $5.8 million on March 29, June 28, and September 30, 2002, respectively. Potomac Edison paid dividends of approximately $9.6 million, $26.2 million, $24.4 million, and $15 million on March 30, June 29, September 28, and December 28, 2001, respectively.

AE owns 100 percent of the common stock of West Penn. West Penn paid dividends of approximately $18.5 million, $10.5 million, and $11.5 million on March 29, June 28, and September 30, 2002, respectively. West Penn paid dividends of approximately $90.1 million and $18.5 million on March 30 and December 28, 2001, respectively.

On July 25, 2003, AE completed the private placement of $300 million aggregate liquidation amount of its 11⁷/8 percent Mandatorily Convertible Trust Preferred Securities (the Trust Preferred Securities) to a group of private investment funds. AE concluded that the placement qualified for exemptions from registration under the Securities Act of 1933, including under Section 4(2) of the Securities Act and Regulation D under the Securities Act. This conclusion was based on several factors, including representations provided by the purchasers and the placement agents. The aggregate price paid by the purchasers in the private placement was $291 million (97% of par). AE paid aggregate placement agents’ commissions of $11.5 million. AE realized net proceeds after expenses, including fees and expenses of purchasers’ and agents’ counsel, of $275 million.

The Trust Preferred Securities will be convertible automatically into shares of AE common stock on or after June 15, 2006 in the event that the closing price per share of AE common stock equals or exceeds $15 over a specified averaging period. The Trust Preferred Securities are also convertible at the option of the holders at any time. The Trust Preferred Securities were issued in multiples of $1,000. The conversion price of the Trust Preferred Securities is $12 per AE common share (that is, 83.33 shares per $1,000 principal amount of the Trust Preferred Securities). The Trust Preferred Securities are convertible in the aggregate into 25 million shares of AE common stock. The terms of the Trust Preferred Securities relating to their conversion are subject to anti-dilution and other adjustment provisions.

AE believes that during the period from on or about October 11, 2002 to on or about October 25, 2002, approximately 613,538 shares of AE common stock were sold under AE’s Employee Stock Ownership and Savings Plan (ESOSP) in excess of the number of shares of AE common stock registered for sale under the then effective registration statement with respect to the ESOSP. We refer to these shares as the excess shares. The ESOSP permitted eligible employees to purchase AE common stock as one investment option under the plan. Through clerical errors and oversight during a period of marked volatility within our business and the market for AE’s common shares, the excess shares were inadvertently sold to ESOSP participants. The sale of AE shares under the ESOSP was suspended when AE discovered the error. The excess shares were sold at various prices ranging from approximately $4.45 to approximately $6.27. The weighted average price of the excess shares was approximately $5.24 and the aggregate purchase price paid by ESOSP participants for the excess shares was approximately $3.21 million.

Although exemptions from registration may be available for certain of the excess share sales, AE may be subject to certain federal and state securities claims and liabilities in connection with these sales, including claims and liabilities based on recission rights of the purchasers of the excess shares.

Allegheny Energy, Inc. (AE) and its consolidated subsidiaries (collectively, Allegheny) have experienced significant changes in their businesses over the last several years, as described in ITEM 1. BUSINESS—Recent Events. During 2002, Allegheny and Allegheny Energy Supply Company, LLC (AE Supply) experienced a strain on their liquidity positions, and, at December 31, 2002, a significant portion of their debt has been reclassified as current, as discussed in Financial Condition, Requirements and Resources. Also, Allegheny incurred a net loss of $632.7 million in 2002, primarily due to trading losses and adverse wholesale energy market conditions experienced by its Generation and Marketing segment as discussed below in Earnings Summary.

In 2002, Allegheny identified various errors relating to its financial statements for years prior to 2002 as a result of a comprehensive financial review as discussed in Note 2 to its financial statements. Corrections to these errors are reflected in the consolidated financial statements for the year ended December 31, 2002, and increased the net loss for 2002 by approximately $20.1 million. Except for certain restatement adjustments to the consolidated balance sheet as of December 31, 2001, Allegheny’s management concluded that these errors were not material, either individually or in the aggregate, to the 2002 or any prior year’s financial statements.

In the second quarter of 2002, Allegheny aligned its businesses into two segments. The Generation and Marketing segment consists primarily of AE’s subsidiary, AE Supply, including its subsidiary, Allegheny Generating Company (AGC). AE Supply is an unregulated (i.e., not subject to state rate regulation) energy supply company that develops, owns, operates, and controls electric generating capacity and supplies and trades energy and energy-related commodities. This segment also includes generation assets for Monongahela Power Company’s (Monongahela) West Virginia regulatory jurisdiction, which has not deregulated electric generation.

The Delivery and Services segment consists primarily of Allegheny’s regulated utility subsidiaries—Monongahela, including its subsidiary, Mountaineer Gas Company (Mountaineer); The Potomac Edison Company (Potomac Edison); and West Penn Power Company (West Penn). The Delivery and Services segment operates regulated electric and natural gas transmission and distribution (T&D) systems. This segment also includes Allegheny Ventures, an unregulated subsidiary, which invests in and develops fiber-optic and data services through Allegheny Communications Connect, Inc. (ACC) and energy-related projects.

Use of Estimates: The preparation of financial statements in conformity with generally accepted accounting principles of the United States of America (GAAP) requires Allegheny to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. The estimates that require management’s most difficult, subjective, and complex judgments involve the fair value of commodity contracts and derivative instruments, adverse power purchase commitments, goodwill, unbilled revenues, regulatory assets and liabilities, pension and other postretirement benefit costs, and long-lived assets. Significant changes in the estimates could have a material effect on Allegheny’s consolidated results of operations, cash flows, and financial position.

Commodity Contracts: Through December 31, 2002, commodity contracts related to Allegheny’s energy trading activities were recorded at their fair value in accordance with the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Energy Trading and Risk Management Activities.” As of January 1, 2003, EITF Issue No. 98-10 was rescinded. However, the vast

majority of Allegheny’s commodity contracts continue to be recorded at their fair value under the FASB’s Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133—an amendment of FASB Statement No. 133,” and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities—an amendment of FASB Statement No. 133” (collectively referred to as SFAS No. 133). At December 31, 2002, the fair value of Allegheny’s commodity contracts represented a net asset position of $429.7 million. Fair values for exchange-traded instruments, principally futures and certain options, are based on actively 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 and estimated market data and pricing models, which may change from time to time. Allegheny has several 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. Allegheny’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 reduced market liquidity, have significantly affected the merchant energy marketplace during 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 Allegheny’s consolidated financial position, cash flows, 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.

Allegheny’s accounting for commodity contracts is discussed under “Operating Revenues” and Note 4 to the consolidated financial statements. Also, see Note 9 to the consolidated financial statements and “Derivative Instruments and Hedging Activities” for additional information regarding Allegheny’s accounting for derivative instruments under SFAS No. 133.

In addition to the above, the fair value of Allegheny’s commodity contracts can be affected by regulatory challenges involving deregulation of energy prices and markets. The California Public Utility Commission (California PUC), the California Department of Water Resources (CDWR), and the California Electricity Oversight Board (CAEOB) challenged the contracts between the CDWR and AE Supply. In June 2003, AE Supply entered into a settlement agreement with the State of California to resolve the state’s litigation regarding its power supply contract with the CDWR. The terms of the settlement reduced the volume of power to be delivered from 2005 - 2011 and reduced the sale price of off-peak power to be delivered from 2004 - 2011, which in turn substantially reduced the value of the contract. The following table shows the renegotiated prices and volumes:

renegotiation of the contract with the CDWR, Allegheny estimates that the fair value of the agreement decreased

by a range of $160 to $190 million. The renegotiation of the contract terms was part of the agreement to settle litigation with the State of California regarding the contract’s validity. Allegheny closed the sale of the contract to a subsidiary of The Goldman Sachs Group, Inc. in September 2003.

The California PUC and the FERC approved the renegotiated agreement, effective August 15, 2003. The modified terms and conditions included in the renegotiated agreement will result in a reduction to the fair value of the CDWR agreement, with a corresponding reduction in earnings.

See Note 26 to the consolidated financial statements for additional information regarding the renegotiated agreement with the CDWR. See also “Financial Condition, Requirements and Resources—Liquidity and Capital Requirements” and Notes 3 and 4 for information regarding agreements entered into by AE Supply to sell the CDWR power supply contract, and associated hedge transactions, and to terminate two tolling agreements in the Western United States energy markets.

Adverse Power Purchase Commitments: At December 31, 2002, Allegheny’s adverse power purchase commitment liability was $255.2 million, which related to a contract that extends to the year 2016. As a result of the deregulation plan approved in 1998 for West Penn, an adverse power purchase liability was recorded by Allegheny related to a commitment to buy electricity from a nonutility generator at prices that are above the future expected market price for electricity. A change in the estimated future market price of electricity or a change in the expected cost of the electricity purchased under the terms of the contract could have a material effect on the adverse power purchase commitment liability and on Allegheny’s results of operations and financial position.

Excess of Cost Over Net Assets Acquired (Goodwill): As of December 31, 2002, Allegheny’s intangible asset for acquired goodwill was $367.3 million related to the acquisition of an energy marketing and trading business in March 2001. Effective January 1, 2002, with the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets,” Allegheny ceased amortization of goodwill and now tests goodwill for impairment at least annually. As discussed in Note 7, upon adoption of SFAS No. 142, Allegheny recorded an impairment of goodwill related to its Delivery and Services segment of $130.5 million, net of income taxes. For Allegheny, the estimation of the fair value of its reporting units, where a reporting unit represents an operating segment or one level below an operating segment, involves the use of present value measurements and cash flow models. This process involves judgments on a broad range of information. Significant changes in the fair value estimates could have a material effect on Allegheny’s results of operations and financial position.

Unbilled Revenues: Unbilled revenues are primarily associated with Allegheny’s regulated utility subsidiaries. Energy sales to individual customers are based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers subsequent to the last meter reading are estimated and the regulated utility subsidiaries recognize unbilled revenues. The unbilled revenue estimates are based on daily generation, purchases of electricity and natural gas, estimated customer usage by customer type, weather effects, electric and natural gas line losses, and the most recent consumer rates. As this process uses several significant estimates and assumptions, a significant change in them could have a material effect on Allegheny’s consolidated results of operations and financial position.

Regulatory Assets and Liabilities: Allegheny’s regulated utility subsidiaries are regulated by various federal and state regulatory agencies. As a result, the regulated utility subsidiaries qualify for the application of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets or liabilities arise as a result of a difference between GAAP, excluding the effects of rate regulation, and the economic effect of decisions by regulatory agencies. Regulatory assets generally represent incurred costs that have been deferred, as they are probable of recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for various reasons.

The regulated utility subsidiaries recognize regulatory assets and liabilities in accordance with the rulings of their federal and state regulators. Future regulatory rulings may affect the carrying value and accounting treatment of Allegheny’s regulatory assets and liabilities at each balance sheet date. Allegheny assesses whether the regulatory assets are probable of future recovery by considering factors such as regulatory environment changes, recent rate orders issued by the applicable regulatory agencies, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an effect on the recovery of costs, the rate of return on invested capital, and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material effect on Allegheny’s results of operations, cash flows, and financial position.

Accounting for Pensions and Postretirement Benefits Other Than Pensions: Allegheny accounts for pensions under SFAS No. 87, “Employers’ Accounting for Pensions” and other postretirement benefits under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Under these rules, certain assumptions are made which represent significant estimates. There are many factors and assumptions involved in determining Allegheny’s pension and other postretirement benefit obligations and costs each period, such as employee demographics (including age, life expectancies, compensation levels), discount rates, rate of return on invested funds, estimated compensation increase rates, medical inflation, and the fair value of assets funded for the plan (see Note 17 to the Consolidated Financial Statements for additional information concerning assumptions used by Allegheny). Changes made to provisions of pension or other postretirement benefit plans may also affect current and future pension and OPEB costs. Allegheny’s assumptions are supported by historical data and reasonable projections and are reviewed annually with an outside actuarial firm.

As of December 31, 2002, Allegheny utilized a 6.50 percent discount rate and a 9.00 percent expected return on plan assets. In selecting an assumed discount rate, Allegheny reviews various corporate Aa bond indices. The 9.00 percent expected return on plan assets is consistent with Allegheny’s historical returns and is based on projected long-term equity and bond returns, maturities and asset allocations. The table below shows the effect that a 100 basis point increase or decrease in the discount rate and expected return on plan assets would have on Allegheny’s pension and other postretirement benefits (OPEB) costs:

Long-Lived Assets: Allegheny’s consolidated balance sheet includes significant long-lived assets, which are not subject to recovery under SFAS No. 71. As a result, Allegheny must generate future cash flows from such assets in a non-regulated environment to ensure the carrying value is not impaired. Certain of these assets are the result of capital investments that have been made in recent years and have not yet reached a mature life cycle. Allegheny assesses the carrying amount and potential impairment of these assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors Allegheny considers in determining if an impairment review is necessary include a significant underperformance of the assets relative to historical or projected future operating results, a significant change in Allegheny’s use of the assets or business strategy related to such assets, and significant negative industry or economic trends. When Allegheny determines that an impairment review is necessary, a comparison is made between the expected undiscounted future cash flows and the carrying amount of the asset. If the carrying amount of the asset is the larger of the two balances, an impairment loss is recognized equal to the amount by which the carrying amount of the asset exceeds the fair value of the asset. In these cases, the fair value is determined by the use of quoted market prices, appraisals, or

the use of valuation techniques such as expected discounted future cash flows. Allegheny must make assumptions regarding these estimated future cash flows and other factors to determine the fair value of the respective assets. Significant changes to these assumptions could have a material effect on Allegheny’s consolidated results of operations and financial position.

The decrease in earnings for 2002, before extraordinary charge and cumulative effect of accounting change, was primarily due to weak wholesale energy markets nationwide, lower net revenue for the Generation and Marketing segment, and write-offs related to cancelled generation projects and other investments determined to be impaired. The Generation and Marketing segment recorded an unrealized loss on its commodity contracts of $221.0 million, net of income taxes ($(1.76) per share), during 2002, compared to an unrealized gain of $375.2 million, net of income taxes ($3.12 per share), during 2001. The unrealized loss for 2002 reflected then current market conditions, which required changes in techniques and assumptions used to determine the fair value of commodity contracts, as well as a decrease in liquidity and volatility in the energy markets in the Western United States. The Generation and Marketing segment also recorded a charge of $149.2 million, net of income taxes ($(1.19) per share), for the cancellation of generation projects during 2002.

The Delivery and Services segment recorded charges of $26.5 million, net of income taxes ($(.21) per share), for unregulated investments determined to be impaired and $18.8 million, net of income taxes ($(.15) per share), for the loss on the sale of Fellon-McCord and Alliance Energy Services. In addition, the Delivery and Services segment earnings were affected by an increase in purchased energy and transmission expense of $59.8 million primarily due to an increase in the price per MWh paid to the Generation and Marketing segment for purchased energy, as these costs were not able to be recovered in retail rates.

For 2002, Allegheny also incurred a charge of $82.6 million, net of income taxes ($(.66) per share), consisting of $30.8 million for the Delivery and Services segment and $51.8 million for the Generation and Marketing segment, respectively, for workforce reduction costs related to Allegheny’s voluntary Early Retirement Option (ERO) program and other employee severance costs, and for restructuring charges and related asset impairment.

The decrease in 2002 earnings per share reflects the decrease in net income and the effects of an increased average number of shares outstanding, due to the issuance of 14.3 million shares on May 2, 2001, and 1.3 million shares during 2002 for various Allegheny benefit plans.

Also for 2002, Allegheny completed its assessment of goodwill in accordance with SFAS No. 142. The assessment determined that approximately $210.1 million of goodwill, primarily related to the acquisitions of Mountaineer and West Virginia Power (WVP), was impaired. As a result, Allegheny recorded a charge of $130.5 million, net of income taxes ($(1.04) per share), as the cumulative effect of an accounting change as of January 1, 2002.

The increase in earnings for 2001, before extraordinary charge and cumulative effect of accounting change, was driven by the addition of unregulated generating capacity and unrealized gains from energy trading activities resulting from the newly acquired energy trading business. The increase in the Generation and Marketing segment’s net revenues included the results of the acquired energy trading business, since March 16, 2001.

The increase in earnings for the Delivery and Services segment for 2001 was due to an increase in revenues from unregulated services, largely offset by increases in purchased energy and transmission and natural gas purchases.

The increase in earnings per share for 2001, before extraordinary charge and cumulative effect of an accounting change, reflects the results of energy trading activities and higher net revenues for the Generation and Marketing segment due to increased generating capacity, partially offset by a higher number of average shares of common stock outstanding as a result of the issuance of 14.3 million shares of common stock on May 2, 2001.

At January 1, 2001, AE Supply had certain option contracts that were derivatives as defined by SFAS No. 133, which did not qualify for hedge accounting. In accordance with SFAS No. 133, AE Supply recorded a charge of $31.1 million against earnings, net of income taxes ($(.26) per share), for these contracts as a change in accounting principle on January 1, 2001. See Note 9 to the consolidated financial statements for additional details.

Delivery and Services: The increase in the Delivery and Services segment’s regulated electric revenues for 2002 was primarily due to an increase in the average number of customers, an increase in customer usage due to a 2.2-percent increase in heating degree days versus the prior year and a 45.7-percent increase in cooling degree days versus the prior year, higher Pennsylvania gross receipts taxes, and a return of choice customers to full service. The increase in the Delivery and Services segment’s regulated electric revenues for 2001 was primarily due to an increase in the average number of customers, partially offset by a decrease in heating degree days of 8.1 percent versus the prior year.

Regulated electric revenues include choice revenues that represent T&D revenues from customers in West Penn’s Pennsylvania, Potomac Edison’s Maryland and Virginia, and Monongahela’s Ohio distribution territories who chose alternate electricity generation suppliers. Pennsylvania, Maryland, Virginia, and Ohio deregulation gave West Penn’s, Potomac Edison’s, and Monongahela’s regulated customers the ability to choose another electricity generation supplier. For 2002 and 2001, all of West Penn’s regulated customers, Potomac Edison’s Maryland regulated customers, and Monongahela’s Ohio regulated customers had the ability to choose another electricity generation supplier. Potomac Edison’s Virginia regulated customers had the ability to choose alternate electricity generation suppliers beginning on January 1, 2002. The return of customers to full service does not affect sales since Allegheny determines sales on the basis of kilowatt-hours (kWh) delivered to customers (regardless of their electricity generation supplier). However, such a return of customers to full service results in an increase in revenues due to the addition of a generation charge that Allegheny had not collected while the customers were using an alternate electricity generation supplier. For 2002, the effect on revenues of customers returning to full service was especially noticeable in the commercial and industrial classes where a higher

percentage of sales were associated with choice customers returning to full service. For 2002, approximately .1 percent of the combined West Penn regulated customers, Potomac Edison Maryland and Virginia regulated customers, and Monongahela Ohio regulated customers chose alternate electricity generation suppliers. For 2001, approximately .2 percent of the combined West Penn regulated customers, Potomac Edison Maryland and Virginia regulated customers, and Monongahela Ohio regulated customers chose alternate electricity generation suppliers.

The Delivery and Services segment’s regulated natural gas revenues include Monongahela and Mountaineer for 2002 and 2001. Because a significant portion of the natural gas sold by Monongahela’s natural gas distribution operations is ultimately used for space heating, both revenues and earnings are subject to seasonal fluctuations. Under the Purchased Gas Adjustment (PGA) mechanism, differences between revenues received for energy costs and actual energy costs are deferred until the next rate proceeding, when energy rates are adjusted to return or recover previous overrecoveries or underrecoveries, respectively. The PGA mechanism continues to exist for Monongahela and came into effect for Mountaineer following a three-year moratorium, which ended on October 31, 2001. For 2002, the decrease in the Delivery and Services segment’s regulated natural gas revenues was primarily due to Mountaineer’s commercial customers switching to other natural gas suppliers and becoming transportation customers only. The increase in the Delivery and Services segment’s regulated natural gas revenues for 2001 was primarily due to Monongahela’s acquisition of Mountaineer in August 2000.

The Delivery and Services segment’s transmission services and bulk power revenues decreased $28.6 million for 2002 and increased $17.7 million for 2001. Transmission services and bulk power revenues included the sale of the output of the AES Warrior Run cogeneration facility into the open wholesale market. As discussed below, AE Supply started buying the output from the AES Warrior Run cogeneration facility in 2002 and the related revenues are reported as other affiliated and nonaffiliated energy services in 2002. This output was part of a Maryland Public Service Commission (Maryland PSC) settlement agreement with Potomac Edison, allowing full recovery from Maryland customers of the purchase power costs incurred by Potomac Edison related to the AES Warrior Run facility in excess of the value of the power sold in the open market. The decrease in the Delivery and Services segment’s transmission services and bulk power revenues for 2002 was partially offset by an $18.3-million increase in transmission revenues resulting from Allegheny joining the PJM Interconnection, LLC (PJM) power market.

The Delivery and Services segment’s unregulated services revenues increased $504.0 million and $116.9 million for 2002 and 2001, respectively, primarily due to revenues for Allegheny Energy Solutions’ agreement to provide seven natural gas-fired turbine generators to the South Mississippi Electric Power Association (SMEPA) for which revenues are recognized using the percentage of completion method of accounting and revenues from Alliance Energy Services, which was acquired by Allegheny Ventures on November 1, 2001. Alliance Energy Services was sold in December 2002. Revenues recognized under the percentage of completion method of accounting are not a material component of Allegheny’s revenues.

In November 2001, AE Supply obtained, through a competitive bidding process approved by the Maryland PSC, the contract to purchase the output of the AES Warrior Run project. As a result, other affiliated and nonaffiliated energy services included revenues for the sale of the output of the AES Warrior Run project. The increase in the Delivery and Services segment’s other affiliated and nonaffiliated energy services due to sales of the AES Warrior Run output for 2002 was partially offset by a decrease in energy and transmission sales from the Delivery and Services segment to the Generation and Marketing segment due to Allegheny joining PJM. The increase in the Delivery and Services segment’s other affiliated and nonaffiliated energy services of $27.0 million for 2001 was primarily due to increased energy and transmission sales from the Delivery and Services segment to the Generation and Marketing segment.

Generation and Marketing: The decrease in the Generation and Marketing segment’s wholesale revenues for 2002 was primarily due to weak wholesale energy markets nationwide and increased net unrealized losses of $358.3 million on commodity contracts. The increase in the Generation and Marketing segment’s revenues for

2001 was primarily due to net unrealized gains of $608.3 million from the energy trading business that was acquired in March 2001.

During 2002, Allegheny completed a thorough evaluation of its businesses, operations, and strategic plans. As a result of this evaluation, Allegheny is refocusing on identifying ways to improve, grow, and build on the earnings and cash flows from its core delivery and generation businesses. Furthermore, Allegheny is implementing an asset-backed trading strategy which will focus on the regions in which it owns generating facilities and serves customers such as in the Mid-Atlantic and Midwest. Allegheny is attempting to reduce its reliance on, and exposure to, energy marketing and speculative trading. Allegheny has modified, its energy marketing and trading activities to focus on reducing risk, optimizing the operations of its generating facilities, and prudently managing and protecting the value associated with the existing positions in Allegheny’s energy marketing and trading portfolio.

During 2002 and 2001, Allegheny traded electricity, natural gas, oil, coal, and other energy-related commodities. Allegheny recorded 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 operating revenues. The realized revenues from energy trading activities are recorded on a net basis in operating revenues on the consolidated statement of operations in accordance with EITF Issue No. 02-3.

The fair value of energy trading commodity contracts, which represent the net unrealized gain and loss positions, is recorded as assets and liabilities, after applying the appropriate counterparty netting agreements in accordance with Financial Accounting Standards Board (FASB) Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts—an Interpretation of APB Opinion No. 10 and FASB Statement No. 105.” At December 31, 2002, the fair value of energy trading commodity contract assets and liabilities was $1,211.5 million and $781.8 million, respectively. At December 31, 2001, the fair value of energy trading commodity contract assets and liabilities was $1,529.3 million and $768.9 million, respectively.

The following table disaggregates the net fair value of commodity contract assets and liabilities, excluding Allegheny’s generating assets and provider-of-last-resort (PLR), as of December 31, 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. Allegheny determines prices actively quoted from various industry services, broker quotes, and the New York Mercantile Exchange (NYMEX). Electricity markets are generally liquid for approximately one year and most natural gas markets are generally liquid for approximately three years. Afterward, some market prices can be observed, but market liquidity is less robust.

Approximately $528.0 million of Allegheny’s commodity contracts were classified above as prices based on models (even though a portion of these contracts are valued based on observable market prices). The most significant variables to Allegheny’s models used to value these contracts are 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 one year, and some observable market prices are available for about three years. After three 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 three years, and some observable market prices are available for about five years. Beyond five years, natural gas prices are escalated, based on trends in prior years.

For deliveries of less than one year, the fair value of Allegheny’s commodity contracts was a net liability of $34.9 million, primarily related to commodity contracts to hedge the CDWR agreement and Allegheny’s contract with Williams Energy Marketing and Trading Company (Williams) to call up to 1,000 megawatts (MW) of generating capacity in southern California.

Net unrealized losses of $358.3 million in 2002 and net unrealized gains of $608.3 million in 2001 were recorded to the consolidated statement of operations in operating revenues to reflect the change in fair value of the commodity contracts. The following table provides a roll-forward of the net fair value, or commodity contract assets less commodity contract liabilities, of Allegheny’s commodity contracts for 2002:

As shown in the table above, the net fair value of Allegheny’s commodity contracts decreased by $358.3 million as a result of net unrealized losses recorded during 2002, primarily caused by $608.1 million in unrealized losses that reflected then current market conditions which required changes in techniques and assumptions used to determine the fair value of commodity contracts. During 2002, the depressed wholesale energy markets significantly affected the merchant energy business, including Allegheny’s energy trading activities. Additional generating capacity, coupled with lower-than-expected demand for electricity due to the weak economy, have led to reduced wholesale prices in several regional markets. Also, the Enron bankruptcy, the California energy crisis, energy trading improprieties by certain companies, the planned retreat of several merchant energy companies from energy trading markets, and the decline in credit quality of merchant energy companies has negatively affected the liquidity of the wholesale energy markets.

During the third quarter of 2002, Allegheny announced a restructuring of its energy marketing and trading activities. Allegheny is significantly reducing its reliance on the wholesale energy trading business primarily by restricting activities to an asset-backed strategy using its low-cost generating assets located in the Mid-Atlantic and Midwest. As a result, Allegheny’s trading activities will focus on lowering risk, optimizing the value of its generating assets, and reducing the effect of mark-to-market earnings to the extent possible.

As a result of significant changes in market conditions, and in conjunction with Allegheny’s decision to restructure its energy trading activities, Allegheny performed a comprehensive assessment of the valuation techniques and assumptions used to value its existing portfolio of energy commodity contracts. To reflect current market conditions, Allegheny revised the valuation techniques and assumptions for certain contracts with option features. As a result, Allegheny reduced the value of its portfolio of energy commodity contracts by $356.3 million, before income taxes, in the third quarter of 2002.

During the fourth quarter of 2002, the fair value of Allegheny’s portfolio of commodity contracts was reduced by an additional $216.4 million, before income taxes. This reduction in fair value resulted from a decrease in the liquidity and volatility of the energy markets in the WSCC. This decrease in market liquidity and volatility primarily affected the fair values related to Allegheny’s contractual right to call up to 1,000 MW of generation in southern California from Williams and the agreement with LV Cogen to call upon up to 222 MW of generating capacity.

On February 21, 2002, the California PUC approved a rate agreement with the CDWR in order for the CDWR to issue Power Supply Revenue 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 Allegheny. In September 2002, the CDWR’s Power Supply Revenue Bonds received the following long-term ratings: Moody’s Investors Service (Moody’s), A3; Standard and Poor’s, BBB+; and Fitch Ratings (Fitch), A-. To date, all payments to Allegheny by the CDWR for purchased power have been made on time and in full.

The California PUC rate agreement and the long-term credit ratings are positive developments relative to the prior assumptions used in assessing the long-term creditworthiness of the CDWR and the estimation of the fair value of Allegheny’s contracts with the CDWR. As a result, the valuation adjustments used in estimating the fair value of these contracts have been reduced. Allegheny recorded a $35.8-million increase in the estimated fair value of the CDWR contract in the first quarter of 2002.

During 2001, Allegheny did not have any changes in the fair value of commodity contracts attributed to changes in valuation techniques. The net fair value of Allegheny’s commodity contracts increased by $608.3 million as a result of unrealized gains recorded during 2001. Of the unrealized gains, $578.9 million related to Allegheny’s contracts in the WSCC. This increase in the fair value of the WSCC portfolio was driven by the fixed-price contract to sell power for approximately 10 years to the CDWR, which increased in fair value as prices dropped in the WSCC during 2001. The increase in the fair value of the CDWR contract was partly offset by decreases in the fair value of the contract with Williams to call up to 1,000 MW of generating capacity in southern California and other contracts primarily used to hedge the WSCC portfolio, including the agreement with LV Cogen.

During 2002 and 2001, Allegheny’s energy trading and excess generation activities resulted in $239.7 million and $223.2 million of net realized losses, respectively. These losses were mainly related to Allegheny’s contract with the CDWR and the related hedges and, in the fourth quarter of 2002, trade terminations resulting from Allegheny’s failure to post collateral in favor of several counterparties following the downgrading of Allegheny’s credit rating below investment grade by Moody’s. These losses were partially offset by realized gains from the sale of generation in excess of the power provided to Allegheny’s regulated utility subsidiaries to meet their PLR obligations. AE Supply hedged the on-peak positions of the CDWR contract at prices above the fixed contract price of $61 per MWh that AE Supply received from the CDWR.

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 Allegheny’s operating results. Similarly, volatility in interest rates

will affect Allegheny’s operating results. The effects may be either positive or negative, depending on whether Allegheny’s subsidiaries are net buyers or sellers of electricity and natural gas.

The Generation and Marketing segment’s revenues for 2002 and 2001 also reflect transactions by AE Supply in the unregulated marketplace to sell electricity to wholesale customers. On May 3, 2001, AE Supply completed the acquisition of three natural gas-fired generating facilities with a total generating capacity of 1,710 MW in the Midwest. During 2001 and 2002, AE Supply also completed the construction of or acquired and placed into operation 214 MW of additional generating capacity. As a result, the Generation and Marketing segment had more generation available for sale into the deregulated marketplace in 2001 and 2002, including sales to West Penn, Potomac Edison, and Monongahela in excess of their PLR obligations.

Eliminations: The elimination between the Delivery and Services segment and the Generation and Marketing segment revenues is necessary to remove the effect of affiliated revenues, primarily sales of bulk power.

Generation and Marketing Net Revenues by Component: The table below separates operating revenues and cost of revenues for the Generation and Marketing segment into two components: PLR and excess generation and trading. The PLR component represents the Generation and Marketing segment’s obligation under long-term power sales agreements to provide West Penn, Potomac Edison, and Monongahela with the amount of electricity, up to their PLR retail load, that they may demand in their Pennsylvania, Maryland, Virginia, and Ohio service territories. The excess generation and trading component represents Allegheny’s energy marketing and trading activities and any generation in excess of the PLR obligations. All realized and unrealized gains and losses from energy trading activities were recorded net in operating revenues in accordance with EITF Issue No. 02-3.

The increase in the PLR net revenues of $51.4 million for 2002 was due to an increase in MWh sales related primarily to a full year of sales to Monongahela’s Ohio customers after the transfer of generating assets in July 2001 and an increase in prices. The decrease in the excess generation and trading net revenues of $1,029.8 million for 2002 was primarily due to weak wholesale energy markets and unrealized losses in 2002 versus unrealized gains in 2001 from energy trading activities.

Fuel Consumed for Electric Generation: Fuel consumed for electric generation, all within the Generation and Marketing segment, for 2002, 2001, and 2000 was $591.5 million, $560.4 million, and $532.8 million,

respectively. Fuel consumed for electric generation represents the cost of coal, natural gas, and oil burned for electric generation. Total fuel expenses increased by $31.1 million for 2002 primarily due to increased average fuel prices. The increase in average fuel prices increased fuel expense by approximately 5.3 percent.

Total fuel consumed for electric generation increased $27.6 million for 2001, primarily due to increased average fuel prices. The increased average fuel prices increased fuel expense by approximately 5.6 percent for 2001. Total fuel expenses for 2001 also increased due to the acquisition of three generating facilities in the Midwest on May 3, 2001.

Purchased Energy and Transmission: Purchased energy and transmission represents power purchases from and exchanges with other companies and purchases from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and consists of the following items:

For 2002, the Delivery and Services segment’s purchased power from PURPA generation increased $8.6 million primarily due to an increase in the average cost per kWh.

The Delivery and Services segment’s other purchased energy primarily consists of West Penn’s, Potomac Edison’s, and Monongahela’s purchases of energy from AE Supply. Pursuant to long-term power sales agreements that are approved by the FERC, AE Supply provides West Penn, Potomac Edison, and Monongahela with the amount of electricity, up to their PLR retail load, that they may demand. 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 pricing component escalates each year through the regulated utility subsidiaries’ electric deregulation transition periods. The increase in the Delivery and Services segment’s other purchased energy for 2002 and 2001 was primarily due to an increase in AE Supply prices, resulting from the market-based pricing component of the agreements, which has no overall effect on revenues for Allegheny.

The decrease in the Generation and Marketing segment’s purchased energy and transmission of $27.5 million for 2002 was primarily due to decreases in purchases made in support of physical energy supply commitments. The decrease in the Generation and Marketing segment’s purchased energy and transmission also reflects the decrease in wholesale market prices and additional generation capacity available for sale in the PJM market.

The increase in the Generation and Marketing segment’s purchased energy and transmission of $69.5 million in 2001 was primarily due to purchases made in support of various physical power supply commitments.

The elimination for purchased energy and transmission between the Delivery and Services segment and the Generation and Marketing segment is necessary to remove the effect of affiliated purchased energy and transmission expenses.

Natural Gas Purchases: Natural gas purchases for 2002, 2001, and 2000 were as follows:

Natural gas purchases represent the cost of natural gas for delivery to customers. The increase in natural gas purchases of $443.2 million for 2002 was primarily due to purchases made by Alliance Energy Services. This increase was also due to an increase in the price of natural gas purchases by Monongahela, including Mountaineer.

The increase in natural gas purchases of $161.0 million for 2001 was primarily due to the acquisition of Mountaineer in August 2000 and the acquisition of Alliance Energy Services in November 2001.

Other: Other cost of revenues, all related to the Delivery and Services segment, for 2002 and 2001 was $93.4 million and $43.6 million, respectively.

The increase in the Delivery and Services segment’s other cost of revenues of $49.8 million and $43.6 million for 2002 and 2001, respectively, was due to Allegheny Energy Solutions’ agreement to provide seven natural gas-fired turbine generators to the SMEPA.

Workforce Reduction Expenses: Workforce reduction expenses for 2002 were $51.1 million for the Delivery and Services segment and $56.5 million for the Generation and Marketing segment, for a total of $107.6 million. There were no workforce reduction expenses for 2001 and 2000.

In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction. Allegheny achieved workforce reductions of approximately 10 percent primarily through a voluntary ERO program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” For 2002, approximately 600 eligible employees accepted the ERO program, resulting in a charge of $82.6 million, before income taxes ($49.5 million, net of income taxes). Allegheny offered a Staffing Reduction Separation Program (SRSP) for employees whose positions were being eliminated as part of the workforce reductions and severance for certain energy trading employees. The SRSP provides for severance and other employee-related costs. For the year ended December 31, 2002, Allegheny recorded a charge of $25.0 million, before income taxes ($15.3 million, net of income taxes), related to approximately 80 employees whose positions have been or are being eliminated.

Operation Expense: Operation expenses for 2002, 2001, and 2000 were as follows:

Operation expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services, and other expenses. The increase in operation expenses for the Delivery and Services segment of $42.0 million for 2002 was primarily due to increases in outside services and operating expenses related to Fellon-McCord and Alliance Energy Services, which were acquired by Allegheny Ventures on November 1, 2001. The increase in operation expenses for the Generation and Marketing segment of $276.4 million for 2002 was primarily due to Allegheny recording charges of $244.0 million, before income taxes, for cancelled generation projects. The increase in operation expenses for the Generation and Marketing segment also includes the reorganization of Allegheny’s trading division, which resulted in a charge of approximately $21.0 million, before income taxes, related to costs associated with its relocation from New York to Monroeville, Pennsylvania, plus a $7.9-million loss for the abandoned leasehold improvements at the New York office. See Note 8 to the consolidated financial statements for additional information regarding restructuring charges.

The increase in the Delivery and Services segment’s operation expenses of $41.7 million for 2001 was primarily due to Monongahela’s acquisition of Mountaineer and Allegheny Ventures acquisition of Fellon-McCord and Alliance Energy Services in November 2001. The increase in the Delivery and Services segment’s expense was also partly due to activities by Allegheny Energy Solutions, primarily related to the SMEPA contract.

The increase in the Generation and Marketing segment’s other operation expenses of $148.6 million for 2001 was due to increased salary, general, and administrative expenses, resulting from the acquired energy trading business, and expenses related to the additional generating assets.

Depreciation and Amortization: Depreciation and amortization expenses for 2002, 2001, and 2000 were as follows:

Total depreciation and amortization expenses increased $7.1 million and $53.6 million for 2002 and 2001. The increase in 2002 was primarily due to additions of facilities in the Delivery and Services segment partially offset by the elimination of goodwill amortization in 2002. Effective January 1, 2002, Allegheny adopted SFAS No. 142 and, accordingly, ceased the amortization of all goodwill. Allegheny recorded goodwill amortization of $26.3 million and $2.2 million for 2001 and 2000, respectively, which primarily related to its acquisitions of Mountaineer on August 18, 2000, and the energy trading business on March 16, 2001. The increase in 2001 was primarily due to depreciation expenses related to the generating facilities in the Midwest that were acquired on May 3, 2001.

Taxes Other Than Income Taxes: Taxes other than income taxes for 2002, 2001, and 2000 were as follows:

Taxes other than income taxes primarily include gross receipts taxes, payroll taxes, property taxes, and capital stock/franchise taxes. Total taxes other than income taxes increased $9.4 million for 2002, primarily due to the gross receipts tax rate increasing from 4.4 percent to 5.9 percent for electric distribution companies in Pennsylvania, including West Penn.

Total taxes other than income taxes increased $6.2 million for 2001, primarily due to increased gross receipts taxes, resulting from higher Pennsylvania taxable revenues, increased West Virginia Business and Occupation taxes, and increased payroll taxes, resulting from a higher tax base due to the Mountaineer and energy trading business acquisitions.

Other income and expenses represent nonoperating revenues and expenses before income taxes. Other income and expenses decreased $63.5 million for 2002 primarily due to a charge of $44.7 million for unregulated investments determined to be impaired and a loss of $31.5 million on the sale of Fellon-McCord and Alliance Energy Services. These charges were partially offset by gains on Canaan Valley land sales of $22.4 million recognized by Monongahela and West Penn. Other income and expenses increased $9.1 million for 2001 primarily due to interest and dividend income, receipt of life insurance proceeds, and a gain on the sale of equipment. See Note 23 to the consolidated financial statements for additional details.

The increase in total interest charges and preferred dividends of $26.9 million and $49.8 million for 2002 and 2001, respectively, resulted from increased average long-term and short-term debt outstanding. The increase in average long-term debt outstanding was primarily the result of AE Supply 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, AE Supply issued $650.0 million of 8.25-percent notes due April 15, 2012. AE Supply 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 1,710 MW of generating assets in the Midwest in May 2001, and for general corporate purposes. In April 2002, West Penn issued $80.0 million of 6.625-percent notes due April 15, 2012. In May 2002, West Penn used the net proceeds

from the notes to redeem $70.0 million principal amount of 8.0-percent Quarterly Income Debt Securities (QUIDS) due June 30, 2025, and for other corporate purposes.

The eliminations for 2002, 2001, and 2000 were to remove the effect of interest expense on affiliated loans between the Delivery and Services segment and the Generation and Marketing segment.

For additional information regarding Allegheny’s short-term and long-term debt, see the consolidated statement of capitalization and Notes 12 and 16 to the consolidated financial statements. Also, see Financial Condition, Requirements and Resources-Liquidity and Capital Requirements for additional information concerning Allegheny’s debt restructuring.

Income tax related to continuing operations was a benefit of $334.5 million for 2002, and an expense of $248.2 million for 2001 and $187.4 million for 2000. The effective tax (benefit) expense rates were (39.6) percent, 35.2 percent, and 37.0 percent for 2002, 2001, and 2000, respectively. The 2002 effective tax rate reflects Allegheny’s pre-tax loss for the year. The change in the effective tax rate between 2001 and 2000, a net 1.8-percent decrease, was primarily caused by a net increase in tax deductible expenses over amounts recognized for financial reporting.

Note 15 to the consolidated financial statements provides a further analysis of income taxes.

Minority interest was $(13.5) million and $2.3 million for 2002 and 2001, respectively, which primarily represented Merrill Lynch’s equity membership interest in AE Supply. In March 2001, AE Supply acquired the energy trading business for $489.2 million plus the issuance of a 1.967-percent equity membership interest in AE Supply. By order dated May 30, 2001, the Securities and Exchange Commission (SEC) authorized the issuance of an equity membership interest in AE Supply to Merrill Lynch. Effective June 29, 2001, the transaction was completed. See Note 5 to the consolidated financial statements for additional information.

The extraordinary charge in 2000 of $77.0 million, net of income taxes, reflects a write-off by Allegheny’s subsidiaries, Monongahela and Potomac Edison, for net regulatory assets determined to be unrecoverable from customers and the establishment of a rate stabilization account for residential and small commercial customers as required by the deregulation plans adopted in Ohio, Virginia, and West Virginia. See Note 14 to the consolidated financial statements for additional information.

On January 1, 2002, Allegheny adopted SFAS No. 142. An assessment upon adoption determined that approximately $210.0 million of goodwill, primarily related to the acquisitions of Mountaineer and WVP, was impaired. As a result, Allegheny recorded a charge of $130.5 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2002. See Note 7 to the consolidated financial statements for additional information.

At January 1, 2001, AE Supply 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, AE Supply recorded a charge of $31.1 million against earnings, net of income taxes ($52.3 million, before income taxes), for these contracts as a change in accounting principle on January 1, 2001. See Note 9 to the consolidated financial statements for additional information.

The components of other comprehensive income include an adjustment related to the recognition of a minimum pension liability, available-for-sale securities, and cash flow hedges. The adjustment related to the minimum pension liability of $29.5 million, net of income taxes, which reduced other comprehensive income in 2002, was primarily due to the performance of the pension plan assets and an increase in the pension obligation due to a decrease in the discount rate from 7.25% in 2001 to 6.50% in 2002. In addition, other comprehensive income includes an unrealized gain for 2002 of $17.9 million and an unrealized loss for 2001 of $18.9 million for cash flow hedges. These amounts are presented net of income taxes, reclassifications to earnings, and minority interest. See Notes 9 and 10 to the consolidated financial statements for additional information regarding other comprehensive income.

To meet cash needs for operating expenses, the payment of interest, retirement of debt, and acquisitions and construction programs, Allegheny and its subsidiaries have used internally generated funds (net cash provided by operating activities less common and preferred dividends) and external financings, including the sale of common and preferred stock, debt instruments, installment loans, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, Allegheny’s and its subsidiaries’ cash needs, and capital structure objectives of Allegheny. The availability and cost of external financings depend upon the financial condition of the companies seeking those funds and market conditions.

During 2001, Allegheny issued $1,186.6 million of long-term debt and issued 14.3 million shares of common stock, resulting in net proceeds of approximately $667.0 million, primarily to finance its acquisition of an energy trading business, three generating facilities in the Midwest, and for other corporate purposes. During 2002, Allegheny issued $1,143.3 million of long-term debt to repay short-term and long-term indebtedness and for other corporate purposes. Allegheny may seek to engage in further financings to support capital expenditures and to maintain working capital. In addition, Allegheny’s wholesale marketing, energy trading, fuel procurement, and risk management activities require direct and indirect credit support. As of December 31, 2002, Allegheny had total indebtedness of $5,167.3 million.

As discussed in detail in ITEM 1. BUSINESS—Recent Events, various recent events left Allegheny in a weakened liquidity position in 2002, and this situation has continued into 2003. Allegheny has taken a number of recent actions to improve its financial condition. These steps include substantial senior management changes, completion of key financing transactions, exiting from Western United States energy markets, refocusing trading activities, asset sales, restructuring and cost-reducing initiatives, and improving internal controls and reporting.

Debt Covenants and Refinancing Principal Credit Facilities: On October 8, 2002, Allegheny announced that AE, AE Supply, and AGC were in technical default under their principal credit agreements after AE Supply declined to post additional collateral in favor of several trading counterparties. These collateral calls followed the downgrading of Allegheny’s credit rating below investment grade by Moody’s. During the period November 2002 through February 2003, AE, AE Supply and AGC obtained waivers of, and amended, certain covenants to these principal credit agreements. The total debt classified as current, in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived by the Creditor,” in the accompanying consolidated

balance sheet related to such defaults was approximately $2,110.4 million as of December 31, 2002. See the discussion below concerning other defaults on additional long-term debt that also resulted in the classification of that debt as current.

Allegheny and its subsidiaries have prepared their financial statements assuming that they will continue as going concerns. However, AE’s noncompliance with certain of its reporting obligations under its debt covenants and the resultant classification of certain debt as current has caused its independent auditors, PricewaterhouseCoopers LLP to issue a modified opinion that indicates there is substantial doubt about AE’s ability to continue as a going concern (a “Going Concern” opinion).

In addition, $380.0 million of indebtedness related to the discontinued St. Joseph, Indiana generating project, in the form of A-Notes, was restructured and assumed by AE Supply. Of this amount, $343.7 million is secured by substantially all of AE Supply’s assets, other than its new generating facility in Springdale, Pennsylvania. The secured portion of this debt bears an interest rate of 10.25 percent, and the unsecured portion bears interest at 13.0 percent. This debt matures in November 2007.

AE Supply borrowed $2,057.8 million under the Borrowing Facilities and the restructured A-Notes. Until August 1, 2003, after certain conditions associated with securing the collateral under the Borrowing Facilities were met on July 19, 2003, the LIBOR component charged AE Supply under the Borrowing Facilities with respect to secured borrowings had a two-percent floor. Also, since AE Supply was unable to secure all of the Borrowing Facilities and the restructured A-Note debt before July 31, 2003, the interest rates charged on the amounts not so secured increased to a spread of 10.5 percent over the applicable LIBOR or the designated money center bank’s base rate for the Refinancing Credit Facility and the Springdale Credit Facility and 13.0 percent for the unsecured portion of the A-Note debt retroactively to February 25, 2003. The total amounts unsecured under the Refinancing Credit Facility, the Springdale Credit Facility and the A-Note debt are approximately $94.3 million, $175.8 million and $36.3 million, respectively. A 30 percent limitation of available secured debt in AE Supply’s indenture will also make it difficult, if not impossible, for AE Supply to borrow additional funds until some of the secured debt under the Borrowing Facilities is repaid.

AE, Monongahela and West Penn borrowed a total of $340 million under the Borrowing Facilities, of which $25 million has been retired. AE was required to maintain a minimum equity to total capitalization ratio (Equity Ratio) of 28 percent as a condition of an SEC order issued under PUHCA. As of December 31, 2002, Allegheny did not meet this Equity Ratio requirement. As a result, future borrowings, or the ability to obtain financing through the issuance of debt obligations, may be restricted by the SEC at Allegheny.

The interest rate margins payable by AE Supply under certain of the Borrowing Facilities are tied to AE Supply’s credit ratings. Should AE Supply’s credit ratings improve from its current ratings of B2 by Moody’s, B by Standard and Poor’s, and B+ by Fitch to certain specified higher ratings, the rate of interest AE Supply would be required to pay under the Refinancing Credit Facility and the Springdale Credit Facility could decrease by .5 percent to 1.0 percent for the secured portion of those credit facilities. AE Supply’s credit ratings would need to improve to BB/Ba2 to achieve a .5 percent decrease in the interest rates and BB+/Ba1 or higher to achieve a 1.0 percent decrease in the interest rates.

AE is required to meet certain financial tests, as defined in the Borrowing Facilities agreements, including:

AE Supply also is required to meet certain financial tests, as defined in the Borrowing Facilities agreements, including:

Effective July 22, 2003, AE and AE Supply were granted waivers from compliance with all of the above financial tests for the first and second quarters of 2003. Effective August 22, 2003, AE and AE Supply received additional waivers of the financial tests for the third quarter of 2003.

The Borrowing Facilities also have provisions requiring prepayments out of the proceeds of asset sales and debt and equity issuances, as follows:

Any prepayments under the provisions of the Borrowing Facilities would reduce the amounts of scheduled principal payments in 2003 and 2004.

AE had several debt agreements that required it to file copies of its annual or quarterly reports as filed with the SEC pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) with or for the debt holders. AE is also required to deliver to or for the debt holders a certificate indicating that Allegheny has complied with all conditions and covenants under the agreements. On April 30, 2003, AE provided certificates to the trustees under its indentures indicating that it was not in compliance with the covenants for filing its annual and quarterly reports that are contained in its First Mortgage Bonds and Debentures. These covenant breaches are deemed defaults of such First Mortgage Bonds and Debentures, as well as defaults of indebtedness subject to cross-acceleration with such First Mortgage Bonds and Debentures, including certain Pollution Control Bonds and other debt, for AE’s financial reporting purposes in accordance with EITF Issue No. 86-30. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was approximately $1,551.8 million as of December 31, 2002. To date, the debt holders have not provided AE with any notices of default under the agreements. Such notices, if received, would allow AE either 30 or 60 days to cure its noncompliance before the debt holders could accelerate the due dates of the debt obligations.

As of December 31, 2002, $90.0 million was outstanding under two Mountaineer Note Purchase Agreements. These Note Purchase Agreements contain covenants that required Mountaineer to deliver annual financial statements, an audited 2002 annual report, and certain certificates to the noteholders by March 31, 2003. Mountaineer did not deliver these items to the noteholders by March 31, 2003. Effective July 23, 2003, Mountaineer obtained waivers extending the covenant due dates until September 30, 2003, for the 2002 annual financial statements and audited report. Also, Mountaineer has obtained waivers until October 31, 2003, and December 1, 2003, for the delivery of its unaudited financial statements to the noteholders for the first and second quarters of 2003, respectively. These amounts are also classified as current in the accompanying consolidated balance sheets.

Private Placement: On July 24, 2003, AE obtained $291 million ($275 million after deducting various fees and placement agents’ commissions) from the issuance to a special purpose finance subsidiary of AE, Allegheny Capital Trust I (Capital Trust), of units comprised of $300 million principal amount of AE’s 11⁷/8 percent Notes due 2008 and warrants for the purchase of up to 25 million shares of AE’s common stock, exercisable at $12 per share. The warrants are mandatorily exercisable if AE’s common stock price equals or exceeds $15 per share over a specified averaging period occurring after June 15, 2006. The warrants are stapled to the notes and may be exercised only through the tender of the notes. The finance subsidiary obtained proceeds required to purchase the units by issuing $300 million liquidation amount of its 11⁷/8 percent Mandatorily-Convertible Trust Preferred Securities to investors in a private placement. The holder of a preferred security is entitled to distributions on a corresponding principal amount of notes and may direct the exercise of warrants stapled to the notes to effect the conversion of the preferred security into AE common stock. AE guarantees Capital Trust’s payment obligations under the preferred securities. In accordance with GAAP, AE’s consolidated balance sheet will reflect the notes as long-term debt. The notes and AE’s guarantee of Capital Trust’s payment obligations are subordinated only to indebtedness arising under the agreements governing certain of AE’s indebtedness under the Borrowing Facilities.

Exiting from Western United States Energy Markets: Allegheny worked through 2003 to accomplish AE Supply’s effective exit from the Western United States power markets. Its positions based in the Western United States had been a substantial source of earnings and cash flow volatility and risk, and trading in these markets does not fit with Allegheny’s new business model.

Renegotiation and Sale of CDWR contract. In June 2003, AE Supply entered into a settlement agreement with the State of California to resolve the state’s litigation regarding its power supply contract with the CDWR. The terms of the settlement reduced the volume of power to be delivered from 2005-2011 and reduced the sale price of off-peak power to be delivered from 2004-2011, which in turn substantially reduced the value of the contract. (See Note 26 to the consolidated financial statements under “Other Litigation-CDWR” for additional information).

On September 15, 2003, Allegheny closed the sale of the CDWR contract and associated hedge transactions, to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc., for approximately $354 million. Allegheny has applied $214 million of the sale proceeds to required payments under agreements entered into to terminate tolling agreements with Williams Energy Marketing and Trading Company (Williams) and Las Vegas Cogeneration II (LV Cogen), a unit of Black Hills Corporation, as described below. Allegheny will apply an additional $28 million of the proceeds to make additional payments in March and September of 2004 under the agreement with Williams. Approximately $26 million will be held in a pledged account for the benefit of AE Supply’s creditors. This arrangement is intended to enhance AE Supply’s ability to refinance certain secured borrowings. Approximately $71 million of the sale proceeds was placed in escrow for the benefit of J. Aron & Company, pending Allegheny’s fulfillment of certain post-closing requirements. When the escrowed funds are released, approximately $50 million will be added to the pledged account and AE Supply will receive the balance. The remaining $15 million of sale proceeds will be used to partially offset certain of the hedges related to the CDWR contract and to pay fees and expenses associated with the transaction.

As of December 31, 2002, the fair value of the CDWR contract and related hedges sold to J. Aron & Company plus the Williams and LV Cogen tolling agreements was $554.5 million. From January 1, 2003, through the date that these contracts were either sold or agreements were reached to terminate the contracts, the aggregate fair value of the contracts decreased by approximately $462.7 million to $91.8 million. As a result of the sale of the CDWR contract and related hedges and the terminations of the Williams and LV Cogen tolling agreements, Allegheny incurred a net loss of approximately $50.4 million, before income taxes, in the third quarter of 2003. This loss was determined excluding the approximately $70.8 million of sale proceeds that were placed in escrow pending Allegheny’s fulfillment of certain post-closing requirements. Allegheny expects to meet these requirements in the fourth quarter of 2003, at which time the net loss would be revised from approximately $50.4 million, before income taxes, to a net gain of approximately $20.4 million, before income taxes.

After completing these major transactions, Allegheny’s remaining trading exposures to the Western United States market will consist of several shorter-term trades that hedged the CDWR contract and several long-term hedges of the LV Cogen tolling agreement. Allegheny continues to seek to unwind these remaining positions.

Refocusing Trading Activities: Adoption of Asset-Based Trading Strategy. AE Supply is reorienting its trading operations from high-volume financial trading in national markets to asset optimization and hedging within its region. AE Supply is implementing this rebalancing over time as its liquidity allows. Effectively exiting the Western United States power markets, together with unwinding substantial non-core trading positions, has enabled AE Supply to reduce long-term trading-related cash out flows and collateral obligations. In the future, AE Supply will seek to concentrate its efforts in the PJM, the Midwest, and Mid-Atlantic markets where it has a physical presence and greater market knowledge. Ultimately, AE Supply intends to conduct asset optimization and hedging activities with the primary objective of locking in cash flows associated with AE Supply’ portfolio of core physical generating and load positions.

Asset Sales: In 2002, Allegheny announced that it was considering selling assets as part of an overall strategy to address its liquidity requirements. Allegheny has achieved the sale of its most significant assets with a nexus to the Western United States. Allegheny has also closed the sale of its interest in the Conemaugh Generating Station, as described below. Allegheny continues to consider the sale of additional assets, especially non-core assets.

Land Sales. Effective February 14, 2002, West Penn, through its subsidiary West Virginia Power and Transmission Company, sold 12,000 acres of land in Canaan Valley, West Virginia, to the U.S. Fish & Wildlife Service for $16 million. Effective December 18, 2002, it also sold a 2,468-acre trac of land for $6.9 million and made a charitable contribution of a 740 acre tract in Canaan Valley, West Virginia, to Canaan Valley Institute.

Fellon-McCord and Alliance Services, LLC. Effective December 31, 2002, AE sold Fellon-McCord, its natural gas and electricity consulting and management services firm, and Alliance Energy Services, LLC, (Alliance Energy Services) a provider of natural gas supply and transportation services, to Constellation Energy Group for approximately $21.8 million.

This contingent amount could be received in full, in part, or not at all, depending upon AE Supply’s performance of certain post-closing obligations.

Restructuring and Cost-Reducing Initiatives: Allegheny has taken several actions to align its operations with its strategy and reduce its cost structure.

Suspension of Dividends. The Board of Directors of AE determined not to declare a dividend on AE’s common stock for the fourth quarter of 2002. Covenants contained in Allegheny’s new Borrowing Facilities entered into in February 2003, and in the indenture entered into in connection with the convertible trust preferred securities issuance in July 2003, as well as regulatory limitations under PUHCA, are expected to preclude AE from declaring or paying cash dividends for the foreseeable future.

Elimination of Preemptive Rights. On March 14, 2003, AE’s common stockholders approved an amendment to AE’s articles of incorporation eliminating common stockholders’ preemptive rights. The elimination of preemptive rights removes an obstacle to AE’s ability to privately place equity or convertible securities.

Improving Internal Controls and Reporting: Comprehensive Accounting Review. Commencing in the third quarter of 2002, Allegheny undertook a comprehensive and extended review of its financial information and internal controls and procedures. This review included continuous efforts by Allegheny’s top management and directors and extensive involvement of independent auditors and other outside service firms. Allegheny continues to address its controls environment and reporting procedures, as well as its SEC filing and other outstanding reporting obligations. See ITEM 14. CONTROLS AND PROCEDURES, for a detailed discussion.

Other Matters Concerning Liquidity and Capital Requirements: Allegheny’s wholesale marketing, energy trading, fuel procurement, and risk management activities require direct and indirect credit support. The amount of credit support required is affected by market price changes for electricity, natural gas, and other energy-related commodities and Allegheny’s credit rating. Such credit support might be in the form of letters of credit, cash deposits, or liquid securities. As previously discussed, Allegheny announced on October 8, 2002, that AE, AE Supply, and AGC were in technical default under their principal credit agreements after AE Supply declined to post additional collateral in favor of several trading counterparties. This default resulted in 24 trading counterparties terminating trades with Allegheny by December 31, 2002. Of these trading counterparties, Allegheny has settled with nine counterparties for a net cash inflow of $6.8 million. As of December 31, 2002, Allegheny had recorded an accounts receivable of $9.0 million for payments due from terminated trading counterparties and had recorded an accounts payable for $40.6 million due to terminated trading counterparties. In early 2003, Allegheny proposed payment schedules with the remaining counterparties to settle the accounts payable by the end of 2003.

Allegheny and certain of its subsidiaries have established credit facilities, or lines of credit, that provide for direct borrowings and the issuance of letters of credit to support general corporate purposes and energy trading

activities. At December 31, 2002, $1,229.9 million of the $1,300.0 million lines of credit with banks were drawn. All of the $70.1 million remaining lines of credit were unavailable.

Allegheny and certain of its subsidiaries have also executed letter of credit facilities to provide for additional capacity of $612.7 million. AE Supply regularly posts cash deposits or letters of credit with counterparties to collateralize a portion of its energy trading obligations. At December 31, 2002, there was $126.6 million outstanding under Allegheny’s letter of credit facilities.

Allegheny has various obligations and commitments to make future cash payments under contracts such as debt instruments, lease arrangements, fuel agreements, and other contracts. The table below provides a summary of the payments due by period for these obligations and commitments as of December 31, 2002. This table does not include capacity contract commitments that were accounted for under fair value accounting, as discussed under “Operating Revenues,” or contingencies.

Amounts related to debentures, notes, and bonds in this table represent contractual cash payments required without taking into account their classification as current, as a result of a default in the underlying debt agreements, on the consolidated balance sheet. (See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, and Note 3 to AE’s consolidated financial statements, “Debt Covenants and Liquidity Strategy,” for additional information). As Allegheny has refinanced its Borrowing Facilities as of February 25, 2003, the contractually required payments under its Borrowing Facilities, as of that date, are as follows:

Allegheny’s capital expenditures, including construction expenditures, of all of the subsidiaries for 2003 and 2004 are estimated at $362.0 million and $304.3 million, respectively. These estimated expenditures include

$63.7 million and $90.9 million, respectively, for environmental control technology. See Note 26 to the consolidated financial statements for additional information.

In 2003, Allegheny’s cash flows are expected to be adequate to meet all of its payment obligations under the debt agreements, including the outstanding notes, and to fund other working capital needs. Allegheny’s ability to meet its payment obligations, beginning in 2004, under its indebtedness, including outstanding notes, and to fund capital expenditures will depend on its future performance. Allegheny’s future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control. Allegheny expects that cash flows from operations in itself, will not be sufficient to cover future obligations in 2004. Allegheny expects that it will need to sell certain assets or arrange for alternative financing in order to repay the principal amounts under the Borrowing Facilities scheduled for the third and fourth quarters of 2004. See Note 3 to the consolidated financial statements for additional information.

Internal generation of cash, consisting of cash flows from operations reduced by common and preferred dividends, was $174.5 million in 2002, compared with $139.8 million in 2001.

Cash flows from operations for 2002 decreased $9.4 million versus 2001. Allegheny’s cash flows from operations include the results of its energy trading activities. For 2002 and 2001, the energy trading activities resulted in approximately $239.7 million and $223.2 million of net cash outflows, respectively. See “Operating Revenues” for additional details regarding the cash outflows for the energy trading activities. Allegheny’s cash paid for interest for 2002 was $289.9 million versus $259.4 million for 2001.

Cash flows used in investing for 2002 decreased $1,759.0 million from 2001. In 2001, AE Supply paid approximately $1,626.8 million for the acquisition of an energy trading business, an interest in the Conemaugh Generating Station, and the purchase of three generating facilities in the Midwest. Also, in 2001, Allegheny Ventures paid $30.5 million to acquire two businesses. Construction expenditures during 2002 and 2001 were $403.1 million and $463.3 million, respectively.

Cash flows provided by financing for 2002 decreased $1,603.3 million from 2001. This decrease was primarily due to a $314.6-million increase in the retirement of long-term debt, a $623.1-million decrease in net short-term debt financing, and a $666.5-million decrease in the proceeds from issuance of common stock.

Cash flows from operations in 2001 declined $202.8 million. Allegheny’s cash flows from operations include the results of its energy trading activities, which resulted in approximately $223.2 million of net cash outflows. See “Operating Revenues” for additional details regarding the cash outflows for the energy trading activities.

Cash flows used in investing increased $1,501.8 million for 2001. In 2001, AE Supply paid approximately $1,626.8 million for the acquisition of an energy trading business, an interest in the Conemaugh Generating Station, and the purchase of three generating facilities in the Midwest. Also, in 2001, Allegheny Ventures paid $30.5 million to acquire two businesses. Construction expenditures were $463.3 million for 2001, compared to $402.4 million for 2000.

Cash flows provided by financing increased $1,772.5 million for 2001, primarily due to $670.5 million net proceeds for the issuance of common stock, a $707.6-million increase in net proceeds from the issuance of long-term debt, and a $451.2-million increase in net short-term financing.

Dividends paid on common stock for 2002 were $.43 per share for the first three quarters and for 2001 were $.43 per share for four quarters. In December 2002, Allegheny suspended its quarterly cash dividend on its common stock. The dividend payout ratio was 46.5 percent in 2001, excluding the cumulative effect of accounting change.

Common Stock: On May 2, 2001, AE completed a public offering of its common stock, selling a total of 14.3 million shares priced at $48.25 per share. A portion of the net proceeds of approximately $667.0 million was used to partially fund AE Supply’s acquisition of generating facilities located in the Midwest. Of the 14.3 million shares of common stock sold, 12.0 million shares were related to treasury stock that had been repurchased by AE in 1999 under Allegheny’s stock repurchase program at an aggregate cost of $398.4 million.

Also during 2002 and 2001, AE issued 1.3 million and .6 million shares of its common stock for $26.7 million and $23.2 million, respectively, primarily under its Dividend Reinvestment and Stock Purchase Plan, Long-term Incentive Plan, and Employee Stock Ownership and Savings Plan.

Debentures, Notes, Bonds and QUIDS: During 2002, Allegheny made the following repayments and redemptions of debentures, notes, bonds and QUIDS: West Penn Funding repaid $70.3 million of transition bonds; AE Supply repaid $80.0 million of floating rate medium-term debt; West Penn redeemed $70.0 million principal amount of 8.0-percent QUIDS and repaid $33.6 million of 5.6-percent fixed-rate medium-term debt; Monongahela redeemed $25.0 million of 7.4-percent fixed-rate first mortgage bonds; Mountaineer made repayments of $3.3 million on 7.6-percent fixed-rate unsecured notes; AFN Finance Company No. 2, LLC, a subsidiary of ACC, repaid $10.5 million of floating rate medium-term debt; and AE Supply and Monongahela redeemed $5.6 million of pollution control bonds per their original terms.

In April 2002, AE Supply issued $650.0 million of 8.25-percent notes due April 15, 2012. AE Supply 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 generating assets, and for general corporate purposes.

In April 2002, West Penn issued $80.0 million of 6.625-percent notes due April 15, 2012. In May 2002, West Penn used the net proceeds from the notes to redeem $70.0 million principal amount of 8.0-percent QUIDS due June 30, 2025, at a redemption price of 100 percent of their principal amount plus accrued interest to the redemption date, and for other corporate purposes.

See “Operating Lease Transactions” below and Note 26 to the consolidated financial statements for additional information regarding debt recorded on Allegheny’s consolidated balance sheet at December 31, 2002, from an operating lease transaction for a generating facility.

See Note 12 to the consolidated financial statements for additional details regarding debt issued and redeemed during 2002 and 2001 and additional capital requirements for debt maturities.

The amount of debt due, contractually, within one year at December 31, 2002, was $257.2 million and represents: $76.0 million of West Penn Funding’s transition bonds; $19.1 million of Monongahela’s and AE Supply’s installment purchase obligations; $61.5 million of Mountaineer’s and AE Supply’s secured notes; $3.3 million of Mountaineer’s unsecured notes; $47.3 million of AE’s and Monongahela’s medium-term notes; and $50.0 million of AGC’s debentures. The transition bonds are supported by an Intangible Transition Charge (ITC) that replaces a portion of the Competitive Transition Charge (CTC) that customers pay. The proceeds from the ITC will be used to pay the principal and interest on these transition bonds, as well as other associated expenses.

Short-term Debt: Short-term debt decreased $106.8 million during 2002 to $1,132.0 million as of December 31, 2002, and consists only of lines of credit. At December 31, 2002, $1,229.9 million of the $1,300.0 million lines of credit with banks were drawn. All of the $70.1 million remaining lines of credit were unavailable. See Note 16 to the consolidated financial statements for additional details regarding short-term debt activity during 2002 and 2001.

Operating Lease Transactions: In November 2001, AE Supply entered into an operating lease transaction to finance construction of a 630-MW generating facility in St. Joseph County, Indiana. As of December 31, 2002, AE Supply recorded the facility on its consolidated balance sheet, as it was deemed the owner of the facility under EITF No. 97-10, “The Effect of Lessee Involvement in Asset Construction,” as a result of lessor reimbursement for construction expenditures. As a result, AE Supply recorded approximately $415.5 million of debt related to this obligation, including costs associated with terminating the project, on its consolidated balance sheet at December 31, 2002. In February 2003, AE Supply purchased the project by assuming $380.0 million of the lessor’s long-term debt and paying an additional $35.5 million financed with debt. Following the purchase of the facility, Allegheny terminated the project resulting in a write-off of $192.0 million, before income taxes ($118.4 million, net of income taxes).

In April 2001, AE Supply entered into an operating lease transaction structured to finance the purchase of turbines and transformers. In November 2001, some of the equipment was used for the St. Joseph generating project. In May 2002, AE Supply terminated the lease and the remainder of the equipment was purchased by an unconsolidated joint venture that placed an 88-MW generating facility in southwest Virginia into commercial operation in June 2002.

In November 2000, AE Supply entered into an operating lease transaction to finance construction of a 540-MW generating facility in Springdale, Pennsylvania. As of December 31, 2002, AE Supply’s maximum recourse obligation under the lease was approximately $249.1 million, reflecting lessor investment of $276.9 million. In February 2003, AE Supply purchased the facility for $318.4 million financed with debt. The facility went into commercial operation in July 2003.

Effective January 1, 2001, Allegheny adopted SFAS No. 133, which established accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives), and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The standards require that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in earnings or other comprehensive income and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

On January 1, 2001, AE Supply recorded an asset of $1.5 million on its consolidated balance sheet based on the fair value of its two cash flow hedge contracts. An offsetting amount was recorded in other comprehensive income as a change in accounting principle as provided by SFAS No. 133. AE Supply’s risk management objectives regarding these cash flow hedge contracts were as follows: 1) to provide electricity in situations where the customers’ demand for electricity exceeded Allegheny’s electric generating capacity and 2) to protect Allegheny from price volatility for electricity.

before income taxes ($3.1 million, net of income taxes), was reclassified to purchased energy and transmission expense from other comprehensive income during the third quarter of 2001.

AE Supply also had certain option contracts that met the derivative criteria in SFAS No. 133, which did not qualify for hedge accounting. On January 1, 2001, AE Supply recorded an asset of $.1 million and a liability of $52.4 million on its consolidated balance sheet based on the fair value of these contracts. In accordance with SFAS No. 133, AE Supply recorded a charge of $31.1 million against earnings, net of income taxes ($52.3 million, before income taxes), for these contracts as a change in accounting principle on January 1, 2001. As of December 31, 2001, these contracts had expired, thus reducing their fair value to zero. The total change in fair value of $52.3 million for these contracts during 2001 was recorded through operating revenues on the consolidated statement of operations.

On March 19, 2002, AE Supply 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. In April 2002, these contracts were settled for a loss of $1.6 million, before income taxes ($1.0 million, net of income taxes). The unrealized loss was recorded in other comprehensive income. In April 2002, AE Supply began reclassifying to earnings the amounts in accumulated other comprehensive income for these treasury lock agreements over the life of the 10-year debt. For 2002, $.1 million, before income taxes ($.1 million, net of income taxes), was reclassified from accumulated other comprehensive income to earnings.

On August 1, 2000, Allegheny issued a $165.0-million 7.75-percent fixed-rate note and a $135.0-million 7.75-percent fixed-rate note. Each note matures on August 1, 2005, and requires semi-annual interest payments on August 1 and February 1. On April 24, 2002, Allegheny entered into an interest rate swap to convert the notes’ fixed rates to variable rates for the notes’ remaining terms. Under the term of the swap, Allegheny receives interest at a fixed-rate of 7.75 percent and pays interest at a variable rate equal to the three-month LIBOR plus a fixed spread. Allegheny designated the swap as a fair-value hedge of changes in the general level of market interest rates. During September 2002, the interest rate swap was terminated by Allegheny at its fair value of $11.3 million. As a result, Allegheny has discontinued its fair value hedge accounting. The increase in the carrying amount of the fixed-rate notes of $11.3 million as a result of the fair value hedge accounting is being amortized over the remaining life of the notes. For 2002, $1.5 million, before income taxes ($.9 million, net of income taxes), was amortized to the consolidated statement of operations.

As of June 30, 2002, Allegheny recorded a liability in other current liabilities and an unrealized loss in operating revenues for derivative instruments of $6.1 million for 10 wholesale electricity contracts. For the third quarter of 2002, Allegheny recorded an unrealized gain of $3.5 million for these contracts. In September 2002, Allegheny made operational changes regarding the delivery of electricity under these contracts. As a result, these contracts now qualify for the normal purchases and normal sales exception under SFAS No. 133.

On November 1, 2001, Allegheny Ventures completed the acquisition of Fellon-McCord and Alliance Energy Services. Effective December 31, 2002, Allegheny Ventures sold Fellon-McCord and Alliance Energy Services. Alliance Energy Services was engaged in the purchase, sale, and marketing of natural gas and other energy-related services to various commercial and industrial customers across the United States. Alliance Energy Services, on behalf of its customers, used both physical and financial derivative contracts, including forwards, NYMEX futures, options, and swaps, in order to manage price risk associated with its purchase and sales activities. These derivative contracts were accounted for as cash flow hedges.

Alliance Energy Services’ primary strategy was to minimize its market risk exposure with respect to its forecasted physical natural gas sales contracts to its customers by entering into offsetting financial and physical natural gas purchase and transportation contracts. The transactions executed under this strategy were accounted

for as cash flow hedges, with the fair value of the offsetting contracts recorded as assets and liabilities on the consolidated balance sheet and changes in fair value for these contracts recorded to other comprehensive income. For 2002, an unrealized gain of $31.2 million, net of reclassifications to earnings, income taxes, and minority interest, was recorded to other comprehensive income for these contracts. For 2001, an unrealized loss of $18.9 million, net of reclassifications to earnings and income taxes, was recorded to other comprehensive income for these contracts. These hedges were highly effective during 2002 and 2001.

Additionally, as a service to its customers, Alliance Energy Services offered price risk intermediation services in order to mitigate the market risk associated with natural gas. Under this program, Alliance Energy Services would execute positions with the customer and enter into offsetting positions with a third counterparty. These transactions did not qualify for hedge accounting under SFAS No. 133 and were accounted for on a mark-to-market basis.

As a result of Allegheny Ventures’ sale of Fellon-McCord and Alliance Energy Services, Allegheny’s consolidated balance sheet as of December 31, 2002, does not include any amounts for the fair value of Alliance Energy Services’ derivative instruments.

In June 2002, the EITF reached a consensus on Issue No. 02-3, 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 was applicable to financial statements for periods ending after July 15, 2002. During 2002, Allegheny modified its reporting as a result of the EITF consensus to reflect the revenues from energy trading activities net of the cost of purchased energy and transmission related to contracts that require physical delivery. In addition, amounts for 2001 and 2000 were adjusted for comparability to reflect the adoption of the EITF consensus. As a result, Allegheny’s 2001 and 2000 operating revenues and cost of revenues are lower than previously reported, with no effect on consolidated net revenues or net income.

At the October 2002 EITF meeting, the EITF reached a consensus to rescind Issue No. 98-10. In reaching this consensus, the EITF also reached consensus on other related items which will have the following effects on Allegheny:

The implementation of EITF Issue No. 02-3 will result in Allegheny recording a cumulative effect of an accounting change of approximately $11.9 million, net of income taxes ($19.7 million, before income taxes), in the first quarter of 2003. This charge will represent the fair value of those contracts previously accounted for under EITF Issue No. 98-10 that no longer qualify for mark-to-market accounting.

Effective January 1, 2002, Allegheny adopted SFAS No. 141, “Business Combinations,” and SFAS No. 142. The application of SFAS No. 142 resulted in Allegheny eliminating the amortization of goodwill and recognizing impairment losses on the goodwill in its Delivery and Services segment. As required by SFAS No. 142, Allegheny must continue to evaluate the remaining goodwill related to the acquisition of the energy trading

business for potential impairment at least annually. See Note 7 to the consolidated financial statements for details regarding Allegheny’s implementation of SFAS Nos. 141 and 142.

Effective January 1, 2002, Allegheny adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 establishes a singular accounting model for the disposal of long-lived assets and carries forward the impairment provisions of SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.”

Effective January 1, 2003, Allegheny adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. See Note 25 to the consolidated financial statements for additional information.

In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which requires disclosures by a guarantor concerning its obligations under certain guarantees that it has issued. FIN 45 also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issued or modified after December 31, 2002. Allegheny does not anticipate FIN 45 will have a material effect on its statement of operations and financial position. See Note 26 to the consolidated financial statements for additional information regarding guarantees.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities,” which addresses consolidation by business enterprises of variable interest entities, commonly referred to as “special purpose entities.” FIN 46 requires consolidation where there is a controlling financial interest in a variable interest entity or where the variable interest entity does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties. Allegheny will apply the provisions of FIN 46 prospectively for all variable interest entities created after January 31, 2003. For variable interest entities created prior to January 31, 2003, Allegheny will be required to consolidate all variable interest entities in which it is the primary beneficiary, as of the third quarter of 2003. Allegheny does not believe that FIN 46 will have a material effect on its statement of operations and financial position.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” which requires certain financial instruments that have historically been classified as equity to be classified as liabilities (or as an asset in certain circumstances). SFAS No. 150 is effective for Allegheny’s financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. In accordance with SFAS No. 150, Allegheny will classify its 11⁷/8 percent convertible trust preferred securities, issued on July 24, 2003, as a liability.

Various other new accounting pronouncements not mentioned above that were effective in 2002 do not have a material effect on Allegheny’s consolidated results of operations, cash flows, and financial position. Also, Allegheny expects that various other new accounting pronouncements, not mentioned above effective in 2003, will not have a significant impact on Allegheny’s consolidated financial statements.

ITEM 7. Management’s Discussion And Analysis Of Financial Condition And Results Of Operations

Allegheny Energy, Inc. (AE) and its consolidated subsidiaries (collectively, Allegheny), including its subsidiary Allegheny Energy Supply Company, LLC (AE Supply), have experienced significant changes in their businesses over the last several years, as described in ITEM 1. BUSINESS—Recent Events. During 2002, Allegheny and AE Supply experienced a strain on their liquidity positions, and, at December 31, 2002, a significant portion of their debt has been reclassified as current, as discussed in Financial Condition, Requirements and Resources. Also, AE Supply incurred a net loss of $583.7 million in 2002, primarily due to trading losses and adverse wholesale energy market conditions as discussed below in Earnings Summary.

In 2002, Allegheny, including AE Supply, identified various errors relating to its financial statements for years prior to 2002 as a result of a comprehensive financial review as discussed in Note 2 to the financial statements. Corrections to these errors are reflected in the financial statements for the year ended December 31, 2002, and increased the net loss for 2002 by approximately $9.3 million for AE Supply. Except for certain restatement adjustments to the consolidated balance sheet as of December 31, 2001, Allegheny’s management concluded that these errors were not material, either individually or in the aggregate, to the 2002 or any prior years’ financial statements.

AE Supply is an unregulated (i.e., not subject to state rate regulation) energy company and a subsidiary of AE that develops, owns, operates, and manages electric generating facilities and, through its fuel and power markets division, purchases and sells energy and energy-related commodities. AE Supply manages its generating assets as an integral part of its wholesale marketing, fuel procurement, risk management, and asset-backed energy trading activities. As of December 31, 2002, AE Supply owned or contractually controlled 9,924 MW of generating capacity (including the contractual right to call up 1,000 MW). Of this capacity, 6,230 MW were transferred from West Penn Power Company (West Penn), The Potomac Edison Company (Potomac Edison), and Monongahela Power Company (Monongahela) at net book value. These transfers included West Penn’s, Potomac Edison’s, and Monongahela’s Ohio ownership in Allegheny Generating Company (AGC) of 77.03 percent. AE Supply operates under a single segment, Generation and Marketing.

Use of Estimates: The preparation of financial statements in conformity with GAAP requires AE Supply to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. The estimates that require management’s most difficult, subjective, and complex judgments involve the fair value of commodity contracts and derivative instruments, goodwill, and long-lived assets. Significant changes in the estimates could have a material effect on AE Supply’s results of operations, cash flows, and financial position.

Commodity Contracts: Through December 31, 2002, commodity contracts related to AE Supply’s energy trading activities were recorded at their fair value in accordance with the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Energy Trading and Risk Management Activities.” As of January 1, 2003, EITF Issue No. 98-10 was rescinded. However, the vast majority of AE Supply’s commodity contracts continue to be recorded at their fair value under the FASB’s Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133—an amendment of FASB Statement No. 133,” and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities—an amendment of FASB Statement No. 133” (collectively referred to as SFAS No. 133). At December 31, 2002, the fair value of AE Supply’s commodity contracts represented a net asset position of $428.2 million. Fair values for exchange-traded instruments, principally futures and certain options, are based on actively 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 and estimated market data and pricing models, which may change from time to time. AE Supply has several 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. AE Supply’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 reduced market liquidity, have significantly affected the merchant energy marketplace during 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 AE Supply’s financial position, cash flows, 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. AE Supply’s accounting for commodity contracts is discussed under “Operating Revenues” and Note 4 to the consolidated financial statements. Also, see Note 9 to the consolidated financial statements and “Derivative Instruments and Hedging Activities” for additional information regarding our accounting for derivative instruments under SFAS No. 133.

In addition to the above, the fair value of AE Supply’s commodity contracts can be affected by regulatory challenges involving deregulation of energy prices and markets. The California Public Utility Commission (California PUC), the California Department of Water Resources (CDWR), and the California Electricity Oversight Board (CAEOB) challenged the contracts between the CDWR and AE Supply. In June 2003, AE Supply entered into a settlement agreement with the State of California to resolve the state’s litigation regarding its power supply contract with the CDWR. The terms of the settlement reduced the volume of power to be delivered from 2005-2011 and reduced the sale price of off-peak power to be delivered from 2004-2011, which

in turn substantially reduced the value of the contract. The following table shows the renegotiated prices and volumes:

The contract’s terms initially provided for a peak and off-peak price per MWh of $61 for the duration of the contract at a volume of 250 MW in 2003, 500 MW in 2004 and 1,000 MW from 2005-2011. As a result of the renegotiation of the contract with the CDWR, AE Supply estimates that the fair value of the agreement decreased by a range of $160 to $190 million. The renegotiation of the contract terms was part of the agreement to settle litigation with the State of California regarding the contract’s validity. Allegheny closed the sale of the contract to a subsidiary of The Goldman Sachs Group, Inc. in September 2003.

The California PUC and the FERC approved the renegotiated agreement, effective August 15, 2003. The modified terms and conditions included in the renegotiated agreement will result in a reduction to the fair value of the CDWR contract, with a corresponding reduction in earnings.

See Note 23 to the consolidated financial statements for additional information regarding the renegotiated agreement with the CDWR. See also “Financial Condition, Requirements and Resources—Liquidity and Capital Requirements” and Notes 3 and 4 for information regarding agreements entered into by AE Supply to sell the CDWR power supply contract, and associated hedge transactions, and to terminate two tolling agreements in the Western United States energy markets.

Excess of Cost Over Net Assets Acquired (Goodwill): As of December 31, 2002, AE Supply’s intangible asset for acquired goodwill was $367.3 million related to the acquisition of an energy marketing and trading business in March 2001. Effective January 1, 2002, with the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets,” AE Supply ceased amortization of goodwill and now tests goodwill for impairment at least annually. For AE Supply, the estimation of the fair value of its single reporting unit, which is the entity as a whole, involves the use of present value measurements and cash flow models. This process involves judgments on a broad range of information. Significant changes in the fair value estimates could have a material effect on AE Supply’s results of operations and financial position.

Long-Lived Assets: AE Supply’s consolidated balance sheet includes significant long-lived assets. AE Supply must generate future cash flows from such assets in a non-regulated environment to ensure the carrying value is not impaired. Certain of these assets are the result of capital investments that have been made in recent years and have not yet reached a mature life cycle. AE Supply assesses the carrying amount and potential impairment of these assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors AE Supply considers in determining if an impairment review is necessary include a significant underperformance of the assets relative to historical or projected future operating results, a significant change in AE Supply’s use of the assets or business strategy related to such assets, and significant negative industry or economic trends. When AE Supply determines that an impairment review is necessary, a comparison is made between the expected undiscounted future cash flows and the carrying amount of the asset. If the carrying amount of the asset is the larger of the two balances, an impairment loss is recognized equal to the amount by which the carrying amount of the asset exceeds the fair value of the asset. In these cases, the fair value is determined by the use of quoted market prices, appraisals, or the use of valuation techniques such as expected

discounted future cash flows. AE Supply must make assumptions regarding these estimated future cash flows and other factors to determine the fair value of the respective assets. Significant changes to these assumptions could have a material effect on AE Supply’s results of operations and financial position.

Consolidated earnings (loss) before cumulative effect of accounting change were $(583.7) million in 2002, $234.8 million in 2001, and $75.5 million in 2000.

The decrease in earnings for 2002, before cumulative effect of accounting change, was primarily due to weak wholesale energy markets nationwide, lower net revenue, reduced economic activity, and write-offs related to cancelled generation projects and other investments determined to be impaired. AE Supply recorded an unrealized loss on its commodity and derivative contracts of $215.7 million, net of income taxes, during 2002, compared to an unrealized gain of $368.9 million, net of income taxes, during 2001. The unrealized loss for 2002 reflected then current market conditions which required changes in techniques and assumptions used to determine the fair value of commodity contracts, as well as a decrease in liquidity and volatility in the energy markets in the Western United States. AE Supply also recorded a charge of $149.2 million, net of income taxes, for the cancellation of generation projects during 2002.

For 2002, AE Supply also incurred a charge of $45.5 million, net of income taxes, for workforce reduction costs related to Allegheny’s voluntary Early Retirement Option (ERO) program and other employee severance costs and for restructuring charges and related asset impairment.

The increase in earnings for 2001, before cumulative effect of accounting change, was driven by the addition of unregulated generating capacity and unrealized gains from energy trading activities resulting from the newly acquired energy trading business. The increase in the Generation and Marketing segment’s net revenues included the results of the acquired energy trading business, since March 16, 2001.

As of January 1, 2001, AE Supply had certain option contracts that were derivatives as defined by SFAS No. 133, which did not qualify for hedge accounting. In accordance with SFAS No. 133, AE Supply recorded a charge of $31.1 million against earnings, net of income taxes ($52.3 million before income taxes) for these contracts as a change in accounting principle on January 1, 2001. See Note 9 to the consolidated financial statements for additional details.

Retail: AE Supply is in the retail markets as an alternate electricity generation supplier in states where retail competition has been implemented. The decrease in retail revenues for 2002 and 2001 was primarily due to AE Supply’s shift in focus away from retail customers toward wholesale markets and energy commodity trading.

Wholesale: The decrease in AE Supply’s wholesale revenues for 2002 was primarily due to weak wholesale energy markets nationwide and increased unrealized losses of $349.7 million on commodity contracts. The increase in AE Supply’s wholesale revenues for 2001 was primarily due to unrealized gains of $598.2 million from the energy trading business that was acquired in March 2001.

During 2002, AE Supply completed a thorough evaluation of its business, operations, and strategic plans. As a result of this evaluation, AE Supply is refocusing on identifying ways to improve, grow, and build on the earnings and cash flows from its core generation businesses. Furthermore, AE Supply is implementing an asset- backed trading strategy which will focus on the regions in which it owns generating facilities and serves customers such as in the Mid-Atlantic and Midwest. AE Supply is attempting to reduce its reliance on, and exposure to, energy marketing and speculative trading. AE Supply has modified its energy marketing and trading activities to focus on reducing risk, optimizing the operations of its generating facilities, and prudently managing and protecting the value associated with the existing positions in AE Supply’s energy marketing and trading portfolio.

During 2002 and 2001, AE Supply traded electricity, natural gas, oil, coal, and other energy-related commodities. AE Supply recorded 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 operating revenues. The realized revenues from energy trading activities are recorded on a net basis in operating revenues on the consolidated statement of operations in accordance with EITF No. 02-3.

The fair value of energy trading commodity contracts, which represent the net unrealized gain and loss positions, is recorded as assets and liabilities, after applying the appropriate counterparty netting agreements in accordance with FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts-an Interpretation of APB Opinion No. 10 and FASB Statement No. 105.” At December 31, 2002, the fair value of energy trading commodity contract assets and liabilities was $1,211.9 million and $783.7 million, respectively. At December 31, 2001, the fair value of energy trading commodity contract assets and liabilities was $1,529.3 million and $779.1 million, respectively.

The following table disaggregates the net fair value of commodity contract assets and liabilities, excluding AE Supply’s generating assets and provider-of-last-resort (PLR), as of December 31, 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. AE Supply determines prices actively quoted from various industry services, broker quotes, and the New York Mercantile Exchange (NYMEX). Electricity markets are generally liquid for approximately one year and most natural gas markets are generally liquid for approximately three years. Afterward, some market prices can be observed, but market liquidity is less robust.

Approximately $526.5 million of AE Supply’s commodity contracts were classified above as prices based on models, even though a portion of these contracts are valued based on observable market prices. The most significant variables to AE Supply’s models used to value these contracts are 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 one year, and some observable market prices are available for about three years. After three 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 three years, and some observable market prices are available for about five years. Beyond five years, natural gas prices are escalated, based on trends in prior years.

For deliveries of less than one year, the fair value of AE Supply’s commodity contracts was a net liability of $34.5 million, primarily related to commodity contracts to hedge the CDWR agreement and AE Supply’s contract with Williams Energy Marketing and Trading Company (Williams) to call up to 1,000 megawatts (MW) of generating capacity in southern California.

Net unrealized losses of $349.7 million in 2002 and net unrealized gains of $598.2 million in 2001 were recorded to the consolidated statement of operations in operating revenues to reflect the change in fair value of the commodity contracts. The following table provides a roll-forward of the net fair value, or commodity contract assets less commodity contract liabilities, of AE Supply’s commodity contracts for 2002:

As shown in the table above, the net fair value of AE Supply’s commodity contracts decreased by $349.7 million as a result of net unrealized losses recorded during 2002, primarily caused by $608.1 million in unrealized losses that reflected then current market conditions which required changes in techniques and assumptions used to determine the fair value of commodity contracts. During 2002, the depressed wholesale energy markets significantly affected the merchant energy business, including AE Supply’s energy trading activities. Additional generating capacity, coupled with lower-than-expected demand for electricity due to the weak economy, have led to reduced wholesale prices in several regional markets. Also, the Enron bankruptcy, the California energy crisis, energy trading improprieties by certain companies, the planned retreat of several merchant energy companies from energy trading markets, and the decline in credit quality of merchant energy companies has negatively affected the liquidity of the wholesale energy markets.

During the third quarter of 2002, AE Supply announced a restructuring of its energy marketing and trading activities. AE Supply is significantly reducing its reliance on the wholesale energy trading business primarily by restricting activities to an asset-backed strategy using its low-cost generating assets located in the Mid-Atlantic and Midwest. As a result, AE Supply’s trading activities will focus on lowering risk, optimizing the value of its generating assets, and reducing the effect of mark-to-market earnings to the extent possible.

As a result of significant changes in market conditions, and in conjunction with AE Supply’s decision to restructure its energy trading activities, AE Supply performed a comprehensive assessment of the valuation techniques and assumptions used to value its existing portfolio of energy commodity contracts. To reflect current market conditions, AE Supply revised the valuation techniques and assumptions for certain contracts with option features. As a result, AE Supply reduced the value of its portfolio of energy commodity contracts by $356.3 million, before income taxes, in the third quarter of 2002.

During the fourth quarter of 2002, the fair value of AE Supply’s portfolio of commodity contracts was reduced by an additional $216.4 million, before income taxes. This reduction in fair value resulted from a decrease in the liquidity and volatility of the energy markets in the WSCC. This decrease in market liquidity and volatility primarily affected the fair values related to Allegheny’s contractual right to call up to 1,000 MW of generation in southern California from Williams and the agreement with LV Cogen to call upon up to 222 MW of generating capacity.

On February 21, 2002, the California PUC approved a rate agreement with the CDWR in order for the CDWR to issue Power Supply Revenue 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 AE Supply. In September 2002, the CDWR’s Power Supply Revenue Bonds received the following long-term ratings: Moody’s, A3; Standard and Poor’s, BBB+; and Fitch, A-. To date, all payments to AE Supply by the CDWR for purchased power have been made on time and in full.

The California PUC rate agreement and the long-term credit ratings are positive developments relative to the prior assumptions used in assessing the long-term creditworthiness of the CDWR and the estimation of the fair value of AE Supply’s contracts with the CDWR. As a result, the valuation adjustments used in estimating the fair value of these contracts have been reduced. AE Supply recorded a $35.8-million increase in the estimated fair value of the CDWR contract in the first quarter of 2002.

During 2001, AE Supply did not have any changes in the fair value of commodity contracts attributed to changes in valuation techniques. The net fair value of AE Supply’s commodity contracts increased by $598.2 million as a result of unrealized gains recorded during 2001. Of the unrealized gains, $578.9 million related to AE Supply’s contracts in the WSCC. This increase in the fair value of the WSCC portfolio was driven by the fixed-price contract to sell power for approximately 10 years to the CDWR, which increased in fair value as prices dropped in the WSCC during 2001. The increase in the fair value of the CDWR contract was partly offset by decreases in the fair value of the contract with Williams to call up to 1,000 MW of generating capacity in southern California and other contracts primarily used to hedge the WSCC portfolio, including the agreement with LV Cogen.

During 2002 and 2001, AE Supply’s energy trading and excess generation activities resulted in $239.7 million and $223.2 of net realized losses, respectively. These losses were mainly related to AE Supply’s contract with the CDWR and the related hedges and, in the fourth quarter of 2002, trade terminations resulting from AE Supply’s failure to post collateral in favor of several counterparties following the downgrading of Allegheny’s credit rating below investment grade by Moody’s. These losses were partially offset by realized gains from the sale of generation in excess of the power provided to West Penn, Potomac Edison, and Monongahela to meet their PLR obligations. AE Supply hedged the on-peak positions of the CDWR contract at prices above the fixed contract price of $61 per MWh that AE Supply received from the CDWR.

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 AE Supply’s operating results. Similarly, volatility in interest rates will affect AE Supply’s operating results. The effects may be either positive or negative, depending on whether West Penn, Potomac Edison, and Monongahela are net buyers or sellers of electricity and natural gas.

AE Supply’s revenues for 2002 and 2001 also reflect transactions by AE Supply in the unregulated marketplace to sell electricity to wholesale customers. On May 3, 2001, AE Supply completed the acquisition of three natural gas-fired generating facilities with a total generating capacity of 1,710 MW in the Midwest. During 2001 and 2002, AE Supply also completed the construction of or acquired and placed into operation 214 MW of additional generating capacity. As a result, AE Supply had more generation available for sale into the deregulated marketplace in 2001 and 2002, including sales to West Penn, Potomac Edison, and Monongahela in excess of their PLR obligations.

The table below separates operating revenues and cost of revenues for AE Supply into two components: PLR and excess generation and trading. The PLR component represents AE Supply’s obligation under long-term power sales agreements to provide West Penn, Potomac Edison, and Monongahela with the amount of electricity, up to their PLR retail load, that they may demand in their Pennsylvania, Maryland, Virginia, and Ohio service territories. The excess generation and trading component represents AE Supply’s energy marketing and trading activities and any generation in excess of the PLR obligations. All realized and unrealized gains and losses from energy trading activities were recorded net in operating revenues in accordance with EITF Issue No. 02-3.

The increase in the PLR net revenues of $56.9 million for 2002 was due to an increase in MWh sales related primarily to a full year of sales to Monongahela’s Ohio customers after the transfer of generating assets in July 2001 and an increase in prices. The decrease in the excess generation and trading net revenues of $986.6 million for 2002 was primarily due to weak wholesale energy markets and unrealized losses in 2002 versus unrealized gains in 2001 from energy trading activities.

Affiliated revenues are revenues that AE Supply obtained from Allegheny’s regulated utility subsidiaries under power sales agreements and a generating asset lease. In Maryland, Ohio, Pennsylvania, and Virginia, AE Supply is obligated under power sales agreements to supply the regulated utility subsidiaries of Allegheny—West Penn, Potomac Edison, and Monongahela—with power. Under these agreements, AE Supply is obligated to provide these companies with the amount of electricity, up to their PLR retail load, that they may demand.

The transfer of Potomac Edison’s generating assets to AE Supply on August 1, 2000, included Potomac Edison’s generating assets located in West Virginia. AE Supply has leased back a portion of these generating assets to Potomac Edison to serve its West Virginia jurisdictional retail customers. Affiliated revenue in 2002, 2001, and 2000 includes $90.8 million, $75.2 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.

Fuel Consumed for Electric Generation: Fuel consumed for electric generation represents the cost of coal, natural gas, and oil burned for electric generation. Total fuel expenses increased $38.1 million for 2002 primarily due to a 5.3 percent increase in average fuel prices and a 2.9 percent increase in Kilowatt-hours (KWhs) generated. The increase in KWhs generated for 2002 was primarily due to Monongahela’s transfer of its Ohio and FERC jurisdictional generating assets to AE Supply on June 1, 2001.

Total fuel consumed for electric generation increased $119.0 million for 2001, primarily due to the transfer of 2,100 MW of Potomac Edison’s generating assets to AE Supply in August 2000. The increase in fuel expenses for 2001 also reflects the transfer to AE Supply in June 2001 of 352 MW of Monongahela Power’s Ohio and FERC jurisdictional generating assets and the purchase on May 3, 2001, of the Midwest Assets.

Purchased Energy and Transmission: Purchased energy and transmission represents power purchases from and exchanges with other companies. The decrease in AE Supply’s purchased energy and transmission of $83.0 million for 2002 was primarily due to decreases in purchases made in support of physical energy supply commitments. The decrease in the AE Supply’s purchased energy and transmission also reflects the decrease in wholesale market prices and additional generation capacity available for sale in the PJM market.

Purchased energy and transmission increased $72.6 million for 2001 primarily related to the wholesale marketing and energy trading activities and power purchased to fulfill AE Supply’s power sales agreement obligations to West Penn, Potomac Edison, and Monongahela.

Workforce Reduction Expenses: In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction. The workforce reduction expenses were allocated among Allegheny’s subsidiaries. Allegheny achieved workforce reductions of approximately 10 percent primarily through a voluntary ERO program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88 and SFAS No. 106. For 2002, approximately 600 of Allegheny’s eligible employees accepted the ERO program. AE Supply recorded a charge of $21.4 million, before income taxes ($13.1 million, net of income taxes) for its allocable share of the effect of the ERO program. Allegheny offered a Staffing Reduction Separation Program (SRSP) for employees whose positions were being eliminated as part of the workforce reductions and severance for certain energy trading employees. The SRSP provides for severance and other employee-related costs. For the year ended December 31, 2002, AE Supply recorded a charge of $24.7 million, before income taxes ($15.2 million, net of income taxes), related to approximately 80 Allegheny employees whose positions have been or are being eliminated.

Operation Expense: Operation expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services, and other expenses. The increase in operation expenses for AE Supply of $277.6 million for 2002 was primarily due to AE Supply recording charges of $244.0 million, before income taxes, for cancelled generation projects. The increase in operation expenses for AE Supply also includes the reorganization of AE Supply’s trading division, which resulted in a charge of approximately $20.2 million, before income taxes, related to costs associated with its relocation from New York to Monroeville, Pennsylvania, plus a $7.9 million loss for the abandoned leasehold improvements at the New York office. See Note 8 to the consolidated financial statements for additional information regarding restructuring charges.

The increase in AE Supply’s operation expenses of $178.0 million for 2001 was due to increased salary, general, and administrative expenses resulting from the acquired energy trading business, expenses related to the issuance of short-term debt, and rent expense for AE Supply’s offices in Monroeville, Pennsylvania. Power station operating costs also increased due to the operation of 2,100 MW of generating assets transferred to AE Supply by Potomac Edison in August 2000, the operation of 1,710 MW of the Midwest Assets, and, to a lesser

extent, the operation of 352 MW of Monongahela’s Ohio and FERC jurisdictional generating assets transferred to AE Supply in June 2001.

Depreciation and Amortization: Total depreciation and amortization expenses increased $3.0 million and $60.7 million for 2002 and 2001, respectively, primarily due to depreciation expenses related to the generating facilities in the Midwest that were acquired on May 3, 2001, partially offset by the elimination of goodwill amortization in 2002. Effective January 1, 2002, AE Supply adopted SFAS No. 142 and, accordingly, ceased the amortization of all goodwill. AE Supply recorded goodwill amortization of $21.1 million for 2001, related to its acquisition of the energy trading business on March 16, 2001.

Taxes Other Than Income Taxes: Taxes other than income taxes primarily include gross receipts taxes, payroll taxes, property taxes, and capital stock/franchise taxes. Total taxes other than income taxes decreased $.7 million for 2002, primarily due to lower payroll and capital stock/franchise taxes which were partially offset by higher gross receipts and property taxes.

Total taxes other than income taxes increased $7.9 million for 2001, primarily due to the transfer of 2,100 MW of Potomac Edison’s generating assets in August 2000 and, to a lesser extent, the transfer to AE Supply of 352 MW of Monongahela’s Ohio and FERC jurisdictional generating assets in June 2001.

Other income and expenses represent nonoperating revenues and expenses before income taxes. Other income and expenses decreased $4.9 million for 2002 primarily due to lower interest income and a $3.5-million gain on the disposal of property in 2001. Other income and expenses increased $1.9 million for 2001. Other income and expenses for 2001 included a gain on the disposal of property of $3.5 million and interest income on collateral of $2.0 million. See Note 18 to the consolidated financial statements for additional details.

The increase in total interest charges of $46.2 million and $70.0 million for 2002 and 2001, respectively, resulted from increased average long-term and short-term debt outstanding. The increase in average long-term debt outstanding was primarily the result of AE Supply 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, AE Supply issued $650.0 million of 8.25-percent notes due April 15, 2012. AE Supply 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 1,710 MW of generating assets in the Midwest in May 2001, and for general corporate purposes.

For additional information regarding AE Supply’s short-term and long-term debt, see the consolidated statement of capitalization and Notes 11 and 14 to the consolidated financial statements. Also, see Financial Condition, Requirements and Resources-Liquidity and Capital Requirements for additional information concerning AE Supply’s debt restructuring.

Income tax on continuing operations changed to a benefit of $362.5 million in 2002 from an expense of $125.0 million in 2001 and $36.1 million in 2000. The effective tax (benefit) expense rates were (38.7) percent, 34.7 percent, and 32.3 percent for 2002, 2001, and 2000, respectively.

In 2002, the effective tax rate switched to a benefit due to the pre-tax loss. The change in the effective tax rate between 2001 and 2000, a net 2.4 percent increase, was caused by: equity in earnings of subsidiaries (2.2

percent increase); consolidated savings (2.1 percent increase); amortization of deferred investment credit (1.5 percent increase); state income tax (1.3 percent decrease) and other various items (2.1 percent net decrease).

Note 13 to the consolidated financial statements provides a further analysis of income taxes.

Minority interest was $4.3 million, $5.0 million, and $2.5 million for 2002, 2001, and 2000, respectively. As of December 31, 2002 and 2001, the minority interest primarily represented Monongahela’s 22.97-percent minority interest in AGC. In August 2000, Potomac Edison transferred to AE Supply all of its generating assets, except certain hydroelectric facilities located in Virginia, at net book value. The asset transfer included Potomac Edison’s 28-percent ownership of AGC. As a result of the transfer, AE Supply’s ownership increased from 45 percent as of July 31, 2000, to 73 percent as of August 1, 2000. Effective August 1, 2000, AE Supply’s consolidated financial statements include the operations of AGC and the related minority interest. In connection with the transfer of 352 MW of Monongahela’s generating assets, AE Supply received an additional 4.03 percent ownership of AGC, which increased AE Supply’s ownership percentage to its current level of 77.03 percent.

The components of other comprehensive income include an unrealized loss, net of reclassification to earnings and income taxes, on cash flow hedges of $1.0 million and $1.5 million for 2002 and 2001, respectively. These amounts are presented net of income taxes, reclassifications to earnings, and minority interest. During 2002 and 2001, AE Supply reclassified $.1 million and $3.1 million, respectively, net of tax, from other comprehensive income to earnings related to losses associated with cash flow hedges. See Notes 9 and 10 to the consolidated financial statements for additional information regarding other comprehensive income.

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

During 2001, AE Supply issued $776.6 million of long-term debt and $520.1 million of short-term debt, and issued notes payable to Allegheny and affiliates of $334.6 million, primarily to finance AE Supply’s acquisitions of Merrill Lynch’s energy trading business and the Midwest Assets, and for other corporate purposes. During 2002, AE Supply issued $943.6 million of long-term debt to repay short-term and long-term indebtedness and for other corporate purposes. AE Supply could incur further financings to support capital expenditures and to

maintain working capital. In addition, AE Supply’s wholesale marketing, energy trading, fuel procurement, and risk management activities require direct and indirect credit support. As of December 31, 2002, AE Supply had total indebtedness of $2,750.8 million.

As discussed in detail in ITEM 1. BUSINESS—Recent Events, various recent events left Allegheny and AE Supply in a weakened liquidity position in 2002, and this situation has continued into 2003. AE Supply has taken a number of recent actions to improve its financial condition. These steps include substantial senior management changes, refinancing principal credit facilities, exiting from Western United States energy markets, refocusing trading activities, asset sales, restructuring and cost-reducing initiatives, and improving internal controls and reporting.

Refinancing Principal Credit Facilities: On October 8, 2002, Allegheny announced that AE, AE Supply, and AGC were in technical default under their principal credit agreements after AE Supply declined to post additional collateral in favor of several trading counterparties. These collateral calls followed the downgrading of Allegheny’s credit rating below investment grade by Moody’s. During the period November 2002 through February 2003, AE, AE Supply and AGC obtained waivers of, and amended, certain covenants to these principal credit agreements. The total debt classified as current, in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived by the Creditor,” in the accompanying consolidated balance sheet related to such defaults was approximately $1,437.0 million as of December 31, 2002. See the discussion below concerning other defaults on additional long-term debt that also resulted in the classification of that debt as current.

Allegheny and its subsidiaries, including AE Supply, have prepared their financial statements assuming that they will continue as going concerns. However, AE Supply’s noncompliance with certain reporting obligations under its debt covenants and the resultant classification of certain debt as current has caused its independent auditors, PricewaterhouseCoopers LLP, to issue a modified opinion that indicates there is substantial doubt about AE Supply’s ability to continue as a going concern (a “Going Concern” opinion).

In February and March 2003, AE, AE Supply, Monongahela, and West Penn entered into agreements (Borrowing Facilities) with various credit providers to refinance and restructure the bulk of AE and AE Supply’s short-term debt. Following is a summary of the terms of the Borrowing Facilities at AE Supply:

In addition, $380.0 million of indebtedness related to the discontinued St. Joseph, Indiana generating project, in the form of A-Notes, was restructured and assumed by AE Supply. Of this amount, $343.7 million is secured by substantially all of the assets of AE Supply, other than its new generating facility in Springdale, Pennsylvania. The secured portion of this debt bears an interest rate of 10.25 percent, and the unsecured portion bears interest at 13.0 percent. This debt matures in November 2007.

The $420.0 million borrowed by AE Supply under the $470.0 million facility represented new liquidity. The Borrowing Facilities at AE Supply also refinanced $1,637.8 million of existing debt and letters of credit, including $894.9 million outstanding under various credit agreements, $270.1 million outstanding for the generating facility in Springdale, Pennsylvania, which went into commercial operation in July 2003. The majority of AE Supply’s restructured debt is secured by substantially all of its assets.

Until August 1, 2003, after certain conditions associated with securing the collateral under the Borrowing Facilities were met on July 19, 2003, the LIBOR component charged AE Supply under the Borrowing Facilities with respect to secured borrowings had a two-percent floor. Also, since AE Supply was unable to secure all of the Borrowing Facilities and the restructured A-Note debt before the end of July 31, 2003, the interest rates charged on the amounts not so secured increased to a spread of 10.5 percent over the applicable LIBOR-based rate or the designated money center bank’s base rate for the Refinancing Credit Facility and the Springdale Credit Facility and 13.0 percent for the unsecured portion of the $380.0 million A-Note debt retroactively to February 25, 2003, the closing date of the Borrowing Facilities. The total amounts unsecured under the Refinancing Credit Facility and the Springdale Credit Facility and the A-Note debt are approximately $94.3 million and $175.8 million and $36.3 million, respectively.

AE Supply borrowed $2,057.8 million under the Borrowing Facilities and the restructured A-Note debt. Of the total, either AE Supply’s new generating facility in Springdale, Pennsylvania or substantially all of AE Supply’s assets secures $1,927.2 million. A 30-percent limitation of available secured debt in AE Supply’s indenture will also make it difficult, if not impossible, for AE Supply to borrow additional funds until some of the secured debt under the Borrowing Facilities is repaid.

As required by the SEC under PUHCA, AE Supply was required to maintain a minimum equity to total capitalization ratio (Equity Ratio) of 20 percent as a condition of an SEC order. As of December 31, 2002, AE Supply had met this Equity Ratio requirement. Future borrowings, or the ability to obtain financing through the issuance of debt obligations, may be restricted by the SEC at AE Supply should it fail to meet the Equity Ratio requirements.

The interest rate margins payable by AE Supply under certain of the Borrowing Facilities are tied to AE Supply’s credit ratings. Should AE Supply’s credit ratings for the Refinancing Facility and the Springdale Credit Facility improve from its current ratings of B2 by Moody’s, B by Standard and Poor’s, and B+ by Fitch to certain specified higher ratings, the rate of interest AE Supply would be required to pay under the Refinancing Credit Facility and the Springdale Credit Facility could decrease by .5 percent to 1.0 percent for the secured portion of those credit facilities. AE Supply’s credit ratings would need to improve to BB/Ba2 to achieve a .5 percent decrease in the interest rates and BB+/Ba1 or higher to achieve a 1.0 percent decrease in the interest rates.

AE Supply also is required to meet certain financial tests, as defined in the Borrowing Facilities agreements, including:

The Borrowing Facilities also have provisions requiring prepayments out of the proceeds of asset sales and debt and equity issuances, as follows:

Any prepayments under the provisions of the Borrowing Facilities would reduce the amounts of scheduled principal payments in 2003 and 2004.

AE Supply had several debt agreements that required it to file copies of its annual or quarterly reports as filed with the SEC pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) with or for the debtholders. AE Supply is also required to deliver to or for the debtholders a certificate indicating that Allegheny has complied with all conditions and covenants under the agreements. On April 30, 2003, Allegheny provided certificates to the trustees under its indenture indicating that it was not in compliance with the covenants for filing its annual and quarterly reports that are contained in its First Mortgage Bonds and Debentures. The covenant breach of the First Mortgage Bonds and Debentures is deemed a default of these debt agreements, as well as a default under agreements governing certain other of AE Supply’s indebtedness, including pollution control bonds and other indebtedness that contain cross-acceleration provisions with the First Mortgage Bonds and Debentures, for AE Supply’s financial reporting purposes in accordance with EITF Issue No. 86-30. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was approximately $310.8 million as of December 31, 2002 for AE Supply. To date, the debtholders have not provided AE Supply with any notices of default under the agreements. Such notices, if received, would allow AE Supply either 30 or 60 days to cure its noncompliance before the debtholders could accelerate the due dates of the debt obligations.

Exiting from Western United States Energy Markets: AE Supply worked through 2003 to accomplish its effective exit from the Western United States power markets. Its positions based in the Western United States had been a substantial source of earnings and cash flow volatility and risk, and trading in these markets does not fit with Allegheny’s new business model.

into to terminate tolling agreements with Williams Energy Marketing and Trading Company (Williams) and Las Vegas Cogeneration II (LV Cogen), a unit of Black Hills Corporation, as described below. Allegheny will apply an additional $28 million of the proceeds to make required payments in March and September 2004 under the agreement with Williams. Approximately $26 million will be held in a pledged account for the benefit of AE Supply’s creditors. This arrangement is intended to enhance AE Supply’s ability to refinance certain secured borrowings. Approximately $71 million of the sale proceeds was placed in escrow for the benefit of J. Aron & Company, pending Allegheny’s fulfillment of certain post-closing requirements. When the escrowed funds are released, approximately $50 million will be added to the pledged account and AE Supply will receive the balance. The remaining $15 million of sale proceeds will be used to partially offset certain of the hedges related to the CDWR contract and to pay fees and expenses associated with the transaction.

Agreement to Terminate Williams Toll. In July 2003, AE Supply entered into a conditional agreement with Williams to terminate its 1,000 MW tolling agreement with Williams. Under the agreement, AE Supply made an initial payment to Williams of approximately $2.4 million to satisfy certain amounts under a related hedge agreement. Allegheny made a $100 million payments to Williams after the close of the sale of the CDWR contract. Allegheny will make two payments of $14 million to Williams in March and September of 2004. The tolling agreement will terminate when the final $14 million payment is made.

Termination of LV Cogen Toll. In mid-September 2003, AE Supply terminated its 222 MW tolling agreement with LV Cogen. AE Supply made a $114 million termination payment to LV Cogen after the closing of the sale of the CDWR contract.

As of December 31, 2002, the fair value of the CDWR contract and related hedges that were sold to J. Aron & Company plus the Williams and LV Cogen tolling agreements was $554.5 million. From January 1, 2003, through the date that these contracts were either sold or agreement were reached to terminate the contracts, the aggregate fair value of the contracts decreased by $462.7 million to $91.8 million. As a result of the sale of the CDWR contract and related hedges and the terminations of the Williams and LV Cogen tolling agreements, AE Supply incurred a net loss of $50.4 million, before income taxes, in the third quarter of 2003. This loss was determined excluding the approximately $70.8 million of sale proceeds that were placed in escrow pending AE Supply’s fulfillment of certain post-closing requirements. AE Supply expects to meet these requirements in the fourth quarter of 2003, at which time the net loss would be revised from $50.4 million, before income taxes, to a net gain of $20.4 million, before income taxes.

After completing these major transactions, AE Supply’s remaining trading exposures to the Western United States market will consist of several shorter-term trades that hedged the CDWR contract and several long-term hedges of the LV Cogen tolling agreement. AE Supply continues to seek to unwind these remaining positions.

Refocusing Trading Activities: Adoption of Asset-Based Trading Strategy. AE Supply is reorienting its trading operations from high-volume financial trading in national markets to asset optimization and hedging within its region. AE Supply is implementing this rebalancing over time as its liquidity allows. Effectively exiting the Western United States power markets, together with unwinding substantial non-core trading positions, has enabled AE Supply to reduce long-term trading-related cash out flows and collateral obligations. In the future, AE Supply will seek to concentrate its efforts in PJM, the Midwest, and Mid-Atlantic markets where it has a physical presence and greater market knowledge. Ultimately, AE Supply intends to conduct asset optimization and hedging activities with the primary objective of locking in cash flows associated with AE Supply’s portfolio of core physical generating and load positions.

are intended to reflect the newly revised focus of the trading function. Management believes that both trading and marketing and generation operations can be enhanced by locating trading personnel closer to personnel managing AE Supply’s generating assets. Personnel involved in the separate functions can be cross-trained and will be better positioned to enhance the relationship between the two functions.

Asset Sales: In 2002, AE Supply announced that it was considering asset sales as part of an overall strategy to address its liquidity concerns. AE Supply has achieved the sale of its most significant assets with a nexus to the Western United States. AE Supply has also closed the sale of its interest in the Conemaugh Generating Station, as described below. AE Supply continues to consider the sale of additional assets, especially non-core assets.

Conemaugh Generating Station. On June 27, 2003, AE Supply completed the sale of its 83-MW share of the coal-fired Conemaugh Generating Station, located near Johnstown, Pennsylvania, to a subsidiary of UGI Corporation, (UGI), for approximately $46.25 million, which does not include a contingent amount of $5 million. This contingent amount could be received in full, in part, or not at all, depending upon AE Supply’s performance of certain post-closing obligations.

Restructuring and Cost-Reducing Initiatives: AE Supply has taken several actions to align its operations with its strategy and reduce its cost structure.

Restructuring of Operations. In July 2002, Allegheny announced a restructuring plan intended to strengthen its financial performance by, among other things, reducing its workforce. Allegheny has achieved workforce reductions of more than 10 percent through a voluntary Early Retirement Option (ERO) program and selected staff reductions. In 2002, approximately 600 eligible employees accepted the ERO program. AE Supply recorded a charge of $21.4 million, before income taxes for its allocable share of the effect of the ERO program. AE Supply has essentially completed these planned workforce reductions. AE Supply will continue to take actions intended to reduce costs and improve productivity in all of its operations.

Improving Internal Controls and Reporting: Comprehensive Financial Review. Commencing in the third quarter of 2002, Allegheny, including AE Supply, undertook a comprehensive and extended review of its financial information and internal controls and procedures. This review included continuous efforts by Allegheny’s top management and directors and extensive involvement of independent auditors and other outside service firms. Allegheny continues to address its controls environment and reporting procedures, as well as its SEC filing and other outstanding reporting obligations. See ITEM 14. CONTROLS AND PROCEDURES, for a detailed discussion.

Other Matters Concerning Liquidity and Capital Requirements: AE Supply’s wholesale marketing, energy trading, fuel procurement, and risk management activities require direct and indirect credit support. The amount of credit support required is affected by market price changes for electricity, natural gas, and other energy-related commodities and AE Supply’s credit rating. Such credit support might be in the form of letters of credit, cash deposits, or liquid securities. As previously discussed, Allegheny announced on October 8, 2002, that AE, AE Supply, and AGC were in technical default under their principal credit agreements after AE Supply declined to post additional collateral in favor of several trading counterparties. This default resulted in 24 trading counterparties terminating trades with AE Supply by December 31, 2002. Of these trading counterparties, AE Supply has settled with nine counterparties for a net cash inflow of $6.8 million. As of December 31, 2002, AE Supply had recorded an accounts receivable of $9.0 million for payments due from terminated trading counterparties and had recorded an accounts payable for $40.6 million due to terminated trading counterparties.

In early 2003, AE Supply proposed payment schedules with the remaining counterparties to settle the accounts payable by the end of 2003.

AE Supply has established credit facilities, or lines of credit, that provide for direct borrowings and the issuance of letters of credit to support general corporate purposes and energy trading activities. At December 31, 2002, $894.9 million of the $965.0 million lines of credit with banks were drawn. All of the $70.1 million remaining lines of credit were unavailable.

AE Supply’s credit facilities provided for letter of credit capacity of $586.0 million. AE Supply regularly posts cash deposits or letters of credit with counterparties to collateralize a portion of its energy trading obligations. At December 31, 2002, there was $99.9 million outstanding under AE Supply’s letter of credit facilities.

AE Supply has various obligations and commitments to make future cash payments under contracts such as debt instruments, lease arrangements, fuel agreements, and other contracts. The table below provides a summary of the payments due by period for these obligations and commitments as of December 31, 2002. This table does not include capacity contract commitments that were accounted for under fair value accounting, as discussed under “Operating Revenues,” or contingencies.

Amounts related to debentures, notes, and bonds in this table represent contractual cash payments required without taking into account their classification as current, as a result of a default in the underlying debt agreements, on the consolidated balance sheet. (See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, and Note 3 to the consolidated financial statements, “Debt Covenants and Liquidity Strategy,” for additional information). As AE Supply has refinanced its Borrowing Facilities as of February 25, 2003, the contractually required payments under its Borrowing Facilities, as of that date, are as follows:

AE Supply’s capital expenditures, including construction expenditures, for 2003 and 2004 are estimated at $186.4 million and $109.4 million, respectively. These estimated expenditures include $51.2 million and $71.1 million, respectively, for environmental control technology. See Note 23 to the consolidated financial statements for additional information.

In 2003, AE Supply’s cash flows are expected to be adequate to meet all of its payment obligations under the debt agreements, including the outstanding notes, and to fund other working capital needs. AE Supply’s ability to meet its payment obligations, beginning in 2004, under its indebtedness, including outstanding notes, and to fund capital expenditures will depend on its future performance. AE Supply’s future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control. AE Supply expects that it will need to sell certain assets or arrange for alternative financing in order to repay the principal amounts under the Borrowing Facilities scheduled for the third and fourth quarters of 2004. See Note 3 to the consolidated financial statements for additional information.

Internal generation of cash, consisting of cash flows from operations reduced by dividends, was a use of cash in 2002 and 2001 of $132.0 million and $106.7 million, respectively.

Cash flows used in operations in 2002 decreased $65.0 million versus 2001. AE Supply’s cash flows from operations include the results of its energy trading activities. For 2002 and 2001, the energy trading activities resulted in approximately $239.7 million and $223.2 million of net cash outflows, respectively. See “Operating Revenues” for additional details regarding the cash outflows for the energy trading activities. AE Supply’s cash paid for interest for 2002 was $143.2 million versus $95.0 million in 2001.

Cash flows used in investing for 2002 decreased $1,534.0 million from 2001. In 2001, AE Supply paid approximately $1,626.8 million for the acquisition of an energy trading business, an interest in the Conemaugh Generating Station, and the purchase of three generating facilities in the Midwest. Construction expenditures during 2002 and 2001 were $169.3 million and $214.0 million, respectively.

Cash flows provided by financing for 2002 decreased $1,581.6 million from 2001. This decrease was primarily due to a $449.1-million increase in the retirement of long-term debt, a $409.1-million decrease in net short-term debt financing, and a $529.5-million increase in the retirement of notes payable to Allegheny and affiliates.

Cash flows used in operations in 2001 increased $292.8 million. AE Supply’s cash flows used in operations include the results of its energy trading activities, which resulted in approximately $223.2 million of net cash outflows. See “Operating Revenues” for additional details regarding the cash outflows for the energy trading activities.

Cash flows used in investing increased $1,592.1 million for 2001. In 2001, AE Supply paid approximately $1,626.8 million for the acquisition of an energy trading business, an interest in the Conemaugh generating station, and the purchase of the three generating facilities in the Midwest. Construction expenditures were $214.0 million for 2001, compared to $177.1 million for 2000.

Cash flows provided by financing increased by $1,906.7 million for 2001 primarily due to a $776.6-million increase in net proceeds from the issuance of long-term debt; a $245.7-million increase in equity contributions from Allegheny; a $352.0-million increase in notes payable to Allegheny and affiliates; and a $354.4-million increase in net short-term financings.

Members’ Equity: On March 16, 2001, AE Supply acquired Merrill Lynch’s energy trading business. AE Supply acquired this business for $489.2 million in cash plus the issuance of a nearly two-percent equity membership interest in AE Supply, effective June 29, 2001. Members’ equity includes capital contributions related to West Penn; Potomac Edison; AYP Energy, Inc., a subsidiary of Allegheny Ventures; and Monongahela generating asset transfers as described in Note 1 to the consolidated financial statements. Members’ equity also includes capital contributions from Allegheny of $2.0 million and $272.5 million in 2002 and 2001, respectively.

Debentures, Notes and Bonds: During 2002, AE Supply redeemed $80.0 million of floating rate medium-term debt. AE Supply also redeemed $3.5 million of pollution control bonds per their original terms.

See “Operating Lease Transactions” below and Note 23 to the consolidated financial statements for additional information regarding debt recorded on AE Supply’s consolidated balance sheet at December 31, 2002, from an operating lease transaction for a generating facility.

See Note 11 to the consolidated financial statements for additional details regarding debt issued and redeemed during 2002 and 2001 and additional capital requirements for debt maturities.

The amount of debt due, contractually, within one year at December 31, 2002, represents $2.8 million of AE Supply’s installment purchase obligations, $61.5 million of AE Supply’s secured notes, and $50.0 million of AGC’s debentures.

Short-term Debt: Short-term debt, including notes payable to affiliates, decreased $276.8 million during 2002 to $797.0 million as of December 31, 2002, and consists only of lines of credit. At December 31, 2002, $894.9 million of the $965.0 million lines of credit with banks were drawn. All of the $70.1 million remaining lines of credit were unavailable.

See Note 14 to the consolidated financial statements for additional details regarding short-term debt activity during 2002 and 2001.

Effective January 1, 2001, AE Supply adopted SFAS No. 133, which established accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS No. 133 required that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The standards require that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in earnings or other comprehensive income and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

On January 1, 2001, AE Supply recorded an asset of $1.5 million on its consolidated balance sheet based on the fair value of its two cash flow hedge contracts. An offsetting amount was recorded in other comprehensive income as a change in accounting principle as provided by SFAS No. 133. AE Supply’s risk management objectives regarding these cash flow hedge contracts were as follows: 1) to provide electricity in situations where the customers’ demand for electricity exceeded AE Supply’s electric generating capacity and 2) to protect AE Supply from price volatility for electricity.

The amounts accumulated in other comprehensive income related to these contracts were reclassified to earnings during July and August of 2001, when the hedged transactions were executed. As a result, a loss of $5.0 million, before income taxes ($3.1 million, net of income taxes), was reclassified to purchased energy and transmission expense from other comprehensive income during the third quarter of 2001.

On March 19, 2002, AE Supply 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. In April 2002, these contracts were settled for a loss of $1.7 million, before income taxes ($1.0 million, net of income taxes). The unrealized loss was recorded in other comprehensive income. In April 2002, AE Supply began reclassifying to earnings the amounts in accumulated other comprehensive income for these treasury lock agreements over the life of the 10-year debt. For 2002, $.1 million, before income taxes ($.1 million, net of income taxes) was reclassified from accumulated other comprehensive income to earnings.

As of June 30, 2002, AE Supply recorded a liability and an unrealized loss for derivative instruments of $5.2 million in other current liabilities for seven wholesale electricity contracts. For the third quarter of 2002, AE

Supply recorded an unrealized gain of $3.2 million for these contracts. In September 2002, AE Supply made operational changes regarding the delivery of electricity under these contracts. As a result, these contracts now qualify for the normal purchases and normal sales exception under SFAS No. 133.

In June 2002, the EITF reached a consensus on Issue No. 02-3, 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 was applicable to financial statements for periods ending after July 15, 2002. During 2002, Allegheny modified its reporting as a result of the EITF consensus to reflect the revenues from energy trading activities net of the cost of purchased energy and transmission related to contracts that require physical delivery. In addition, amounts for 2001 and 2000 were adjusted for comparability to reflect the adoption of the EITF consensus. As a result, AE Supply’s 2001 and 2000 operating revenues and cost of revenues are lower than previously reported, with no effect on consolidated net revenues or net income.

The implementation of EITF Issue No. 02-3 will result in AE Supply recording a cumulative effect of an accounting change of approximately $11.9 million, net of income taxes ($19.7 million, before income taxes), in the first quarter of 2003. This charge will represent the fair value of those contracts previously accounted for under EITF Issue No. 98-10 that no longer qualify for mark-to-market accounting.

Effective January 1, 2002, AE Supply adopted SFAS No. 141, “Business Combinations,” and SFAS No. 142. The application of SFAS No. 142 resulted in AE Supply eliminating the amortization of goodwill. As required by SFAS No. 142, AE Supply must continue to evaluate the remaining goodwill related to the acquisition of the energy trading business for potential impairment at least annually. See Note 7 to the consolidated financial statements for details regarding AE Supply’s implementation of SFAS Nos. 141 and 142.

Effective January 1, 2002, AE Supply adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which establishes a singular accounting model for the disposal of long-lived assets and carries forward the impairment provisions of SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.”

Effective January 1, 2003, AE Supply adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. See Note 22 to the consolidated financial statements for additional information.

also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issued or modified after December 31, 2002. AE Supply does not anticipate FIN 45 will have a material effect on its consolidated results of operations and financial position. See Note 23 to the consolidated financial statements for additional information regarding guarantees.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities,” which addresses consolidation by business enterprises of variable interest entities, commonly referred to as “special purpose entities.” FIN 46 requires consolidation where there is a controlling financial interest in a variable interest entity or where the variable interest entity does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties. AE Supply will apply the provisions of FIN 46 prospectively for all variable interest entities created after January 31, 2003. For variable interest entities created prior to January 31, 2003, AE Supply will be required to consolidate all variable interest entities in which it is the primary beneficiary, as of the third quarter of 2003. AE Supply does not believe that FIN 46 will have a material effect on its consolidated results of operations and financial position.

Various other new accounting pronouncements not mentioned above that were effective in 2002 do not have a material effect on AE Supply’s consolidated results of operations, cash flows, and financial position. Also, AE Supply expects that various other new accounting pronouncements not mentioned above effective in 2003, will not have a significant impact on AE Supply’s consolidated financial statements.

ITEM 7. Management’s Discussion And Analysis Of Financial Condition And Results Of Operations

Allegheny Energy, Inc. (AE) and its consolidated subsidiaries (collectively, Allegheny), including its subsidiary Monongahela Power Company (Monongahela), have experienced significant changes in their businesses over the last several years, as described in Item 1. BUSINESS—Recent Events. During 2002, Allegheny has experienced a strain on its liquidity position, and, at December 31, 2002, a significant portion of its debt, including the debt of Monongahela, has been reclassified as current, as discussed in Financial Condition, Requirements and Resources.

In addition to Allegheny’s strained financial condition, Allegheny, including Monongahela, identified various errors relating to its financial statements for years prior to 2002 as a result of a comprehensive financial review as discussed in Note 2 to Monongahela’s financial statements. Corrections to these errors are reflected in the financial statements for the year ended December 31, 2002, and increased the net loss for 2002 by approximately $6.3 million for Monongahela. Allegheny’s management concluded that these errors were not material, either individually or in the aggregate, to the 2002 or any prior year’s financial statements.

Monongahela is a wholly-owned subsidiary of AE and along with its wholly-owned subsidiary Mountaineer Gas Company (Mountaineer) and its regulated affiliates, The Potomac Edison Company (Potomac Edison) and West Penn Power Company (West Penn), collectively doing business as Allegheny Power, operate electric and natural gas Transmission and Distribution (T&D) systems. Monongahela’s business is the operation of electric T&D systems in Ohio and West Virginia, the operation of natural gas T&D systems in West Virginia, and the generation of electric energy for its West Virginia jurisdiction. In 2002, Monongahela aligned its businesses into two principal business segments. The Generation and Marketing segment is comprised of Monongahela’s electric generation. The Delivery and Services segment is comprised of Monongahela’s electric and natural gas T&D systems.

Use of Estimates: The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires Monongahela to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. The estimates that require management’s most difficult, subjective, and complex judgment involve goodwill, unbilled revenues, regulatory assets and liabilities, and long-lived assets. Significant changes in the estimates could have a material effect on Monongahela’s results of operations, cash flows, and financial position.

Excess of Cost Over Net Assets Acquired (Goodwill): Effective January 1, 2002, with the implementation of Financial Accounting Standards Board (FASB) statement of financial statements (SFAS) No. 142 “Goodwill and Other Intangible Assets”, Monongahela recognized an impairment loss on all of its goodwill. For Monongahela, the impairment of its goodwill involved the estimation of the fair value of its reporting units, where a reporting unit represents an operating segment or one level below an operating segment, which involved the use of present value measurements and cash flow models. This process involved judgments on a broad range of information.

usage by customer type, weather effects, electric and natural gas line losses, and the most recent consumer rates. As this process uses several significant estimates and assumptions, a significant change in them could have a material effect on Monongahela’s results of operations and financial position.

Regulatory Assets and Liabilities: Monongahela is regulated by various federal and state regulatory agencies. As a result, Monongahela qualifies for the application of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”, which recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets or liabilities arise as a result of a difference between GAAP, excluding the effects of rate regulation, and the economic effect of decisions by regulatory agencies. Regulatory assets generally represent incurred costs that have been deferred, as they are probable of recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for various reasons.

Monongahela recognizes regulatory assets and liabilities in accordance with the rulings of its federal and state regulators. Future regulatory rulings may affect the carrying value and accounting treatment of Monongahela’s regulatory assets and liabilities at each balance sheet date. Monongahela assesses whether the regulatory assets are probable of future recovery by considering factors such as regulatory environment changes, recent rate orders issued by the applicable regulatory agencies, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an effect on the recovery of costs, the rate of return on invested capital, and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material effect on Monongahela’s results of operations, cash flows, and financial position.

Long-lived Assets: Monongahela’s consolidated balance sheet includes significant long-lived assets, which are not subject to recovery under SFAS No. 71. As a result, Monongahela must generate future cash flows from such assets in a non-regulated environment to ensure the carrying value is not impaired. Monongahela assesses the carrying amount and potential impairment of these assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors Monongahela considers in determining if an impairment review is necessary include a significant underperformance of the assets relative to historical or projected future operating results, a significant change in Monongahela’s use of the assets or business strategy related to such assets, and significant negative industry or economic trends. When Monongahela determines that an impairment review is necessary, a comparison is made between the expected undiscounted future cash flows and the carrying amount of the asset. If the carrying amount of the asset is the larger of the two balances, an impairment loss is recognized equal to the amount by which the carrying amount of the asset exceeds the fair value of the asset. The fair value is determined by the use of quoted market prices, appraisals, or the use of valuation techniques such as expected discounted future cash flows. Monongahela must make assumptions regarding these estimated future cash flows and other factors to determine the fair value of the respective assets. Significant changes to these assumptions could have a material effect on Monongahela’s results of operations and financial position.

The decrease in earnings for 2002, before extraordinary charge and cumulative effect of accounting change, of $55.8 million was primarily due to lower net revenues, increased purchased energy costs, and a charge for workforce reduction expenses. The decrease in earnings for 2001, before extraordinary charge and cumulative effect of accounting change, of $5.1 million was primarily due to the June 1, 2001, transfer of Monongahela’s Ohio portion of its generating assets to Allegheny Energy Supply Company, LLC (AE Supply), an unregulated generation subsidiary of Allegheny.

The extraordinary charge of $63.1 million, net of income taxes, reflects write-offs by Monongahela of costs determined to be unrecoverable as a result of West Virginia and Ohio legislation requiring deregulation of electric generation and recognition of a rate stabilization obligation. As discussed in Note 10 to the consolidated financial statements, Monongahela determined, in the first quarter of 2003, that deregulation of its West Virginia generating assets was no longer probable.

The cumulative effect of accounting change of $115.4 million, net of income taxes, reflects a charge for the impairment of goodwill related to the acquisitions of Mountaineer and West Virginia Power (WVP). See Notes 4 and 5 to the consolidated financial statements for additional details.

Delivery and Services revenues increased $6.8 million for 2002 primarily due to an increase in regulated electric revenues offset, in part, by a decrease in regulated natural gas revenues. The increase in regulated electric revenues was the result of an increase in customer usage in the residential and industrial classes. The increase in residential revenues reflected a 60.5 percent increase in cooling degree days versus the prior year. The industrial class is less affected by weather conditions and reflected increased usage in the chemical and primary metals industries. The decrease in regulated natural gas revenues was primarily due to commercial customers switching to other natural gas suppliers and becoming transportation customers only.

Delivery and Services revenues increased $132.6 million for 2001 and is attributable to an increase in regulated natural gas revenues due to the acquisition of Mountaineer in August 2000.

Generation and Marketing represents energy and ancillary services sales to Monongahela’s Delivery and Services segment and excess energy sales to AE Supply. Generation and Marketing revenues decreased $38.8

million and $46.8 million for 2002 and 2001, respectively, due to the transfer of Monongahela’s Ohio and FERC jurisdictional generation assets to AE Supply on June 1, 2001.

Fuel Consumed for Electric Generation: Fuel consumed for electric generation, all within the Generation and Marketing segment, for 2002, 2001, and 2000 was $128.9 million, $131.8 million, and $145.7 million, respectively. Fuel consumed for electric generation represents the cost of coal burned for electric generation. Total fuel expenses decreased $2.9 million for 2002 primarily due to an 8.5 percent decrease in kilowatt-hours (kWhs) generated, partially offset by a 5.1 percent increase in average fuel prices. Total fuel expenses for 2001 decreased by $13.9 million due to an 11.6 percent decrease in kWhs generated, partially offset by a 2.6 percent increase in average fuel prices. The decline in kWhs generated for 2002 and 2001 was primarily due to Monongahela’s transfer of its Ohio and FERC jurisdictional generating assets to AE Supply on June 1, 2001.

Purchased Energy and Transmission: Purchased energy and transmission represents power purchases from and exchanges with other companies and purchases from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and consists of the following items:

For 2001, the Delivery and Services segment’s purchased power from PURPA generation decreased $11.0 million due to an unscheduled shutdown of a PURPA generation facility and credits recorded by Monongahela for overpayments of PURPA generation in prior years.

Prior to Monongahela’s transfer of its Ohio and FERC jurisdictional generating assets to AE Supply on June 1, 2001, the Delivery and Services segment’s other purchased energy consisted primarily of energy purchases from Monongahela’s Generation and Marketing segment to supply energy to customers in all of its jurisdictions. Effective June 1, 2001, the Delivery and Services segment’s other purchased energy consisted primarily of energy purchases from Monongahela’s Generation and Marketing segment to supply energy to its West Virginia customers and energy purchases from AE Supply to supply its PLR retail load in Ohio. The increases in the Delivery and Services segment’s other purchased energy for 2002 and 2001 of $11.3 million and $3.4 million, respectively, are primarily due to purchases from AE Supply at prices that are higher than the prices charged by Monongahela’s Generation and Marketing segment. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional details concerning the Delivery and Services segment’s purchase of energy from AE Supply.

The Generation and Marketing segment’s purchased energy and transmission increased $8.1 million for 2002 and decreased $4.0 million for 2001. The increase in 2002 was due to higher transmission charges associated with Monongahela joining the PJM in April 2002, and increased non-affiliated energy purchases at

increased prices. The decrease in 2001 was due primarily to lower AGC capacity shortages due to the transfer of Monongahela’s Ohio portion of its generation assets to AE Supply on June 1, 2001.

The elimination for purchased energy and transmission between the Delivery and Services segment and the Generation and Marketing segment is necessary to remove the effect of the Delivery and Services segment’s purchase of energy from the Generation and Marketing segment.

Natural Gas Purchases: Natural gas purchases, all within the Delivery and Services segment, for 2002, 2001, and 2000 were $134.0 million, $128.0 million, and $56.1 million, respectively. Natural gas purchases represent the cost of natural gas for delivery to customers. The increase in natural gas purchases of $6.0 million for 2002 was primarily due to an increase in transportation costs associated with the purchase of natural gas, largely offset by a decrease in the quantity of natural gas purchased as a result of commercial customers switching to other natural gas suppliers. The increase in natural gas purchases of $71.9 million for 2001 was primarily due to the acquisition of Mountaineer in August 2000.

Deferred Energy Costs, Net: The increase in deferred energy costs, net for 2002 is the result of Mountaineer returning to the Purchased Gas Adjustment (PGA) mechanism in West Virginia on November 1, 2001. See Note 1 to the consolidated financial statements for additional information on deferred energy costs, net.

Workforce Reduction Expenses: Workforce reduction expenses for 2002 were $17.7 million for the Delivery and Services segment and $10.1 million for the Generation and Marketing segment, for a total of $27.8 million. There were no workforce reduction expenses for 2001 and 2000.

In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction. The workforce reduction expenses were allocated among Allegheny’s subsidiaries. Allegheny achieved workforce reductions of approximately 10 percent primarily through a voluntary Early Retirement Option (ERO) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans for Termination Benefits” and SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions”. For 2002, approximately 600 of Allegheny’s eligible employees accepted the ERO program. Monongahela recorded a charge of $27.7 million, before income taxes ($16.5 million, net of income taxes) for its allocable share of the effect of the ERO program.

Allegheny offered a Staffing Reduction Separation Program (SRSP) for employees whose positions are being eliminated as part of the workforce reductions. The SRSP provides for severance and other employee-related costs. For the year ended December 31, 2002, Monongahela recorded a charge of $.1 million, before income taxes ($.1 million, net of income taxes), for its allocable share of the effect of the SRSP related to approximately 80 Allegheny employees whose positions have been or are being eliminated.

Operation Expense: Operation expenses for 2002, 2001, and 2000 were as follows:

Services segment of $5.4 million for 2002 was primarily due to an increase in salaries and wages and employee benefits. The increase in operation expenses for the Delivery and Services segment of $31.9 million for 2001 was primarily due to additional expenses associated with serving customers acquired through the acquisition of Mountaineer in August 2000. The decrease in operation expense for the Generation and Marketing segment of $2.4 million for 2002 was primarily due to the transfer of the Ohio and FERC jurisdictional generating assets to AE Supply on June 2001. The increase in operation expenses for the Generation and Marketing segment of $6.5 million for 2001 was attributable primarily to an increase in maintenance costs as compared to 2000.

Depreciation and Amortization: Depreciation and amortization expenses for 2002, 2001, and 2000 were as follows:

The Delivery and Services segment’s depreciation and amortization expenses decreased $3.0 million for 2002 primarily due to the elimination of goodwill amortization in 2002. The increase in depreciation and amortization expense of $8.8 million for the Delivery and Services segment for 2001 was primarily due to the amortization of goodwill related to the acquisition of Mountaineer in August 2000. Effective January 1, 2002, Monongahela adopted SFAS No. 142 and, accordingly, ceased the amortization of all goodwill. Monongahela recorded goodwill amortization of $5.1 million and $2.2 million for 2001 and 2000, respectively, which related to its acquisitions of Mountaineer in August 2000 and WVP in December 1999. The Generation and Marketing segment’s deprecation and amortization expenses decreased $2.5 million for 2002 and 2001 primarily due to the transfer of the Ohio and FERC jurisdictional generating assets to AE Supply on June 1, 2001.

Taxes Other Than Income Taxes: Taxes other than income taxes for 2002, 2001, and 2000 were as follows:

Taxes other than income taxes primarily include gross receipts taxes, payroll taxes, and property taxes. Total taxes other than income taxes for the Delivery and Services segment increased $5.3 million and $6.3 million for 2002 and 2001, respectively, primarily due to the acquisition of Mountaineer in August 2001. Total taxes other than income taxes decreased for the Generation and Marketing segment $5.3 million for 2002 due to the transfer of the Ohio and FERC jurisdictional generating assets to AE Supply on June 1, 2001. Total taxes other than income taxes increased $1.5 million for 2001 for the Generation and Marketing segment due to increased West Virginia Business and Occupation Taxes offset, in part, by the transfer of its Ohio and FERC jurisdictional generating assets.

Other income and expenses, net represent nonoperating revenues and expenses. Other income and expenses decreased $1.6 million for 2002 primarily due to decreases in interest income, Monongahela’s share of the earnings from Allegheny Generating Company (AGC), an unregulated generation unit of AE Supply, and non-operating income offset, in part, by gains on Canaan Valley land sales. The increase in other income and expenses of $1.6 million for 2001 was due primarily to an increase in interest income as a result of investments within the money pool offset, in part, by a decrease in Monongahela’s share of the earnings from AGC. See Note 17 to the consolidated financial statements for additional details.

Interest charges decreased $2.9 million for 2002 primarily due to the retirement of long-term debt. Interest charges increased $7.5 million for 2001 primarily due to increased average long-term debt outstanding as a result of additional debt incurred for the acquisition of Mountaineer in August 2000. The increase in average long-term debt in 2000 was also the result of the acquisition of WVP in December 1999.

For additional information regarding Monongahela’s debt, see the consolidated statement of capitalization and Notes 8 and 12 to the consolidated financial statements.

Income tax expense on continuing operations was $8.8 million in 2002, $38.5 million in 2001, and $52.4 million in 2000. The effective tax rates were 20.7 percent, 30.1 percent, and 35.7 percent for 2002, 2001, and 2000, respectively.

The change in the effective tax rate between 2002 and 2001, a net 9.4 percent decrease, was caused by: prior period adjustment (7.7 percent increase); adjustment to nondeductible reserves (6.8 percent decrease); equity in the earnings of subsidiaries (4.6 percent decrease); amortization of deferred investment credit (3.5 percent decrease); tax depreciation (2.3 percent decrease); and other various items (0.1 percent net increase).

The change in the effective tax rate between 2001 and 2000, a net 5.5 percent decrease, was caused by: adjustment to nondeductible reserves (4.8 percent decrease); equity in earnings of subsidiaries (2.8 percent increase); state income tax (2.3 percent decrease); and other various items (1.2 percent net decrease).

Note 11 to the consolidated financial statements provides a further analysis of income tax expenses.

The extraordinary charge in 2000 of $63.1 million, net of income taxes, reflects a write-off by Monongahela for net regulatory assets determined to be unrecoverable from customers and the establishment of a rate stabilization account for residential and small commercial customers as required by the deregulation plans adopted in Ohio and West Virginia. See Note 10 to the consolidated financial statements for additional information.

On January 1, 2002, Monongahela adopted SFAS No. 142. An assessment upon adoption determined that approximately $195.0 million of goodwill, related to its acquisitions of Mountaineer and WVP, was impaired. As a result, Monongahela recorded a charge of $115.4 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2002. See Note 5 to the consolidated financial statements for additional information.

To meet cash needs for operating expenses, the payment of interest, retirement of debt, and its construction program, Monongahela has used internally generated funds (net cash provided by operating activities less common and preferred dividends) and external financings, including the sale of common and preferred stock, debt instruments, installment loans, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, Monongahela’s cash needs, and capital structure objectives of Monongahela. The availability and cost of external financings depend upon the financial condition of Monongahela and market conditions.

Monongahela had several debt agreements that required it to file copies of its annual or quarterly reports as filed with the SEC pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) with or for the debt holders. Monongahela is also required to deliver to or for the trustees under its indentures a certificate indicating that Monongahela has complied with all conditions and covenants under the agreements. On April 30, 2003, Monongahela provided certificates to the trustees under its indentures indicating that it was not in compliance with the covenants for filing its annual and quarterly reports that are contained in its First Mortgage Bonds and Medium Term Notes. The covenant breach of the First Mortgage Bonds and Medium Term Notes is deemed a default of these debt agreements, as well as a default under certain other of Monongahela’s indebtedness, primarily its Pollution Control Bonds, that contain cross-acceleration provisions with the First Mortgage Bonds, for financial reporting purposes in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived by the Creditor”. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was approximately $600.1 million as of December 31, 2002. To date, the debt holders have not provided Monongahela with any notices of default under the agreements. Such notices, if received, would allow Monongahela 60 days to cure its noncompliance before the debt holders could accelerate the due dates of the debt obligations.

As of December 31, 2002, $90.0 million was outstanding under two Mountaineer Note Purchase Agreements. These Note Purchase Agreements contain covenants that required Mountaineer to deliver annual financial statements, an audited 2002 annual report, and certain certificates to the noteholders by March 31, 2003. Mountaineer did not deliver these items to the noteholders by March 31, 2003. Effective July 23, 2003, Mountaineer obtained waivers extending the covenant due dates until September 30, 2003, for the 2002 annual audited financial statements. Also, Mountaineer has obtained waivers until October 31, 2003, and December 31, 2003 for the delivery of its unaudited financial statements to the noteholders for the first and second quarter of 2003, respectively. These amounts are also classified as current on the consolidated balance sheet.

Monongahela has prepared its financial statements assuming that it will continue as a going concern. However, noncompliance with its debt covenants and the classification of certain debt as current has caused its independent auditors, PricewaterhouseCoopers LLP, to issue a modified opinion that indicates there is a substantial doubt about Monongahela’s ability to continue as a going concern (a “Going Concern” opinion). The financial statements do not include any adjustments that might result from the resolution of this uncertainty.

In 2003, Monongahela’s cash flows are expected to be adequate to meet all of its payment obligations under the First Mortgage Bonds and Pollution Control Bonds and to fund other liquidity needs. Monongahela’s ability to meet its payment obligations under its First Mortgage Bonds and Pollution Control Bonds and to fund capital expenditures will depend on its future performance. Monongahela’s future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control.

In February and March 2003, AE, AE Supply, Monongahela and West Penn entered into agreements (the Borrowing Facilities), totaling $2,437.8 million, with various credit providers to refinance the bulk of AE and AE Supply’s short-term debt. Proceeds from the financing were used to refinance existing debt and for general corporate purposes.

Following is a summary of the terms of the Borrowing Facilities at AE and its subsidiaries other than AE Supply:

The Borrowing Facilities at AE, Monongahela and West Penn are unsecured and refinanced $340.0 million of existing debt and letters of credit.

The terms of the Borrowing Facilities require that Allegheny, on a consolidated basis meet certain financial tests, as defined in the Borrowing Facilities agreements. The Borrowing Facilities also have provisions requiring prepayments out of the proceeds of asset sales, debt and equity issuances, and excess cash flows, as defined in the agreements, by Allegheny, including Monongahela. Any prepayments under the provisions of the Borrowing Facilities would reduce the amounts of scheduled principal payments in 2003 and 2004.

During 2002, Monongahela was a participant in bank lines of credit with Allegheny and various affiliates. At December 31, 2002, the entire lines of credit were drawn by Allegheny, and no amounts were available to Monongahela.

Monongahela and its affiliates also use an internal money pool as a facility to accommodate intercompany short-term borrowing needs, to the extent that certain companies have funds available. The money pool provides funds to approved Allegheny subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven-day commercial paper rate, as quoted by the same source, less four basis points. At December 31, 2002, Monongahela had no borrowings outstanding from the money pool but had $8.5 million invested in the money pool, recorded as Notes Receivable Due From Affiliates on the consolidated balance sheet. Monongahela has SEC authorization for total short-term borrowings, from all sources, of $106.0 million. See Note 12 to the consolidated financial statements for information regarding short-term borrowings.

Monongahela has various obligations and commitments to make future cash payments under contracts, such as debt instruments, lease arrangements, fuel agreements, and other contracts. The table below provides a summary of the payments due by period for these obligations and commitments.

Debentures, notes, bonds, and QUIDS in this table represent contractual cash payments required without taking into account their classification as current, as a result of a default in the underlying debt agreements, on the consolidated balance sheet.

Monongahela’s capital expenditures, including construction expenditures, for 2003 and 2004, are estimated at $68.0 million and $71.6 million, respectively. These estimated expenditures include $17.4 million and $19.1 million, respectively, for environmental control technology. See Note 22 to the consolidated financial statements for additional information.

Internal generation of cash, consisting of cash flows from operations reduced by common and preferred dividends, was $101.3 million in 2002, compared with $91.0 million in 2001.

Cash flows from operations for 2002 decreased $15.9 million from 2001 reflecting changes in net income, deferred investment credit and income taxes, net, materials and supplies, and taxes payable. Cash flows used in investing decreased $15.3 million for 2002 primarily due to lower construction expenditures. Cash flows used in financing decreased $50.6 million for 2002 primarily due to changes in reduced investments in the money pool, reduced dividend payments, offset by reduced net long-term debt borrowings.

Cash flows from operations for 2001 decreased $11.3 million reflecting changes in net income, accounts receivable, materials and supplies, prepayments, accounts receivable from affiliates, and accounts payable to affiliates. Cash flows used in investing decreased for 2001 primarily due to the acquisition of Mountaineer in 2000. Cash flows used in financing increased $194.2 million for 2001 due to the equity contribution from parent and an increase in dividends paid.

Debentures, Notes, Bonds, and QUIDS: During 2002, Monongahela redeemed $1.8 million of 4.35 percent unsecured notes and $25.0 million of 7.375 percent first mortgage bonds, and Mountaineer made repayments of $3.3 million on 7.6 percent fixed-rate unsecured notes.

See Note 7 to the consolidated financial statements for additional details regarding debt issued and redeemed during 2002 and 2001 and additional capital requirements for debt maturities.

Monongahela’s long-term debt due within one year at December 31, 2002, of $65.9 million represents: $19.1 million of installment purchase obligations, $43.5 million of medium-term notes, and $3.3 million of Mountaineer’s unsecured notes.

Short-Term Debt: See Note 11 to the consolidated financial statements for additional details regarding short-term debt activity during 2002 and 2001.

As of December 31, 2002 and 2001, Monongahela had no material financial instruments, commodity contracts, or other commitments that required recognition as assets or liabilities on the consolidated balance sheet at fair value under the provisions of SFAS 133.

Effective January 1, 2002, Monongahela adopted SFAS No. 141 “Business Combinations” and SFAS No. 142. The application of SFAS No. 142 resulted in Monongahela recognizing an impairment loss on all of its goodwill. See Note 4 to consolidated financial statements for additional information.

Effective January 1, 2003, Monongahela adopted SFAS No. 143 “Accounting for Asset Retirement Obligations”, which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. See Note 21 to the consolidated financial statements for additional information.

Effective January 1, 2002, Monongahela adopted SFAS No. 144 “Accounting for the Impairment of Disposal of Long-lived Assets”, which addresses financial accounting and reporting for the impairment or

disposal of long-lived assets. SFAS No. 144 establishes a singular accounting model for the disposal of long-lived assets and carries- forward the impairment provisions of SFAS No. 121.

In November 2002, the FASB issued FASB Interpretation No. (FIN) 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including indirect Guarantees of Indebtedness of Others”, which requires disclosures by a guarantor concerning its obligations under certain guarantees that it has issued. FIN 45 also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issue or modified after December 31, 2002. Allegheny does not anticipate FIN 45 will have a material impact on its statement of operations and financial position.

Various other new accounting pronouncements not mentioned above that were effective in 2002 do not have a material effect on Monongahela’s results of operations, cash flows, and financial position.

Allegheny Energy, Inc. (AE) and its consolidated subsidiaries (collectively, Allegheny, including its subsidiary The Potomac Edison Company (Potomac Edison) have experienced significant changes in their businesses over the last several years, as described in ITEM 1. BUSINESS—Recent Events. During 2002, Allegheny experienced a strain on its liquidity position, and, at December 31, 2002, a significant portion of its debt, including the debt of Potomac Edison, has been reclassified as current, as discussed in Financial Condition, Requirements and Resources.

In addition to Allegheny’s strained financial condition, Allegheny, including Potomac Edison, identified various errors relating to its financial statements for years prior to 2002 as a result of a comprehensive financial review as discussed in Note 2 to Potomac Edison’s financial statements. Corrections to these errors are reflected in the financial statements for the year ended December 31, 2002, and decreased net income for 2002 by approximately $.7 million for Potomac Edison. Allegheny’s management concluded that these errors were not material, either individually or in the aggregate, to the 2002 or any prior year’s financial statements.

Potomac Edison is a regulated wholly-owned subsidiary of AE and collectively with AE’s consolidated subsidiaries (Allegheny) and along with its regulated utility affiliates, Monongahela Power Company (Monongahela) and West Penn Power Company (West Penn), collectively doing business as Allegheny Power, operate electric and natural gas Transmission and Distribution (T&D) systems. Potomac Edison’s business is the operation of an electric T&D system in Maryland, Virginia, and West Virginia. Potomac Edison currently operates under a single business segment, Delivery and Services. Prior to August 1, 2000 Potomac Edison operated an additional segment, Generation and Marketing.

Use of Estimates: The preparation of financial statements in conformity with generally accepted accounting principles of the United States of America (GAAP) requires Potomac Edison to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. The estimates that require management’s most difficult, subjective, and complex judgements involve unbilled revenues and regulatory assets and liabilities. Significant changes in the estimates could have a material effect on Potomac Edison’s results of operations, cash flows, and financial position.

Unbilled Revenues: Energy sales to individual customers are based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers subsequent to the last meter reading are estimated and Potomac Edison recognizes unbilled revenues. The unbilled revenue estimates are based on daily purchases of electricity, estimated customer usage by customer type, weather effects, electric line losses, and the most recent customer rates. As this process uses several significant estimates and assumptions, a significant change in them could have a material effect on Potomac Edison’s results of operations and financial position.

Regulatory Assets and Liabilities: Potomac Edison is regulated by various federal and state regulatory agencies. As a result, Potomac Edison qualifies for the application of Financial Accounting Standards Board (FASB), SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets or liabilities arise as a result of a difference between GAAP, excluding the effects of rate regulation, and the

economic effect of decisions by regulatory agencies. Regulatory assets generally represent incurred costs that have been deferred, as they are probable of recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for various reasons.

Potomac Edison recognizes regulatory assets and liabilities in accordance with the rulings of its federal and state regulators. Future regulatory rulings may affect the carrying value and accounting treatment of Potomac Edison’s regulatory assets and liabilities at each balance sheet date. Potomac Edison assesses whether the regulatory assets are probable of future recovery by considering factors such as regulatory environment changes, recent rate orders issued by the applicable regulatory agencies, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an effect on the recovery of costs, the rate of return on invested capital, and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material effect on Potomac Edison’s results of operations, cash flows, and financial position.

Earnings were $32.7 million in 2002, $48.0 million in 2001, and $70.5 million (after extraordinary charges of $13.9 million) in 2000.

The decrease in earnings for 2002 of $15.3 million was primarily due to increased operating expenses, including a charge for workforce reduction expenses.

The decrease in earnings for 2001, before the extraordinary charge, of $36.4 million was primarily due to the August 1, 2000, transfer, at book value, of 2,100 megawatt (MW) of Potomac Edison’s generating capacity to Allegheny Energy Supply, LLC, an unregulated generation subsidiary of Allegheny Energy, Inc., also a holding Company (AE Supply). The extraordinary charge in 2000 of $13.9 million, net of taxes, reflects a write-off of costs determined to be unrecoverable as a result of West Virginia legislation requiring deregulation of electric generation and recognition of a rate stabilization obligation. See Note 7 to the consolidated financial statements for additional details.

“Customer choice”—that is, the ability for customers to choose an alternate electricity generation supplier, while retaining Potomac Edison’s transmission and distribution services—has had little impact on Potomac Edison as very few customers have chosen alternate suppliers.

The following discussion applies to changes in all operating revenue categories in the table above. Under the provisions of the Public Utilities Regulatory Policies Act of 1978 (PURPA), Potomac Edison was required to enter into a long-term contract to purchase capacity and energy from the AES Warrior Run facility through the

beginning of 2030. Effective July 1, 2000, Potomac Edison was authorized by the Maryland Public Service Commission (Maryland PSC) to recover all contract costs from the AES Warrior Run facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market, through the life of the contract by means of a retail revenue surcharge (the AES Warrior Run Surcharge). Any under or overrecovery of net costs is being deferred on Potomac Edison’s balance sheet, as deferred energy costs, pending subsequent recovery from or return to customers through adjustments to the AES Warrior Run Surcharge. Since the AES Warrior Run Surcharge represents a dollar-for-dollar recovery of net contract costs, there is no impact on Potomac Edison’s net income related to AES Warrior Run Surcharge revenues or revenues from sales of AES Warrior Run output. From July 1, 2000, through December 31, 2001, Potomac Edison sold output of the AES Warrior Run facility to non-affiliated parties. These revenues are reflected under “Transmission services and bulk power” in the table above. Through a competitive bidding process approved by the Maryland PSC, AE Supply was awarded the contract to purchase the output of the AES Warrior Run facility for the period January 1, 2002, through December 31, 2004. These revenues are reflected under “Other affiliated and nonaffiliated energy services” in the table above.

Effective with bills rendered on or after January 8, 2002, there was a decrease in distribution rates for Maryland customers. This decrease or “Customer Choice Credit” is a result of implementing the rate reductions called for by a settlement agreement approved by the Maryland PSC in December 1999. The Customer Choice Credit will remain in effect until a total of $72.8 million (approximately $10.4 million annually) has been credited to residential customers and a total of $10.5 million (approximately $1.5 million annually) has been credited to commercial and industrial customers.

Residential revenues increased $13.8 million in 2002 primarily due to an increase in AES Warrior Run Surcharge revenues and a 6.1 percent increase in kilowatt-hour (kWh) sales. The increase in sales reflected a 2.8 percent increase in the average number of customers served, a 2.0 percent increase in heating degree days versus the prior year, and a 33.6 percent increase in cooling degree days versus the prior year. Partially offsetting these factors and reducing revenues was the Customer Choice Credit.

Residential revenues increased $14.0 million in 2001 primarily due to a 2.3 percent increase in kWh sales, offset slightly by decreased AES Warrior Run Surcharge revenues as a result of Potomac Edison selling AES Warrior Run output into the wholesale energy market for all of 2001 and only a part of 2000. The increase in sales reflected a 2.1 percent increase in the average number of customers served, partially offset by the effects of a 6.8 percent decrease in heating degree days and a .7 percent decrease in cooling degree days versus the prior year.

Commercial revenues increased $14.9 million in 2002 primarily due to an increase in AES Warrior Run Surcharge revenues and a 5.6 percent increase in kWh sales. The increase in sales reflected a 2.8 percent increase in the average number of customers served and increased heating and cooling degree days as mentioned above.

Commercial revenues increased $1.7 million in 2001 primarily due a 1.7 percent increase in kWh sales, offset slightly by decreased AES Warrior Run Surcharge revenues as a result of Potomac Edison selling AES Warrior Run output into the wholesale energy market for all of 2001 and only a part of 2000. The increase in sales reflected a 2.8 percent increase in the average number of customers served, partially offset by the effects of decreased heating and cooling degree days as mentioned above.

Industrial revenues increased $5.6 million in 2002 primarily due to an increase in AES Warrior Run Surcharge revenues.

Industrial revenues increased $12.6 million in 2001 primarily due to increases in kWh sales to a major customer in the primary metal industry and several customers in the food products industry.

Wholesale, street lighting, and other revenues decreased $15.7 million in 2002 primarily due to decreased revenues from wholesale customers between April 2002 and August 2002 as a result of operational changes brought about by Potomac Edison’s entry into PJM Interconnection, LLC (PJM). During this period, most of Potomac Edison’s wholesale customers purchased their energy directly from PJM. Thus, during this period, Potomac Edison recognized neither revenues from these customers nor associated purchased energy costs to serve them. Beginning September 1, 2002, additional operational changes resulted in Potomac Edison again recognizing revenues from these wholesale customers and associated purchased energy costs to serve them.

Transmission services and bulk power revenues decreased $40.1 million in 2002 primarily due to the classification of revenues from the output of the AES Warrior Run facility as Transmission services and bulk power in 2001 and as Other affiliated and nonaffiliated energy services in 2002.

Transmission services and bulk power revenues increased $17.8 million in 2001 primarily due to Potomac Edison selling the AES Warrior Run output into the wholesale energy market beginning in July 2000.

Other affiliated and nonaffiliated energy services revenues increased $27.2 million in 2002 primarily due to the classification of revenues from the output of the AES Warrior Run facility as Other affiliated and nonaffiliated energy services in 2002 and as Transmission services and bulk power in 2001. Partially offsetting the increase due to the AES Warrior Run facility was decreased sales to AE Supply. Because of Potomac Edison’s transfer of generating assets to AE Supply in 2000, Potomac Edison no longer has generation available for sale and purchases nearly all of its electricity to serve customers who have not chosen an alternate electricity supplier from AE Supply. Prior to Potomac Edison joining PJM in April 2002, if Potomac Edison purchased more electricity than was needed to serve its customers, the excess electricity purchased was sold back to AE Supply. Upon Potomac Edison joining PJM, operational changes were made so that Potomac Edison no longer has excess electricity to sell back to AE Supply.

Other affiliated and nonaffiliated revenues decreased $12.5 million in 2001 primarily due to decreased sales to AE Supply.

Fuel Consumed for Electric Generation: Fuel expense was eliminated for 2002 and 2001 as a result of the transfer of Potomac Edison’s 2,100 MW electric generation capacity to AE Supply on August 1, 2000.

Purchased Energy and Transmission: Purchased energy and transmission represents power purchases primarily from AE Supply and qualified facilities under the PURPA. Purchased energy and transmission increased $6.3 million in 2002 primarily due to increased purchases from AE Supply at higher prices. Purchased energy and transmission increased $221.7 million in 2001 as a result of Potomac Edison purchasing all of its power for a full year due to the transfer of its generating assets in 2000. Under a revised rate schedule effective January 1, 2001, a portion of the electricity purchased by Potomac Edison from AE Supply is now subject to pricing at market-based rates. Potomac Edison incurred additional purchased electricity costs due to the market-based pricing component of the revised rate schedule of $12.1 million and $3.9 million in 2002 and 2001, respectively. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional details.

Deferred Energy Costs, Net: Deferred energy costs, net are related to the recovery of net costs associated with the AES Warrior Run facility. See “Operating Revenues” for additional details.

Workforce Reduction Expenses: In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction. The workforce reduction expenses were allocated among Allegheny’s subsidiaries. Allegheny achieved workforce reductions of approximately 10 percent primarily through a voluntary Early Retirement Option (ERO) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”. For 2002, approximately 600 of Allegheny’s eligible employees accepted the ERO program. Potomac Edison recorded a charge of $12.4 million, before income taxes ($7.5 million, net of income taxes) for its allocable share of the effect of the ERO program. Allegheny offered a Staffing Reduction Separation Program (SRSP) for employees whose positions were being eliminated as part of the workforce reductions. The SRSP provides for severance and other employee-related costs. For the year ended December 31, 2002, Potomac Edison recorded a charge of $.04 million, before income taxes, for its allocable share of the effect of the SRSP related to approximately 80 Allegheny employees whose positions have been or are being eliminated.

Operation Expense: Operation expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services, and other expenses. The increase in operation expenses of $2.2 million for 2002 was primarily due to increases in salaries and wages and outside services. The decrease in operation expenses for 2001 of $25.1 million was due primarily to a reduction in maintenance expense and fuel handling fees.

Depreciation and Amortization: The increase in depreciation and amortization expenses for 2002 of $2.3 million reflects the completion of the refund to customers of the Maryland deferred fuel balance that had the effect of reducing depreciation and amortization expenses between February and October 2001 and new capital additions. The decrease in depreciation and amortization expenses for 2001 of $27.5 million reflects the transfer of Potomac Edison’s generating assets to AE Supply, offset, in part, by depreciation of new capital additions.

Taxes Other Than Income Taxes: Taxes other than income taxes expense primarily include gross receipts taxes, payroll taxes, and property taxes. Total taxes other than income taxes decreased $16.9 million in 2001 primarily due to lower West Virginia Business and Occupation Taxes and property taxes. The decrease is also reflective of the transfer of Potomac Edison’s generating assets to AE Supply.

Other income and expenses represent nonoperating revenues and expenses before income taxes. Other income and expenses increased $2.9 million for 2002 due primarily to the net impact of coal brokering fees and tax credits related to the purchase of Maryland mined coal. The decrease in other income and expenses for 2001 of $8.7 million was primarily due to a decrease in Potomac Edison’s portion of Allegheny Generating Company’s (AGC), an unregulated generation unit of AE Supply, earnings due to the transfer of Potomac Edison’s ownership interest in AGC to AE Supply on August 1, 2000, coupled with a decrease in interest income and an increase in losses associated with Maryland coal brokerage activities. See Note 13 to the consolidated financial statements for additional details.

Interest on debt decreased $1.9 million in 2002 due primarily to the reduction in short-term debt, including notes payable to affiliates. There were no debt issuances or repayments in 2002.

The decrease of $7.4 million in 2001 was due primarily to a reduction in long-term debt outstanding related to Potomac Edison’s release from co-obligor status with AE Supply in December 2000 on $104.2 million of pollution control notes. AE Supply assumed these notes in conjunction with Potomac Edison’s transfer of generating assets to AE Supply. Interest charges also decreased as a result of the maturity of $75 million of Potomac Edison’s 5⁷/8 percent series first mortgage bonds in March 2000.

For additional information regarding Potomac Edison’s short-term and long-term debt, see the consolidated statement of capitalization and Notes 6 and 9 to the consolidated financial statements.

Income tax expense related to continuing operations was $15.7 million in 2002, $27.4 million in 2001, and $34.1 million in 2000. The effective tax rates were 32.5 percent, 36.3 percent, and 28.8 percent for 2002, 2001, and 2000, respectively.

The change in the effective tax rate between 2002 and 2001, a net 3.9 percent decrease, was caused by: state income tax (3.2 percent decrease); and other immaterial items (.6 percent net decrease).

The change in the effective tax rate between 2001 and 2000, a net 7.5 percent increase, was caused by: state income tax (6.7 percent increase); tax depreciation (2.1 percent decrease); equity in earnings of subsidiaries (1.1 percent increase); and other immaterial items (1.8 percent net increase).

Note 8 to the consolidated financial statements provides a further analysis of income tax expenses.

The extraordinary charge in 2000 of $13.9 million, net of income taxes, reflects a write-off by Potomac Edison for net regulatory assets determined to be unrecoverable from customers and the establishment of a rate stabilization account for residential and small commercial customers as required by the deregulation plans adopted in Virginia and West Virginia.

To meet cash needs for operating expenses, the payment of interest, retirement of debt, and its construction program, Potomac Edison has used internally generated funds (net cash provided by operating activities less common dividends) and external financings, including the sale of common and preferred stock, debt instruments, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, Potomac Edison’s cash needs, and capital structure objectives of Potomac Edison. The availability and cost of external financings depend upon the financial condition of Potomac Edison and market conditions.

Potomac Edison had several debt agreements that required it to file copies of its annual or quarterly reports as filed with the SEC pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) with or for the debt holders. Potomac Edison is also required to deliver to the trustees under its indentures a certificate indicating that Potomac Edison has complied with all conditions and covenants under the agreements. On April 30, 2003, Potomac Edison provided certificates to the trustees under its indentures indicating that it was not in compliance with the covenants for filing its annual and quarterly reports that are contained in its First Mortgage Bonds and Medium Term Notes. These covenant breaches of the First Mortgage Bonds and Medium Term Notes are deemed defaults of the related debt agreements for Potomac Edison’s financial reporting purposes in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived

By the Creditor.” The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was approximately $416.0 million as of December 31, 2002. To date, the debt holders have not provided Potomac Edison with any notices of default under the agreements. Such notices, if received, would allow Potomac Edison 60 days to cure its noncompliance before the debt holders could accelerate the due dates of the debt obligations.

Potomac Edison has prepared its financial statements assuming that it will continue as a going concern. However, noncompliance with its debt covenants and the classification of certain debt as current has caused its independent auditors, PricewaterhouseCoopers LLP, to issue a modified opinion that indicates there is substantial doubt about Potomac Edison’s ability to continue as a going concern (a “Going Concern” opinion). The financial statements do not include any adjustments that might result from the resolution of this uncertainty. Management’s plans with respect to this matter are discussed below.

In 2003, Potomac Edison’s cash flows are expected to be adequate to meet all of its payment obligations under the debt agreements and to fund other liquidity needs. Potomac Edison’s ability to meet its payment obligations in 2004 under its indebtedness and to fund capital expenditures will depend on its future performance. Potomac Edison’s future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control.

During 2002, Potomac Edison was a participant in bank lines of credit totaling $335.0 million with Allegheny and various affiliates. At December 31, 2002, the entire lines of credit were drawn by Allegheny, and no amounts were available to Potomac Edison.

Potomac Edison and its affiliates also use an internal money pool as a facility to accommodate intercompany short-term borrowing needs, to the extent that certain companies have funds available. The money pool provides funds to approved Allegheny subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven-day commercial paper rate, as quoted by the same source, less four basis points. At December 31, 2002, Potomac Edison had borrowings outstanding of $8.5 million from the money pool. Potomac Edison has SEC authorization for total short-term borrowings, from all sources, of $130.0 million. See Note 9 to the consolidated financial statements for information regarding these borrowings.

Potomac Edison has various obligations and commitments to make future cash payments under contracts, such as debt instruments, lease arrangements, purchased power agreements, and other contracts. The table below provides a summary of the payments due by period for these obligations and commitments.

Notes and bonds in this table represent contractual cash payments required without taking into account their classification as current, as a result of a default in the underlying debt agreements on the consolidated balance sheet.

Potomac Edison’s capital expenditures, including construction expenditures, for 2003 and 2004 are estimated at $59.1 million and $59.8 million, respectively.

Internal generation of cash, consisting of cash flows from operations reduced by common dividends, was $96.5 in 2002, compared with $32.6 million in 2001.

Cash flows from operations for 2002 increased $7.0 million from 2001, resulting increases accounts payable and accounts payable/affiliates and income taxes, offset by increases in accounts receivable. Cash flows used in investing for 2002 decreased $9.1 million from 2001 due to reductions in construction expenditures. Cash flows used in financing for 2002 increased $11.4 million from 2001. Cash used for short-term financing increased $64.0 million, offset by a decrease in cash paid for dividends of $56.9 million. Additionally, the absence of financing activities relating to long-term debt transactions accounted for $4.3 million of the variance.

Cash flows from operations for 2001 decreased $22.6 million from 2000 primarily from changes in net income, depreciation and amortization, deferred investment credit and income taxes, accrued taxes, and accrued interest levels. Cash flows used in investing for 2001 decreased $16.8 million from 2000 due to reductions in construction expenditures. Cash flows used in financing for 2001 decreased $32.5 million from 2000 due primarily to a reduction in dividends paid.

Notes and bonds: Potomac Edison had no issuances or redemptions of debt during 2002.

See Note 6 to the consolidated financial statements for additional details regarding long-term debt issued and redeemed during 2001 and additional capital requirements for debt maturities.

Short-term Debt: Potomac Edison had no short-term debt outstanding at December 31, 2002. See Note 9 to the consolidated financial statements for additional details regarding short-term debt activity during 2002 and 2001.

As of December 31, 2002 and 2001, Potomac Edison had no financial instruments, commodity contracts, or other commitments that required recognition as assets or liabilities on the consolidated balance sheet at fair value under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”.

Effective January 1, 2003, Potomac Edison adopted SFAS No. 143 “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. See Note 17 to the consolidated financial statements for additional information.

In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which requires disclosures by a guarantor concerning its obligations under certain guarantees that it has issued. FIN 45 also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issued or modified after December 31, 2002. Potomac Edison does not anticipate FIN 45 will have a material effect on its statement of operations and financial position.

Potomac Edison does not expect various other new accounting pronouncements not mentioned above that were effective in 2002 to have a material effect on Potomac Edison’s results of operations, cash flows, and financial position.

Allegheny Energy, Inc. (AE) and its consolidated subsidiaries (collectively, Allegheny), including its subsidiary West Penn Power Company (West Penn), have experienced significant changes in their businesses over the last several years, as described in ITEM 1. BUSINESS—Recent Events. During 2002, Allegheny experienced a strain on its liquidity position, and, at December 31, 2002, a significant portion of its debt, including that of West Penn, has been reclassified as current, as discussed in Financial Condition, Requirements and Resources.

In 2002 Allegheny, including West Penn, identified various errors relating to its financial statements for years prior to 2002 as a result of a comprehensive financial review as discussed in Note 2 to West Penn’s financial statements. Corrections to these errors are reflected in the financial statements for the year ended December 31, 2002, and decreased net income for 2002 by approximately $2.3 million. Allegheny’s management concluded that these errors were not material, either individually or in the aggregate, to the 2002 or any prior year’s financial statements.

West Penn is a wholly-owned subsidiary of AE and, along with its regulated utility affiliates, Monongahela Power Company (Monongahela) and The Potomac Edison Company (Potomac Edison), collectively do business as Allegheny Power, operates electric and natural gas transmission and distribution (T&D) systems. West Penn’s business is the operation of an electric T&D system in Pennsylvania. West Penn operates under a single business segment, Delivery and Services.

Use of Estimates: The preparation of financial statements in conformity with generally accepted accounting principles of the United States of America (GAAP) requires West Penn to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. The estimates that require management’s most difficult, subjective, and complex judgments involve adverse power purchase commitments, unbilled revenues, and regulatory assets and liabilities. Significant changes in the estimates could have a material effect on West Penn’s results of operations, cash flows, and financial position.

Adverse Power Purchase Commitments: At December 31, 2002, West Penn’s adverse power purchase commitment liability was $255.2 million, which related to a contract that extends to the year 2016. As a result of the deregulation plan approved in 1998 for West Penn, an adverse power purchase liability was recorded by West Penn related to a commitment to buy electricity from a nonutility generator at prices that are above the future expected market price for electricity. A change in the estimated future market price of electricity or a change in the expected cost of the electricity purchased under the terms of the contract could have a material effect on the adverse power purchase commitment liability and on West Penn’s results of operations and financial position.

Unbilled Revenues: Energy sales to individual customers are based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers subsequent to the last meter reading are estimated and West Penn recognizes unbilled revenues. The unbilled revenue estimates are based on daily purchases of electricity, estimated customer usage by customer type, weather effects, electric line losses, and the most recent consumer rates. As this process uses several significant estimates and assumptions, a significant change in them could have a material effect on West Penn’s results of operations and financial position.

Regulatory Assets and Liabilities: West Penn is regulated by various federal and state regulatory agencies. As a result, West Penn qualifies for the application Financial Accounting Standards Board’s (FASB) of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” which recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets or liabilities arise as a result of a difference between GAAP, excluding the effects of rate regulation, and the economic effect of the decisions by regulatory agencies. Regulatory assets generally represent incurred costs that have been deferred, as they are probable of recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for various reasons.

West Penn recognizes regulatory assets and liabilities in accordance with the rulings of its federal and state regulators. Future regulatory rulings may affect the carrying value and accounting treatment of West Penn’s regulatory assets and liabilities at each balance sheet date. West Penn assesses whether the regulatory assets are probable of future recovery by considering factors such as regulatory environment changes, recent rate orders issued by the applicable regulatory agencies, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an effect on the recovery of costs, the rate of return on invested capital, and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material effect on West Penn’s results of operations, cash flows, and financial position.

Earnings were $94.0 million in 2002, $109.8 million in 2001, and $102.4 million in 2000.

The decrease in earnings for 2002 of $15.8 million was primarily due to increased operating expenses, including a charge for workforce reduction expenses, partially offset by gains on sales of land.

The increase in earnings for 2001 of $7.4 million was primarily due to increased net revenues and decreased interest expense on long-term debt, partially offset by higher operating expenses.

As a result of West Penn’s restructuring settlement, beginning in January 1999 two-thirds of West Penn’s customers were permitted to choose an alternate electricity generation supplier—that is, customers had the ability to choose another provider for the generation or supply portion of their service while retaining West Penn’s T&D services. All of West Penn’s customers were permitted to make this choice beginning in January 2000. Many of those customers choosing an alternate electricity generation supplier began returning to West Penn as their electricity generation supplier during 2000, and this trend has continued through mid-2002. Such a return of

customers to full service does not impact sales since West Penn determines sales on the basis of kilowatt-hours kWhs (kWhs) delivered to customers (regardless of their electricity generation supplier). However, such a return of customers to full service results in a significant increase in revenues due to the addition of a generation charge that West Penn had not collected while the customers were using an alternate electricity generation supplier. The effect on revenues of customers returning to full service was especially noticeable in the commercial and industrial classes where a higher percentage of sales were associated with choice customers returning to full service. As of December 31, 2002, less than .2% of West Penn’s customers were using alternate electricity generation suppliers.

Residential revenues increased $23.3 million in 2002 primarily due to a 2.7% increase in kWh sales and higher gross receipts taxes of $7.5 million. The increase in sales reflected a 47.2% increase in cooling degree days versus the prior year, a 3.7% increase in heating degree days versus the prior year, and a .7% increase in the average number of customers served. Effective January 1, 2002, the Pennsylvania Department of Revenue increased the gross receipts tax rate from 4.4 percent to 5.9 percent for electric distribution companies in the state, including West Penn. The collection of increased gross receipts taxes did not impact West Penn’s earnings, since these taxes are remitted to the state and reflected under “Taxes other than income taxes” on the consolidated statement of operations.

Residential revenues increased $19.1 million in 2001 primarily due to a 3.9% increase in kWh sales, which reflected a 13.3% increase in cooling degree days versus the prior year, partially offset by the effects of an 8.7% decrease in heating degree days versus the prior year, and a .4% increase in the average number of customers served.

Commercial revenues increased $21.3 million in 2002 primarily due to a 4.6% increase in kWh sales, the return of choice customers to full service, and higher gross receipts taxes of $4.8 million. The increase in sales reflected increased heating and cooling degree days as mentioned above and a 1.3% increase in the average number of customers served.

Commercial revenues increased $23.4 million in 2001 primarily due to the return of choice customers to full service. A 1.1% increase in kWh sales, due mainly to a 1.6% increase in the average number of customers served, also contributed to the increase in 2001 revenues.

Industrial revenues increased $22.1 million in 2002 primarily due to the return of choice customers to full service, higher gross receipts taxes of $5.9 million, and higher average rates due to sales mix variances (i.e., increases in sales to customers with higher average rates and decreases in sales to customers with lower average rates).

Industrial revenues increased $14.0 million in 2001 primarily due to the return of choice customers to full service, partially offset by decreased sales, mainly to the steel industry.

Wholesale, street lighting, and other revenues decreased $9.5 million in 2002 primarily due to decreased revenues from wholesale customers between April 2002 and August 2002 as a result of operational changes brought about by West Penn’s entry into the PJM Interconnection, LLC, a regional transmission organization (PJM). During this period, most of West Penn’s wholesale customers purchased their energy directly from PJM. Thus, during this period, West Penn recognized neither revenues from these customers nor associated purchased energy costs to serve them. Beginning September 1, 2002, additional operational changes resulted in West Penn again recognizing revenues from these wholesale customers and associated purchased energy costs to serve them.

Wholesale, street lighting, and other revenues increased $7.9 million in 2001 primarily due to the reversal of a regulatory asset in 2000 and the resulting reduction in revenues.

Transmission services and bulk power revenues increased $7.0 million in 2002 primarily due to increased sales to non-affiliated companies through PJM. In 2001, the bulk of West Penn’s transmission services was sold to Allegheny Energy Supply Company, LLC (AE Supply), an unregulated generation affiliate. These 2001 revenues were included in “Other affiliated and nonaffiliated energy services”.

Other affiliated and nonaffiliated energy services revenues decreased $25.6 million in 2002 primarily due to decreased revenues from AE Supply. Because of West Penn’s transfer of generating assets to AE Supply in 1999, West Penn no longer has generation available for sale and purchases nearly all of its electricity to serve customers who have not chosen an alternate electricity supplier from AE Supply. Prior to West Penn joining PJM in April 2002, if West Penn purchased more electricity than was needed to serve its customers, the excess electricity purchased was sold back to AE Supply. Upon West Penn joining PJM, operational changes were made so that West Penn no longer has excess electricity to sell back to AE Supply.

Other affiliated and nonaffiliated energy services revenues increased $5.7 million in 2001 primarily due to increased revenues from AE Supply due to increased sales back to AE Supply as described above.

Purchased Energy and Transmission: Purchased energy and transmission represents power purchases primarily from AE Supply and qualified facilities under the Public Utilities Regulatory Policies Act of 1978 (PURPA). Purchased energy and transmission increased $44.3 million and $50.4 million in 2002 and 2001, respectively, primarily due to increased purchases from AE Supply at higher prices. Increased purchases from AE Supply were due, in part, to West Penn serving choice customers who returned to West Penn as their electricity generation supplier. Under a revised rate schedule effective January 1, 2001, a portion of the electricity purchased by West Penn from AE Supply is now subject to pricing at market-based rates. West Penn incurred additional purchased electricity costs due to the market-based pricing component of the revised rate schedule of $22.5 million and $7.5 million in 2002 and 2001, respectively. See “ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK” for additional details.

Workforce Reduction Expenses: In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction. The workforce reduction expenses were allocated among Allegheny’s subsidiaries. Allegheny achieved workforce reductions of approximately 10 percent primarily through a voluntary Early Retirement Option (ERO) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”. For 2002, approximately 600 of Allegheny’s eligible employees accepted the ERO program. West Penn recorded a charge of $19.3 million, before income taxes ($11.4 million, net of income taxes) for its allocable share of the effect of the ERO program. Allegheny offered a Staffing Reduction Separation Program (SRSP) for employees whose positions were being eliminated as part of the workforce reductions. The SRSP provides for severance and other employee-related costs. For the year ended December 31, 2002, West Penn recorded a charge of $.1 million, before income taxes, for its allocable share of the effect of the SRSP related to approximately 80 Allegheny employees whose positions have been or are being eliminated.

The increase of $6.0 million in 2001 is mainly due to an increase in various general and administrative expenses, none of which were individually significant.

Depreciation and Amortization: Depreciation and amortization expenses increased $6.4 million and $6.9 million in 2002 and 2001, respectively, primarily due to higher property, plant, and equipment balances, including computer software that is amortized over comparatively short lives.

Taxes Other Than Income Taxes: Taxes other than income taxes primarily include gross receipts taxes, payroll taxes, property taxes, and capital stock/franchise taxes. Total taxes other than income taxes increased $9.3 million in 2002 primarily due to increased Pennsylvania gross receipts taxes in 2002. See “Operating Revenues” above for additional details on the increase in Pennsylvania gross receipts taxes in 2002.

Total taxes other than income taxes increased $9.9 million in 2001 primarily due to increased gross receipts taxes resulting from higher revenues and Pennsylvania Capital Stock tax adjustments in 2000 related to prior years.

Other income and expenses represent nonoperating revenues and expenses before income taxes. Other income and expenses increased $22.9 million in 2002 primarily due to gains on Canaan Valley land sales of $20.5 million. Other income and expenses decreased $5.1 million in 2001 primarily due to a decrease in interest income of $4.9 million. See Note 12 to the consolidated financial statements for additional details.

Total interest charges decreased $4.4 million in 2002 compared to 2001 primarily due to lower average long-term debt levels due to the repayment of $70.3 million of transition bonds during 2002.

Total interest charges decreased $15.3 million in 2001 due primarily to West Penn’s release from co-obligor status with AE Supply in December 2000 on $231.0 million of pollution control notes. AE Supply assumed these notes in conjunction with West Penn’s transfer of generating assets to AE Supply. Interest charges also decreased as a result of the repayment of transition bonds during 2001.

For additional information regarding West Penn’s short-term and long-term debt, see the consolidated statement of capitalization and Notes 5 and 8 to the consolidated financial statements. Also, see Financial Condition, Requirements and Resources, Liquidity and Capital Requirements for additional information concerning Allegheny’s debt restructuring.

Income tax expense on continuing operations was $44.5 million in 2002, $54.2 million in 2001, and $55.7 million in 2000. The effective tax rates were 32.1 percent, 33.0 percent, and 35.2 percent for 2002, 2001, and 2000, respectively.

The change in the effective tax rate between 2002 and 2001, a net .9 percent decrease, was caused by: non-cash charitable contributions (2.4 percent decrease); state income tax (2.1 percent increase); and other immaterial items (.6 percent net decrease).

The change in the effective tax rate between 2001 and 2000, a net 2.2 percent decrease, was caused by: state income tax (3.5 percent decrease); tax depreciation (3.0 percent increase); and other immaterial items (1.7 percent net decrease).

Note 7 to the consolidated financial statements provides a further analysis of income taxes.

To meet cash needs for operating expenses, the payment of interest, retirement of debt, and its construction program, West Penn has used internally generated funds (net cash provided by operating activities less common dividends) and external financings, including the sale of common and preferred stock, debt instruments, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, West Penn’s cash needs, and capital structure objectives of West Penn. The availability and cost of external financings depend upon the financial condition of West Penn and market conditions.

West Penn had several debt agreements that required it to file copies of its annual or quarterly reports as filed with the Securities and Exchange Commission (SEC) pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) with or for the debt holders. West Penn is also required to deliver to the trustees under its indentures a certificate indicating that West Penn has complied with all conditions and covenants under the agreements. On April 30, 2003, West Penn provided certificates to the trustee under the indentures indicating that it was not in compliance with the covenants for filing its annual and quarterly reports that are contained in its Transition Bonds and Medium Term Notes. The covenant breaches with respect to the Transition Bonds and Medium Term Notes are deemed defaults of the related debt agreements for West Penn’s financial reporting purposes in accordance with EITF Issue No. 86-30, “Classification of Obligations When Violation is Waived by the Creditor.” The total debt classified as current in the accompanying consolidated balance sheet related to such default was approximately $510.2 million as of December 31, 2002. To date, the debt holders have not provided West Penn with any notices of default under the agreement. Such notices, if received, would allow West Penn either 30 or 60 days to cure its noncompliance before the debt holders could accelerate the due dates of the debt obligations.

In 2003, West Penn’s cash flows are expected to be adequate to meet all of its payment obligations under the debt agreements and to fund other liquidity needs. West Penn’s ability to meet its payment obligations in 2004 under its indebtedness and to fund capital expenditures will depend on its future performance. West Penn’s future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control.

The Borrowing Facilities at AE, Monongahela, and West Penn are unsecured and refinanced $340.0 million of existing debt and letters of credit.

The terms of the borrowing facilities require that Allegheny, on a consolidated basis, meet certain financial tests, as defined in the Borrowing Facilities agreements. The Borrowing Facilities also have provisions requiring prepayments out of the proceeds of asset sales, debt and equity issuances, and excess cash flows, as defined in the agreements, by Allegheny, including West Penn. Any prepayments under the provision of the Borrowing Facilities would reduce the amounts of scheduled principal payments in 2003 and 2004.

During 2002, West Penn was a participant in bank lines of credit totaling $335.0 million with Allegheny and various affiliates. At December 31, 2002, the entire lines of credit were drawn by Allegheny, and no amounts were available to West Penn.

West Penn and its affiliates also use an internal money pool as a facility to accommodate intercompany short-term borrowing needs, to the extent that certain companies have funds available. The money pool provides funds to approved Allegheny subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven-day commercial paper rate, as quoted by the same source, less four basis points. At December 31, 2002, West Penn had neither borrowings outstanding from nor investments in the money pool. West Penn has SEC authorization for total short-term borrowings, from all sources, of $500.0 million. See Note 8 to the consolidated financial statements for information regarding short-term borrowings.

West Penn has various obligations and commitments to make future cash payments under contracts, such as debt instruments, lease arrangements, purchased power agreements, and other contracts. The table below provides a summary of the payments due by period for these obligations and commitments as of December 31, 2002.

West Penn’s capital expenditures, including construction expenditures, for 2003 and 2004 are estimated at $45.4 million and $58.9 million, respectively.

Internal generation of cash, consisting of cash flows from operations reduced by common dividends, was $157.6 million in 2002, compared with $94.7 million in 2001.

Cash flows from operations for 2002 decreased $5.3 million from 2001, reflecting lower operating income, largely offset by income tax refunds and proceeds from Canaan Valley land sales. Cash flows used in investing for 2002 decreased $33.9 million from 2001 as a result of lower construction expenditures and the receipt of proceeds from Canaan Valley land sales. Cash flows used in financing for 2002 decreased $2.7 million from 2001, primarily due to a $79.7 million issuance of long-term debt and a $68.2 million decrease in dividends on common stock, largely offset by a $113.7 million increase in the retirement of long-term debt.

Cash flows from operations for 2001 increased $156.5 million from 2000, reflecting higher net income, collection on accounts receivable, and increased current payable amounts to affiliates. Cash flows used in investing for 2001 increased $17.6 million from 2000 as a result of higher construction expenditures. Cash flows used in financing for 2001 increased $125.6 million from 2000 primarily due to the payment of common dividends of $108.7 million to Allegheny in 2001. West Penn made no dividend payments to Allegheny in 2000 in order to increase West Penn’s equity as a percentage of total capitalization.

Notes, Bonds and QUIDS: During 2002, West Penn Funding LLC, a wholly-owned subsidiary of West Penn (West Penn Funding), repaid $70.3 million of transition bonds, and West Penn repaid $32.1 million of 5.66-percent notes and $1.5 million of 5.56-percent notes.

In April 2002, West Penn issued $80.0 million of 6.625-percent notes due April 15, 2012. In May 2002, West Penn used the net proceeds from the notes to redeem $70.0 million principal amount of 8.0-percent Quarterly Income Debt Securities (QUIDS) due June 30, 2025, at a redemption price of 100 percent of their principal amount plus accrued interest to the redemption date, and for other corporate purposes.

See Note 5 to the consolidated financial statements for additional details regarding debt issued and redeemed during 2002 and 2001 and additional capital requirements for debt maturities.

The amount of debt due, contractually, within one year at December 31, 2002, was $76.0 million and relates entirely to West Penn Funding’s transition bonds. The transition bonds are supported by an Intangible Transition Charge (ITC) that replaces a portion of the Competitive Transition Charge (CTC) that customers pay. The proceeds from the ITC will be used to pay the principal and interest on these transition bonds, as well as other associated expenses.

Short-term Debt: West Penn had no short-term debt outstanding at December 31, 2002. See Note 8 to the consolidated financial statements for additional details regarding short-term debt activity during 2002 and 2001.

As of December 31, 2002 and 2001, West Penn had no financial instruments, commodity contracts, or other commitments that required recognition as assets or liabilities on the consolidated balance sheet at fair value under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133—an amendment of FASB Statement No. 133,” and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities—an amendment of FASB No. 133” (collectively referred to as SFAS No. 133).

Effective January 1, 2003, West Penn adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”, which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. See Note 15 to the consolidated financial statements for additional information.

In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which requires disclosures by a guarantor concerning its obligations under certain guarantees that it has issued. FIN 45 also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issued or modified after December 31, 2002. West Penn does not anticipate that FIN 45 will have a material effect on its statement of operations and financial position.

Various other new accounting pronouncements not mentioned above that were effective in 2002 do not have a material effect on West Penn’s consolidated results of operations, cash flows, and financial position. Also, West Penn expects that various other new accounting pronouncements not mentioned above effective in 2003, will not have a significant impact on West Penn’s consolidated financial statements.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allegheny Energy, Inc. (AE) and its consolidated subsidiaries (collectively, Allegheny) have experienced significant changes in their businesses over the last several years, as described in Item 1, Business, Recent Events. During 2002, Allegheny experienced a strain on its liquidity positions, and, at December 31, 2002, a significant portion of its debt, including the debt of Allegheny Generating Company (AGC), has been reclassified as current, as discussed in Financial Condition, Requirements and Resources.

AGC is owned 77.03 percent by Allegheny Energy Supply Company, LLC (AE Supply) and 22.97 percent by Monongahela Power Company (Monongahela) (collectively the Parents). The Parents are subsidiaries of AE, a diversified utility holding company whose principal business segments are the Generation and Marketing segment and the Delivery and Services segment. The Generation and Marketing segment includes AE Supply, AGC, and Monongahela’s generation for its West Virginia regulatory jurisdiction, which has not deregulated electric generation. AGC owns an undivided 40 percent interest, 960 megawatts (MW), in the 2,400-MW pumped-storage hydroelectric station in Bath County, Virginia, operated by the 60 percent owner, Virginia Electric and Power Company, a nonaffiliated utility. AGC sells its generating capacity to its Parents. AGC operates under a single business segment, Generation and Marketing.

Use of Estimates: The preparation of financial statements in conformity with generally accepted accounting principles of the United States of America (GAAP) requires AGC to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. The estimates that require management’s most difficult, subjective, and complex judgment involve regulatory assets and liabilities. Significant changes in the estimates could have a material effect on AGC’s results of operations, cash flows, and financial position.

Regulatory Assets and Liabilities: AGC is regulated by the FERC. As a result, AGC qualifies for the application of Financial Accounting Standards Board’s Statement of Financial Accounting Standards SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” which recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets or liabilities arise as a result of a difference between GAAP, excluding the effect of rate regulation, and the economic effect of decisions by regulatory agencies. Regulatory assets generally represent incurred costs that have been deferred, as they are probable of recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for various reasons.

AGC recognizes regulatory assets and liabilities in accordance with FERC rulings. Future regulatory rulings may affect the carrying value and accounting treatment of AGC’s regulatory assets and liabilities at each balance sheet date. AGC assesses whether the regulatory assets are probable of future recovery by considering factors such as regulatory environment changes, recent rate orders issued by the FERC, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an effect on the recovery of costs, the rate of return on invested capital, and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material effect on AGC’s results of operations, cash flows, and financial position.

Earnings were $18.6 million in 2002, $20.3 million in 2001, and $21.9 million in 2000.

Earnings decreased $1.7 million in 2002 and $1.6 million in 2001. Revenues decreased each year due to a normal continuing reduction in AGC’s net investment in the Bath County station and its connecting transmission facilities upon which the return on investment is determined.

Affiliated operating revenues were $64.1 million in 2002, $68.5 million in 2001, and $70.0 million in 2000.

AGC’s only operating assets are an undivided 40% interest in the Bath County, Virginia, pumped-storage hydroelectric station and its connecting transmission facilities. AGC has no plans for construction of any other major facilities.

Pursuant to an agreement, the Parents buy all of AGC’s capacity in the station priced under a “cost-of-service formula” wholesale rate schedule approved by the FERC. Under this arrangement, AGC recovers in revenues all of its operation expenses, depreciation, taxes, and a return on its investment. On December 29, 1998, the FERC issued an Order accepting a proposed amendment to the Parents’ Power Supply Agreement for AGC effective January 1, 1999. This amendment sets the generation demand for each Parent proportional to its ownership in AGC. Previously, demand for each Parent fluctuated due to customer usage.

Revenues decreased, and are expected to continue to decrease, each year due to a normal continuing reduction in AGC’s net investment in the Bath County station and its connecting transmission facilities upon which the return on investment is determined. The net investment (primarily net plant less deferred income taxes) decreases to the extent that provisions for depreciation and deferred income taxes exceed net plant additions.

Allegheny achieved workforce reductions of approximately 10 percent primarily through a voluntary Early Retirement Option (ERO) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans for Termination Benefits” and SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” For 2002, approximately 600 of Allegheny’s eligible employees accepted the ERO program. AGC recorded a charge of $.02 million, before income taxes ($.01 million, net of income taxes) for its allocable share of the effect of the ERO program.

Operation Expense: Operation expenses primarily includes salaries and wages, employee benefits, materials and supplies, contract work, outside services, and other expenses. Operation expenses decreased $.5 million in 2001 due to a decrease in licensing fees.

Depreciation Expense: Depreciation expense is determined on a straight-line method based on estimated services lives of depreciable property. Because there have been no material additions or retirements of property, plant and equipment, depreciation charges have remained relatively constant.

Taxes Other Than Income Taxes: Taxes other than income taxes expense primarily include payroll taxes and property taxes. Total taxes other than income taxes decreased $1.5 million in 2001 due to a change in Virginia tax policy. In 2000, Virginia levied gross receipts tax on entities selling power. In 2001 their tax policy was restructured and the gross receipts tax was replaced by a tax on consumption, reducing AGC’s tax expense.

Changes in interest on debt and other interest between 2002, 2001, and 2000 were due to changes in the amount of short-term debt outstanding and changes in short-term interest rates.

Income tax expense on continuing operations was $7.5 million in 2002, $10.2 million in 2001, and $7.5 million in 2000. The effective tax rates were 28.7 percent, 33.4 percent, and 25.5 percent for 2002, 2001, and 2000, respectively.

The change in the effective tax rate between 2002 and 2001, a net 4.7 percent decrease, was caused by: tax depreciation (5.2 percent decrease); and other immaterial items (0.5 percent net increase).

The change in the effective tax rate between 2001 and 2000, a net 7.9 percent increase, was caused by: state income tax (6.2 percent increase); and other immaterial items (1.7 percent net increase).

Note 5 to the financial statements provides a further analysis of income tax expenses.

To meet cash needs for operating expenses, the payment of interest, retirement of debt, and its construction expenditures, AGC has used internally generated funds (net cash provided by operating activities less common dividends) and external financings, including debt instruments. The timing and amount of external financings depend primarily upon economic and financial market conditions, AGC’s cash needs, and capital structure objectives of AGC. The availability and cost of external financings depend upon the financial condition of AGC and market conditions.

On October 8, 2002, Allegheny announced that AE, AE Supply, and AGC were in technical default under their principal credit agreements after AE Supply declined to post additional collateral in favor of several trading counterparties. These collateral calls followed the downgrading of Allegheny’s credit rating below investment grade by Moody’s. AGC was a participant in these principal credit agreements through Allegheny. During the period November 2002 through February 2003, AE, AE Supply and AGC obtained waivers of, and amended, certain covenants to these principal credit agreements. The total debt classified as current, in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived by the Creditor,” in the accompanying consolidated balance sheet related to such defaults was approximately $100.0 million as of December 31, 2002.

AGC has prepared its financial statements assuming that it will continue as going a concern. However, noncompliance with its debt covenants and the classification of certain debt as current has caused its independent auditors, PricewaterhouseCoopers LLP, to issue a modified opinion that indicates there’s substantial doubt about AGC’s ability to continue as a going concern (a “Going Concern” opinion). The financial statements do not include any adjustments that might result from the resolution of this uncertainty.

In February and March 2003, AE, AE Supply, Monongahela and West Penn entered into agreements (Borrowing Facilities) totaling $2,447.8 million with various credit providers to refinance and restructure the bulk of AE and AE Supply’s short-term debt.

The Borrowing Facilities at AE Supply provided $470.0 million of additional funding, of which $420 million was committed and is outstanding and $50.0 million is no longer committed, and refinanced $1,637.8 million of existing debt and letters of credit. The majority of AE Supply’s restructured debt is secured by substantially all of its assets. The Borrowing Facilities at AE are unsecured and refinanced $340.0 million of existing debt and letters of credit.

At December 31, 2002, AGC had $55.0 million drawn against lines of credit totaling $579.0 million in which AE Supply and AGC were participants. In connection with the Borrowing Facilities, on February 25, 2003, AE Supply provided AGC with a loan of $55.0 million in order for AGC to repay the amount due under its bank line of credit. AGC has $50 million of debentures that were due on September 1, 2003. On September 1, 2003 AGC received an equity contribution of $40.0 million from its parent companies AE Supply and Monongahela with which it used these proceeds to help retire the $50 million in debentures.

AGC had no amounts drawn against lines of credit totaling $150.0 million in which Allegheny and its regulated subsidiaries, including AGC, were participants.

Through August 2002, AGC also participated in an Allegheny internal money pool, which accommodates intercompany short-term borrowing needs to the extent that certain of Allegheny’s subsidiaries have funds available. The money pool provides funds to approved Allegheny subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven-day commercial paper rate, as quoted by the same source, less four basis points. Because AGC’s participation in the money pool ended in August 2002, AGC had no borrowings outstanding from the money pool at December 31, 2002. AGC has SEC authorization for total short-term borrowings, from all sources, of $100.0 million. See Note 6 to the financial statements for information regarding short-term obligations.

AGC’s capital expenditures, primarily construction expenditures, for 2003 and 2004 are estimated at $9.7 million and $6.1 million, respectively.

AGC received authority from the SEC to pay common dividends from time to time through December 31, 2001, out of capital to the extent permitted under applicable corporation law and any applicable financing agreements which restrict distributions to shareholders. Due to the nature of being a single asset company with declining capital needs, AGC systematically reduces capitalization each year as its asset depreciates. This has resulted in the payment of dividends in excess of current earnings out of other paid-in capital and the reduction of retained earnings to zero. The approval granted to AGC expired on December 31, 2001. AGC filed a request with the SEC on March 22, 2002, to obtain approval to continue the practice of paying dividends out of excess earnings. The SEC issued an order authorizing AGC to pay dividends out of capital surplus through December 31, 2005.

Internal generation of cash, consisting of cash flows from operations reduced by common dividends, was a $11.3 million source of cash in 2002, compared to a $7.4 million use of cash in 2001.

Cash flows from operations for 2002 increased $.7 million from 2001 reflecting decreased payments for income taxes, largely offset by changes in other assets and liabilities. Cash flows used in investing decreased

$.8 million for 2002 due to decreased construction expenditures. Cash flows used in financing decreased $.7 million for 2002 due to reduced dividends paid on common stock largely offset by increased net repayments of current debt.

Cash flows from operations for 2001 decreased $7.3 million from 2000 primarily due to increased payments for income taxes. Cash flows used in investing increased $1.2 million for 2001 due to increased construction expenditures. Cash flows used in financing decreased $8.5 million for 2001 due to increased current debt.

Debt: AGC has debentures with total principal balances (excluding any discount on the debt) of $150 million outstanding at December 31, 2002; a total of $50.0 million of the debt is classified as long-term debt due within one year with a due date of September 2003. The remaining $100.0 million has been reclassified to current debt due to the reclassification as previously discussed.

Short-term Debt: AGC has short-term debt representing notes payable to banks of $55.0 million at December 31, 2002. In February 2003, AE Supply loaned AGC amounts sufficient to repay the total outstanding bank loan of $55.0 million.

Effective January 1, 2003, AGC adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. See Note 12 to the Financial Statements for additional information.

AGC does not expect various other new accounting pronouncements not mentioned above that were effective in 2002 to have a material effect on AGC’s results of operations, cash flows, and financial position.

In 2002, Allegheny announced a series of initiatives to improve financial performance and respond to the challenges it faces in the current marketplace. This included Allegheny’s decision to focus on reducing risk, optimizing the value of its generating facilities, reducing the effect and amount of mark-to-market earnings, and prudently managing and protecting the value associated with the existing positions in Allegheny’s energy marketing and trading portfolio.

Allegheny remains 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. Allegheny is mandated by its Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

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

To manage Allegheny’s financial exposure to commodity price fluctuations in its energy trading, fuel procurement, power marketing, natural gas supply, and risk management activities, Allegheny enters into contracts, such as electricity and natural gas purchase and sale commitments, to hedge its risk exposure. However, Allegheny does not hedge the entire exposure of its operations from commodity price volatility for a variety of reasons, including open positions caused by counterparty terminations, as discussed below. To the extent Allegheny does not successfully hedge against commodity price volatility, its consolidated results of operations, cash flows, and consolidated financial position may be affected either favorably or unfavorably by a shift in the forward price curves and spot commodity prices.

Also, Allegheny’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 its regulated utility subsidiaries to meet their PLR obligations. Certain of 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, Allegheny’s results of operations and financial position can be favorably or unfavorably affected by a change in forward 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, Allegheny is primarily exposed to risks associated with the wholesale marketing of electricity, including the generation, fuel procurement, power marketing, and trading of electricity. Allegheny’s wholesale activities principally consist of marketing and trading over-the-counter forward contracts, and swaps 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. Allegheny’s forward contracts generally require physical delivery of electricity and natural gas. The swap contracts generally require financial settlement.

Allegheny 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).

In October 2002, Allegheny announced that AE, AE Supply, and AGC were in technical default under their principal credit agreements after Allegheny declined to post additional collateral in favor of several trading

counterparties. The request for additional collateral resulted from the downgrade of Allegheny below investment grade by Moody’s. This breach resulted in 24 trading counterparties terminating trades with Allegheny. Of these trading counterparties, Allegheny has settled with nine counterparties for a net cash inflow of $6.8 million. As of December 31, 2002, Allegheny had recorded an accounts receivable of $9.0 million for payments due from terminated trading counterparties and had recorded an accounts payable for $40.6 million due to terminated trading counterparties. Allegheny continues in settlement discussions with the remaining counterparties. Due to Allegheny’s current liquidity situation and the trade terminations, Allegheny’s sales and purchases of energy are currently not balanced in its portfolio of commodity contracts. This imbalance exposes Allegheny to significant risk resulting from the fluctuation in the market prices of electricity and natural gas.

A portion of Allegheny’s energy trading activities involves long-term structured transactions. Since March 1, 2001, Allegheny entered into certain long-term contracts as part of its energy trading activities. Because of uncertainty of future market conditions, commodity prices, and the lack of market liquidity in the long-term, Allegheny is exposed to fluctuations in future cash flows and earnings. The following contracts that extend beyond five years were added to Allegheny’s energy trading portfolio during 2002 and 2001:

In 2003, Allegheny’s exposure to variable interest rates increased. In February 2003, Allegheny announced that it and AE Supply had entered into agreements with lenders for the Borrowing Facilities totaling $2,447.8

million. The Borrowing Facilities’ interest rates are based upon a fixed spread over LIBOR. Also, the interest rates payable by AE Supply under certain parts of the Borrowing Facilities are dependent on AE Supply’s credit rating. Should AE Supply’s credit rating decline below its current rating, the rate of interest AE Supply would be required to pay would increase. A one percent increase in the variable interest under the Borrowing Facilities would increase Allegheny’s interest expense for 2003 by approximately $21.5 million.

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’s independent risk management group oversees credit risk. Allegheny 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, Allegheny may incur a loss to close-out the position. The risk of default depends on the creditworthiness of the counterparty or issuer of the instrument. Allegheny has a concentration of customers in the electric and natural gas utility and oil and natural gas exploration and production industries. These concentrations of customers may affect Allegheny’s overall exposure to credit risk, either positively or 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 positions by counterparty credit quality for Allegheny at December 31, 2002:

Included in the commodity contracts with counterparties that were investment grade are two contracts with a single counterparty, with a fair value of $1,037.5 million, or 9.7 percent of Allegheny’s total assets at December 31, 2002. These two contracts are AE Supply’s power sales to the CDWR. On February 21, 2002, the California PUC approved a rate agreement with the CDWR in order for the CDWR to issue Power Supply Revenue 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 Allegheny. In September 2002, the CDWR’s Power Supply Revenue Bonds received the following long-term ratings: Moody’s, A3; Standard and Poor’s, BBB+; and Fitch, A-. To date, all payments to Allegheny by the CDWR for purchased power have been made on time and in full. As of December 31, 2002, the CDWR has met all of its obligations under this agreement. As described under ITEM 1. BUSINESS—Recent Events, Allegheny sold the CDWR contract in September 2003.

On May 9, 2003, EPMI, a Chapter 11 debtor, commenced an adversary proceeding against AE Supply in its bankruptcy case, which is pending in the United States Bankruptcy Court for the Southern District of New York. The complaint alleges that AE Supply owes EPMI (i) $27.6 million for accounts receivable due and owing for energy delivered to the commencement of EPMI’s bankruptcy case, and (ii) $8.3 million in cash collateral previously posted by EPMI to AE Supply, less any amounts owed to AE Supply as a result of EPMI’s default under a master trading agreement entered into between the parties and certain transactions thereunder. By the complaint, EPMI also seeks certain declaratory relief, including a declaration that the arbitration provision found in the master trading agreement is unenforceable. On August 1, 2003, AE Supply filed an answer asserting affirmative defenses. AE Supply is unable to predict the outcome of this matter.

Market risk arises from the potential for changes in the value of energy related to price and volatility in the market. Allegheny 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. Allegheny evaluates commodity price risk, operational risk, and credit risk in establishing the fair value of commodity contracts.

Allegheny uses various methods to measure its exposure to market risk on a daily basis, 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 risk tolerance, determine risk targets, and monitor positions. Allegheny calculates VaR by using a variance/covariance approach, in which the option positions were taken by their delta equivalences. 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 Allegheny’s market risk exposure. As a result, the actual changes in Allegheny’s market risk sensitive instruments could differ from the calculated VaR, and such changes could have a material effect on its consolidated results of operations and financial position. In addition to VaR, Allegheny 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.

Allegheny’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. Allegheny calculates the VaR, including its generating capacity and the power sales agreements for the regulated utility subsidiaries’ PLR 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. Allegheny 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 December 31, 2002, Allegheny’s VaR was $8.2 million, including its generating capacity and power sales agreements with its regulated utility subsidiaries. This VaR is lower than Allegheny’s VaR at December 31, 2001, of $14.4 million. The change in VaR for 2002 is primarily due to a reduction in the volatility of energy prices. Allegheny also calculated VaR using the full term of all trading positions, but excluded its generating capacity and the PLR 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 December 31, 2002, this calculation yielded a VaR of $15.3 million. Allegheny’s average VaR, including its generating capacity and power sales agreements with its regulated utility subsidiaries, for 2002 was $7.4 million.

In 2002, Allegheny announced a series of initiatives to improve financial performance and respond to the challenges it faces in the current marketplace. This included AE Supply’s decision to focus on reducing risk, optimizing its generating facilities, reducing the effect and amount of mark-to-market earnings, and prudently managing and protecting the value associated with the existing positions in AE Supply’s energy marketing and trading portfolio.

AE Supply remains 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. AE Supply is mandated by its Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

Allegheny 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 independent risk management group within Allegheny actively measures and monitors the risk exposures to ensure compliance with the policy and that it is periodically reviewed.

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

Also, AE Supply’s energy trading business enters into certain contracts for the sale of electricity produced by AE Supply’s Midwest generating assets and AE Supply’s other generating facilities in excess of the power provided to AE Supply’s regulated utility subsidiaries to meet their PLR obligations. Certain of 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, AE Supply’s results of operations and financial position can be favorably or unfavorably affected by a change in forward market prices used to value the contracts, since there is not an offsetting adjustment to the recorded cost of the generating facilities.

Of AE Supply’s commodity-driven risks, AE Supply is primarily exposed to risks associated with the wholesale marketing of electricity, including the generation, fuel procurement, power marketing, and trading of electricity. Our wholesale activities principally consist of marketing and trading over-the-counter forward contracts, and swaps 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. Our forward contracts generally require physical delivery of electricity and natural gas. The swap contracts generally require financial settlement.

AE Supply 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).

counterparties. The request for additional collateral resulted from the downgrade of AE Supply below investment grade by Moody’s. This breach resulted in 24 trading counterparties terminating trades with AE Supply. Of these trading counterparties, AE Supply has settled with nine counterparties for a net cash inflow of $6.8 million. As of December 31, 2002, AE Supply had recorded an accounts receivable of $9.0 million for payments due from terminated trading counterparties and had recorded an accounts payable for $40.6 million due to terminated trading counterparties. AE Supply continues in settlement discussions with the remaining counterparties. Due to AE Supply’s current liquidity situation and the trade terminations, AE Supply’s sales and purchases of energy are currently not balanced in its portfolio of commodity contracts. This imbalance exposes AE Supply to significant risk resulting from the fluctuation in the market prices of electricity and natural gas.

A portion of AE Supply’s energy trading activities involves long-term structured transactions. Since March 1, 2001, AE Supply entered into certain long-term contracts as part of its energy trading activities. Because of uncertainty of future market conditions, commodity prices, and the lack of market liquidity in the long-term, AE Supply is exposed to fluctuations in future cash flows and earnings. The following contracts that extend beyond five years were added to AE Supply’s energy trading portfolio during 2002 and 2001:

In 2003, Allegheny and AE Supply’s exposure to variable interest rates increased. In February 2003, Allegheny announced that Allegheny and AE Supply had entered into agreements with lenders for the Borrowing

Facilities totaling $2,057.8 million. The Borrowing Facilities’ interest rates are based upon a fixed spread over LIBOR. Also, the interest rates payable by AE Supply under certain parts of the Borrowing Facilities are dependent on AE Supply’s credit rating. Should AE Supply’s credit rating decline below its current rating, the rate of interest AE Supply would be required to pay would increase. A one percent increase in the variable interest rate under the Borrowing Facilities would increase AE Supply’s interest expense for 2003 by approximately $19.0 million.

AE Supply 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, AE Supply may incur a loss to close-out the position. The risk of default depends on the creditworthiness of the counterparty or issuer of the instrument. AE Supply has a concentration of customers in the electric and natural gas utility and oil and natural gas exploration and production industries. These concentrations of customers may affect AE Supply’s overall exposure to credit risk, either positively or 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 AE Supply at December 31, 2002:

The net fair value of $1.26 billion, or 22.9 percent of AE Supply’s total assets, for “Investment grade” mainly relates to our power sales agreement with the CDWR. On February 21, 2002, the California PUC approved a rate agreement with the CDWR in order for the CDWR to issue Power Supply Revenue 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 AE Supply. In September 2002, the CDWR’s Power Supply Revenue Bonds received the following long-term ratings: Moody’s, A3; Standard and Poor’s, BBB+; and Fitch, A-. To date, all payments to AE Supply by the CDWR for purchased power have been made on time and in full. As of December 31, 2002, the CDWR has met all of its obligations under this agreement.

On May 9, 2003, EPMI, a Chapter 11 debtor, commenced an adversary proceeding against AE Supply in its bankruptcy case, which is pending in the United States Bankruptcy Court for the Southern District of New York. The complaint alleges that AE Supply owes EPMI (i) $27.6 million for accounts receivable due and owing for energy delivered to the commencement of EPMI’s bankruptcy case, and (ii) $8.3 million in cash collateral previously posted by EPMI to AE Supply, less any amounts owed to AE Supply as a result of EPMI’s default under a master trading agreement entered into between the parties and certain transactions there under. By the complaint, EPMI also seeks certain declaratory relief, including a declaration that the arbitration provision found in the master trading agreement is unenforceable. On August 1, 2003, AE Supply filed an answer asserting affirmative defenses. AE Supply is unable to predict the outcome of this matter.

Market risk arises from the potential for changes in the value of energy related to price and volatility in the market. AE Supply 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. AE Supply evaluates commodity price risk, operational risk, and credit risk in establishing the fair value of commodity contracts.

AE Supply uses various methods to measure its exposure to market risk on a daily basis, 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. AE Supply calculates VaR by using a variance/covariance approach, in which the option positions were taken by their 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 AE Supply’s market risk exposure. As a result, the actual changes in AE Supply’s market risk sensitive instruments could differ from the calculated VaR, and such changes could have a material effect on our financial results. In addition to VaR, AE Supply 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.

AE Supply’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. AE Supply’s calculates the VaR, including its generating capacity and the power sales agreements for the regulated utility subsidiaries’ PLR 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. AE Supply 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 December 31, 2002, AE Supply’s VaR was $8.2 million, including its generating capacity and power sales agreements with its regulated utility subsidiaries. This VaR is lower than AE Supply’s VaR at December 31, 2001, of $14.4 million. The change in VaR for 2002 is primarily due to a reduction in the volatility of energy prices. AE Supply also calculated VaR using the full term of all trading positions, but excluded its generating capacity and the PLR 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 December 31, 2002, this calculation yielded a VaR of $15.3 million. AE Supply’s average VaR for 2002 was $7.4 million.

Monongahela 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 and natural gas as discussed below. The interest rate risk exposure results from changes in interest rates related to variable- and fixed-rate debt. Monongahela is mandated by Allegheny’s Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

As part of Monongahela’s efforts to spur deregulation in West Virginia, Monongahela agreed to terminate its expanded net energy cost (fuel clause) effective July 1, 2000. As a result, Monongahela is subject to capped rates from a revenue standpoint without the existence of a fuel clause to offset fluctuations in the market price of fuel. In order to manage Monongahela’s financial exposure to these price fluctuations, Monongahela routinely enters into contracts, such as fuel purchase commitments, in order to reduce its risk exposure. To the extent that Monongahela purchases fuel at significantly higher prices, Monongahela’s results of operations could be adversely affected.

As a result of Monongahela’s restructuring plan in Ohio, Monongahela unbundled its rates in Ohio to reflect three separate charges—a generation (or supply) charge, a Restructuring Transition Charge, and T&D charges. The generation rates applied to customers not choosing an alternate electricity generation supplier are capped through a transition period that ends December 31, 2005.

Pursuant to agreements, AE Supply provides Monongahela with the total amount of electricity needed for those Ohio customers not choosing an alternate electricity generation supplier during the transition period. The original rate schedule for these agreements, effective through December 31, 2000, established fixed purchase prices corresponding to the capped generation rates charged to customers not electing an alternate electricity generation supplier. Thus, the cost of purchased electricity was recovered through the capped generation rates charged to customers.

Under a revised rate schedule approved by the FERC effective January 1, 2001, a portion of the electricity purchased from AE Supply for Monongahela’s Ohio jurisdiction now has a market-based pricing component that could result in higher electricity prices when market prices exceed the fixed prices (corresponding to the capped generation rates). Purchased electricity prices would never be set below the established fixed prices. The amount of electricity purchased under this rate schedule that is subject to market prices escalates each year through 2005. To the extent that Monongahela purchases electricity from AE Supply at market prices that exceed the established fixed prices, Monongahela’s results of operations could be adversely affected. In 2002 and 2001, Monongahela incurred $2.2 million and $.8 million, respectively, of additional purchased electricity costs due to the market-based pricing component of the revised rate schedule.

Potomac Edison is exposed to market risks associated with commodity prices and interest rates. The commodity price risk exposure results from market fluctuations in the price of electricity as discussed below. The interest rate risk exposure results from changes in interest rates related to variable- and fixed-rate debt. Potomac Edison is mandated by Allegheny’s Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

As a result of Potomac Edison’s restructuring plans in Maryland and Virginia, Potomac Edison unbundled its rates to reflect two separate charges—a generation (or supply) charge and T&D charges. The generation rates applied to customers not choosing an alternate electricity generation supplier are capped through specified transition periods. The transition period for Potomac Edison’s Maryland residential customers is from July 1, 2000, to December 31, 2008, and the transition period for all other Maryland customers is from July 1, 2000, to December 31, 2004. The transition period for all of Potomac Edison’s Virginia customers is from January 1, 2002, to July 1, 2007, unless the Virginia State Corporate Commission (Virginia SCC) reduces this period.

Pursuant to agreements, AE Supply provides Potomac Edison with the total amount of electricity needed for those customers not choosing an alternate electricity generation supplier during the transition periods. The original rate schedule for these agreements, effective through December 31, 2000, established fixed purchase prices corresponding to the capped generation rates charged to customers not electing an alternate electricity generation supplier. Thus, the cost of purchased electricity was recovered through the capped generation rates charged to customers.

Under a revised rate schedule approved by the Federal Energy Regulatory Commission (FERC) effective January 1, 2001, a portion of the electricity purchased from AE Supply now has a market-based pricing component that could result in higher electricity prices when market prices exceed the fixed prices (corresponding to the capped generation rates). Purchased electricity prices would never be set below the established fixed prices. The amount of electricity purchased under this rate schedule that is subject to market prices escalates each year through June 30, 2007, in Virginia and December 31, 2008, in Maryland. To the extent that Potomac Edison purchases electricity from AE Supply at market prices that exceed the established fixed prices, Potomac Edison’s results of operations could be adversely affected. In 2002 and 2001, Potomac Edison incurred $12.1 million and $3.9 million, respectively, of additional purchased electricity costs due to the market-based pricing component of the revised rate schedule.

West Penn is exposed to market risks associated with commodity prices and interest rates. The commodity price risk exposure results from market fluctuations in the price of electricity as discussed below. The interest rate risk exposure results from changes in interest rates related to variable- and fixed-rate debt. West Penn is mandated by Allegheny’s Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

As a result of West Penn’s restructuring plan, West Penn unbundled its rates to reflect three separate charges—a generation (or supply) charge, a Competitive Transition Charge (CTC), and T&D charges. The generation rates applied to customers not choosing an alternate electricity generation supplier are capped through a transition period that ends December 31, 2008.

Pursuant to agreements, AE Supply provides West Penn with the total amount of electricity needed for those customers not choosing an alternate electricity generation supplier during the transition period. The original rate schedule for these agreements, effective through December 31, 2000, established fixed purchase prices corresponding to the capped generation rates charged to customers not electing an alternate electricity generation supplier. Thus, the cost of purchased electricity was recovered through the capped generation rates charged to customers.

Under a rate schedule approved by the Federal Energy Regulatory Commission effective January 1, 2001, a portion of the electricity purchased from AE Supply now has a market-based pricing component that could result in higher electricity prices when market prices exceed the fixed prices (corresponding to the capped generation rates). Purchased electricity prices would never be set below the established fixed prices. The amount of electricity purchased under this rate schedule that is subject to market prices escalates each year through 2008. To the extent that West Penn purchases electricity from AE Supply at market prices that exceed the established fixed prices, West Penn’s results of operations could be adversely affected. In 2002 and 2001, West Penn incurred $22.5 million and $7.5 million, respectively, of additional purchased electricity costs due to the market-based pricing component of the revised rate schedule.

Allegheny Energy, Inc. (AE) and its subsidiaries’ (collectively, Allegheny) principal business segments are the Delivery and Services segment and the Generation and Marketing segment. The Delivery and Services segment primarily consists of the regulated utility subsidiaries, Monongahela Power Company (Monongahela), excluding Monongahela’s generation of electricity for its West Virginia jurisdiction, The Potomac Edison Company (Potomac Edison), and West Penn Power Company (West Penn), collectively doing business as Allegheny Power. These subsidiaries primarily operate electric and natural gas transmission and distribution systems (T&D) in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia. These subsidiaries are subject to federal and state regulation, including the Public Utility Holding Company Act of 1935 (PUHCA). In 2002, revenues from the 50 largest electric utility customers provided approximately 17.9 percent of the consolidated retail revenues.

The Delivery and Services segment also includes Allegheny Ventures, Inc. (Allegheny Ventures), an unregulated subsidiary, which invests in and develops fiber-optic and data services through its subsidiary, Allegheny Communications Connect, Inc. (ACC), and energy-related projects. These subsidiaries are also subject to federal regulation under PUHCA.

The Generation and Marketing segment consists primarily of Allegheny’s subsidiary, Allegheny Energy Supply Company, LLC (AE Supply), including Allegheny Generating Company (AGC). AE Supply is an unregulated (i.e., not subject to state rate regulation) energy company that develops, owns, operates, and controls electric generating capacity and supplies and trades energy and energy-related commodities. AGC owns and sells generating capacity to its parent companies, AE Supply and Monongahela. The Generation and Marketing segment also includes Monongahela’s generation of electricity for its West Virginia regulatory jurisdiction, which has not deregulated electric generation. The Generation and Marketing segment is subject to federal regulation, including PUHCA, but is not subject to state regulation of rates. As of December 31, 2002, the Generation and Marketing segment had 12,041 megawatts (MW) of generating capacity, which it owned or contractually controlled.

Certain amounts in the December 31, 2001, consolidated balance sheet and in the December 31, 2001, and 2000, consolidated statement of operations and consolidated statement of cash flows have been reclassified for comparative purposes. Significant accounting policies of Allegheny and its subsidiaries are summarized below.

The preparation of financial statements in conformity with generally accepted accounting principles of the United States of America (GAAP) requires Allegheny to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. On a continuous basis, Allegheny evaluates its estimates, including those related to the calculation of the fair value of commodity contracts and derivative instruments, unbilled revenues, provisions for depreciation and amortization, adverse power purchase commitments, regulatory assets, income taxes, pensions and other postretirement benefits, and contingencies related to environmental matters and litigation. Allegheny bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Allegheny’s accounting for commodity contracts, which requires some of its more significant judgments and estimates used in the preparation of its consolidated financial statements, is discussed under “Revenues” below and in Note 4. The accounting for derivative instruments is discussed in Note 9.

The consolidated financial statements reflect investments in controlled subsidiaries on a consolidated basis. The consolidated financial statements include the accounts of Allegheny and all subsidiary companies after elimination of intercompany transactions and balances and are prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of the Federal Energy Regulatory Commission (FERC) and applicable state regulatory commissions.

Revenues from the sale of electricity and natural gas to customers of the regulated utility subsidiaries are recognized in the period that the electricity and natural gas are delivered and consumed by customers, including an estimate for unbilled revenues.

Revenues from the sale of unregulated generation are recorded in the period in which the electricity is delivered and consumed by customers.

Allegheny records contracts entered into in connection with energy trading at fair value on the consolidated balance sheet, with changes in fair value recorded as a component of operating revenues on the consolidated statement of operations.

Fair values for exchange-traded instruments, principally futures and certain options, are based on actively quoted market prices. In establishing the fair value of commodity contracts that do not have quoted prices, such as physical contracts, over-the-counter options, and swaps, management uses available market data and pricing models to estimate fair values. Estimating fair values of instruments which do not have quoted market prices requires management’s judgment in determining amounts which could reasonably be expected to be received from, or paid to, a third party in settlement of the instruments. These amounts could be materially different from amounts that might be realized in an actual sale transaction. Fair values are subject to change in the near term and reflect management’s best estimate based on various factors.

For energy trading, Allegheny enters into physical energy commodity contracts and energy-related financial contracts. The sales and purchases made under commodity contracts for energy trading are recorded in operating revenues in accordance with Emerging Issues Task Force (EITF) Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts.”

Allegheny has netting agreements with various counterparties, which provide the right to set off amounts due from and to the counterparty. To the extent of those netting agreements, Allegheny records the fair value of commodity contract assets and liabilities and accounts receivable and accounts payable with counterparties on a net basis.

The Delivery and Services segment also constructs generating facilities for unrelated third parties. For these activities, construction revenues are recognized under the percentage of completion method, measured by the percentage of costs incurred to date to total estimated costs on a contract-by-contract basis. Revenues from all

other Delivery and Services segment activities are recorded in the period that products or services are delivered and accepted by customers.

Natural gas production revenue is recognized as income when the natural gas is extracted, delivered, and sold.

The difference between the costs of fuel, purchased energy, and certain other costs and revenues from regulated electric utility purchases from or sales to other utilities and power marketers, including transmission services, and fuel-related revenues billed to customers has historically been deferred until it is either recovered from or credited to customers under fuel and energy cost-recovery procedures in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia. With the exception of one power purchase agreement under the Public Utilities Regulatory Policies Act of 1978 (PURPA), which continues to be subject to a deferred energy cost mechanism in Maryland, effective January 1, 2001, fuel and purchased energy costs for the regulated electric utilities have been expensed as incurred as a result of the elimination of deferred energy cost mechanisms by Allegheny’s state regulatory bodies.

The difference between natural gas supply costs incurred, including the cost of natural gas transmission and transportation within the former West Virginia Power Company (WVP) territory, acquired in 1999, and natural gas cost revenues collected from customers is deferred until recovered from or credited to customers under a Purchased Gas Adjustment (PGA) clause in effect for this operation in West Virginia. Prior to November 1, 2001, the cost of natural gas for Mountaineer Gas Company (Mountaineer) was expensed as incurred. Effective November 1, 2001, Mountaineer returned to the PGA mechanism.

Costs incurred to issue debt are recorded as deferred charges on the consolidated balance sheet. These costs are amortized on a straight-line basis over the lives of the related debt securities, which does not differ materially from the effective interest method.

Regulated property, plant, and equipment are stated at original cost. Costs include direct labor and materials; allowance for funds used during construction (AFUDC) on regulated property for which construction work in progress is not included in rate base; and indirect costs such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes, and other benefits related to employees engaged in construction.

Upon retirement, the cost of depreciable regulated property, plus removal costs less salvage, are charged to accumulated depreciation by the regulated subsidiaries in accordance with the provisions of the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”

Unregulated property, plant, and equipment are stated at original cost. West Penn, Potomac Edison, and Monongahela’s Ohio and FERC jurisdictional generating assets were transferred to AE Supply at book value from 1999 through June 2001. For the unregulated subsidiaries, gains or losses on asset dispositions are included in the determination of net income.

Allegheny capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over the expected useful life of the software beginning upon a project’s completion.

Allegheny accounts for its natural gas exploration and production activities under the successful efforts method of accounting. The cost of Monongahela’s natural gas wells is being depleted using the units of production method.

Allegheny adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. Long-lived assets owned by Allegheny are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, resulting in the asset being written down to its fair value. The fair value is determined by the use of quoted market prices, appraisals, or the use of other valuation techniques, such as expected discounted future cash flows. See Note 6 for information related to asset impairment charges recorded during 2002.

Allowance for Funds Used During Construction (AFUDC) and Capitalized Interest

AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is recognized by the regulated subsidiaries as a cost of regulated property, plant, and equipment. Rates used by the regulated subsidiaries for computing AFUDC in 2002, 2001, and 2000 averaged 10.59 percent, 7.36 percent, and 7.91 percent, respectively.

For unregulated construction, Allegheny capitalizes interest costs in accordance with SFAS No. 34, “Capitalization of Interest Costs.” The interest capitalization rates in 2002, 2001, and 2000 were 6.22 percent, 6.37 percent, and 5.75 percent, respectively. Allegheny capitalized $13.6 million of interest during 2002.

Depreciation expense is determined generally on a straight-line method based on the estimated service lives of depreciable properties and amounted to approximately 2.8 percent of average depreciable property in 2002, 2.6 percent in 2001, and 2.9 percent in 2000. Estimated service lives for generation property range from four to 50 years, for T&D property range from seven to 58 years, and, for all other property, range from two to 60 years. The Delivery and Service segment’s depreciation expense was $126.4 million, $130.5 million, and $118.8 million for 2002, 2001, and 2000, respectively. The Generation and Marketing segment’s depreciation expense was $149.5 million, $126.7 million, and $110.7 million for 2002, 2001, and 2000, respectively. Depreciation expense for regulated property is provided for under currently enacted regulatory rates.

Maintenance expenses represent costs incurred to maintain the power stations, the electric and natural gas T&D systems, and general plant and reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage to the T&D system. Maintenance costs are expensed in the year incurred.

Allegheny records the acquisition cost in excess of fair value of tangible and intangible assets acquired, less liabilities assumed, as goodwill. See Note 5 for information regarding Allegheny’s recent acquisitions. Effective January 1, 2002, with the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets,” Allegheny ceased amortization of goodwill and now tests goodwill for impairment at least annually. SFAS No. 142 also requires that other intangible assets with indefinite lives not be amortized, but, rather, be tested for impairment at least annually. Other intangible assets with finite lives are to be amortized over their useful lives and tested for impairment when events or circumstances warrant. See Note 7 for additional information regarding Allegheny’s adoption of SFAS No. 142 and ongoing accounting for goodwill and other intangible assets.

Benefit plans’ investments primarily represent the estimated cash surrender values of purchased life insurance on qualifying management employees under executive life insurance and supplemental executive retirement plans.

Unregulated investments represent equity investments in and loans to unconsolidated entities. Equity investments are recorded using the equity method of accounting if the investment gives Allegheny the ability to exercise significant influence, but not control, over the investee. The income or loss from unregulated investments is recorded in other income and expenses in the consolidated statement of operations.

For purposes of the consolidated statement of cash flows and balance sheet, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, and repurchase agreements, are considered to be the equivalent of cash.

In accordance with SFAS No. 71, Allegheny’s consolidated financial statements include certain assets and liabilities resulting from cost-based ratemaking regulation.

Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the financial statements and tax basis of assets and liabilities computed using the most current tax rates. See Note 15 for additional information regarding income taxes.

Allegheny has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant, and equipment.

Allegheny has a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on each employee’s years of service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security

Act of 1974 (ERISA) and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities, short-term investments, and insurance contracts.

Allegheny’s subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993. The funding policy is to contribute the maximum amount that can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self-insured.

Allegheny maintains a stock-based employee compensation plan, which is described in greater detail in Note 18. Allegheny accounts for this plan under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. No stock-based employee compensation expense has been recognized in consolidated net income, as all options granted under the plan had an exercise price that equaled the market price of the underlying stock on the date of the grant. Allegheny adopted the disclosure provisions of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure, an Amendment of SFAS No. 123,” effective for financial statements for fiscal years ending after December 15, 2002. The following table illustrates the effect on consolidated net income and earnings per share as if Allegheny had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation.

Other comprehensive income, consisting of unrealized gains and losses, net of income taxes, from the temporary decline in the fair value of available-for-sale securities, cash flow hedges, and the adjustment for the minimum pension liability is presented in the consolidated financial statements as required by SFAS No. 130, “Reporting Comprehensive Income.”

After Allegheny filed its quarterly report on Form 10-Q for the period ended June 30, 2002, Allegheny identified a miscalculation in its business segment information. Following the discovery of this miscalculation, and in light of Allegheny’s prior restatements of reports filed with the Securities and Exchange Commission (SEC), Allegheny initiated a comprehensive review of its financial processes, records, and internal controls to ensure that its current and prior financial statements are fairly presented in accordance with GAAP.

for certain classification adjustments to the consolidated balance sheet as of December 31, 2001, Allegheny’s management concluded that these errors were not material, either individually or in the aggregate, to the current year or any prior years’ financial statements. Accordingly, prior year financial statements have not been restated, except for the consolidated balance sheet as of December 31, 2001. These adjustments, which increase the 2002 net loss, aggregate approximately $20.1 million, net of income taxes, and have been recorded in the first quarter of 2002 as an increase to the loss. The nature and amounts of these adjustments are primarily as follows:

In addition, Allegheny identified certain adjustments affecting only years prior to the year 2002 primarily as follows:

The years to which the (charges) income, net of income taxes, relate are as follows:

Had the adjustments listed above been recorded in the appropriate years, the following table demonstrates the effect on both consolidated (loss) income before extraordinary charge and cumulative effect of accounting change, and consolidated net (loss) income:

Allegheny’s management concluded that the consolidated balance sheet as of December 31, 2001, required restatement to correct amounts previously reported as commodity contract assets and liabilities and the related deferred income taxes. At December 31, 2001, commodity contracts were incorrectly classified between assets and liabilities due to errors in Allegheny’s process for identifying those commodity contracts that included the right of setoff. As a result, the amounts previously reported by Allegheny as commodity contract assets and liabilities did not comply with the requirements of FASB Interpretation No. (FIN) 39, “Offsetting of Amounts Related to Certain Contracts,” since the amounts did not accurately reflect Allegheny’s legal right, by contract or otherwise, to offset the commodity contract assets and liabilities. In order to correct the errors, Allegheny has restated the following assets and liabilities as of December 31, 2001 after correcting its process for identifying commodity contracts that include the right of setoff.

The balance sheet reclassification restatement displayed above had no impact on 2001 consolidated shareholders’ equity, cash flows, or the results of operations.

While certain changes in policies and procedures have been instituted, additional changes are needed to improve the internal control structure of Allegheny.

Regarding its internal controls for energy trading operations, Allegheny has revised its corporate energy risk policy to incorporate the best practices as defined by the Committee of Chief Risk Officers (CCRO) in its white papers issued in November 2002. As a result, the role and responsibilities of Allegheny’s corporate risk management function, which is independent from its energy trading operations, have been significantly expanded, to include the responsibility for determining the fair value of energy trading positions. Allegheny has established clear separation of duties for front, middle, and back office activities. Allegheny also reduced transaction and exposure limits for its energy trading operations.

Allegheny’s management, Audit Committee, and Board of Directors are fully committed to the resolution of Allegheny’s internal control deficiencies. Ultimate resolution of the deficiencies will include changing the culture of the accounting function to focus on accountability and the strict, timely adherence to a set of sound internal control policies and procedures. Management has commenced or is undertaking the following corrective actions in order to achieve an immediate improvement in the controls environment:

In October 2002, Allegheny announced that AE, AE Supply, and AGC were in technical default under their principal credit agreements after AE Supply declined to post additional collateral in favor of several trading counterparties. The request for additional collateral resulted from a downgrade in Allegheny’s credit rating below investment grade by Moody’s. During the period November 2002 through February 2003, AE, AE Supply and AGC obtained waivers of, and amended, certain covenants to these principal credit facilities. The total debt classified as current, in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived by the Creditor,” in the accompanying consolidated balance sheet related to such defaults was approximately $2,110.4 million as of December 31, 2002. See the discussion below concerning other defaults on additional long-term debt that also resulted in the classification of that debt as current.

Allegheny prepared its financial statements assuming that it will continue as a going concern. However, Allegheny’s noncompliance with certain of its reporting obligations under certain of its debt covenants and the resultant classification of certain debt as current has caused its independent auditors, PricewaterhouseCoopers LLP, to issue a modified opinion that indicates there is substantial doubt about Allegheny’s ability to continue as a going concern (a “Going Concern” opinion). The financial statements do not include any adjustments that might result from the resolution of this uncertainty. Management’s plans with respect to this matter are discussed below.

On February 25, 2003, AE, AE Supply, Monongahela, and West Penn entered into agreements (Borrowing Facilities) totaling $2,437.8 million with various credit providers to refinance and restructure the bulk of AE and AE Supply’s short-term debt. In addition, Monongahela entered into an agreement on March 13, 2003, to restructure an additional $10.0 million of indebtedness. See Note 27 for additional details regarding the Borrowing Facilities.

The Borrowing Facilities at AE Supply, which total $2,057.8 million, excluding $50.0 million that is no longer committed, require repayments of $250.0 million in the fourth quarter of 2003, $200.0 million in the third quarter of 2004, $150.0 million in the fourth quarter of 2004, $1,077.8 million in the second quarter of 2005, and $380.0 million in the fourth quarter of 2007. The Borrowing Facilities at AE, Monongahela, and West Penn, which total $315.0 million, excluding $25.0 million that was repaid in July 2003, require repayments of approximately $7.5 million each quarter, starting with the first quarter of 2003 and continuing through the first quarter of 2005, approximately $10 million in the fourth quarter of 2003, and $237.5 million in the second quarter of 2005.

Bonds and Debentures. The covenant breach of the First Mortgage Bonds and Debentures is deemed a default of such indebtedness, as well as a default of indebtedness subject to cross-acceleration with such First Mortgage Bonds and Debentures, including certain Pollution Control Bonds and other debt, for Allegheny’s financial reporting purposes in accordance with EITF Issue No. 86-30. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was approximately $1,551.8 million as of December 31, 2002. To date, the debt holders have not provided Allegheny with any notices of default under the agreements. Such notices, if received, would allow Allegheny either 30 or 60 days to cure its noncompliance before the debt holders could accelerate the due dates of the debt obligations.

Management plans to file its Annual Report on Form 10-K for the period ended December 31, 2003 on a timely basis.

As of December 31, 2002, $90.0 million was outstanding under two Mountaineer Note Purchase Agreements. These Note Purchase Agreements contain covenants that required Mountaineer to deliver annual financial statements, an audited 2002 annual report, and certain certificates to the noteholders by March 31, 2003. Mountaineer did not deliver these items to the noteholders by March 31, 2003. Effective July 23, 2003, Mountaineer obtained waivers extending the covenant due dates until September 30, 2003, for the 2002 annual financial statements and audited annual report. Also, Mountaineer has obtained waivers until October 31, 2003, and December 1, 2003, for the delivery of its unaudited financial statements to the noteholders for the first and second quarters of 2003, respectively.

In 2003, Allegheny’s cash flows are expected to be adequate to meet all of its payment obligations under the debt agreements, including the outstanding notes, and to fund other working capital needs. Allegheny’s projected cash flows from operations are not expected to be sufficient in 2004 to meet all of its payment obligations under its debt agreements, including the outstanding notes, or to fund its other liquidity needs. Allegheny is actively pursuing a liquidity strategy in an effort to obtain cash to meet its payment obligations. Allegheny cannot assure that its liquidity strategy will provide liquidity in a manner or time frame to meet its payment obligations under the Borrowing Facilities.

Upon re-examining its business model and structure, Allegheny has adopted a long-term strategy of focusing on the core generation and T&D businesses in which it has been historically engaged. Allegheny will seek, consistent with regulatory constraints, to manage its business lines as an integrated whole. Implementing this strategy will be a significant challenge, in part, because of the continuing legacy of past transactions that have negatively impacted Allegheny’s operations and financial condition.

Allegheny has taken a number of recent actions to improve its financial condition. These steps include substantial senior management changes; completion of key financing transactions, including the refinancing of principal credit facilities (as discussed above); exiting from Western United States energy markets; refocusing trading activities; asset sales; restructuring and cost-reducing initiatives; and improving internal controls and reporting.

Private Placement: On July 24, 2003, Allegheny obtained $291 million ($275 million after deducting various fees and placement agents’ commissions) from the issuance to a special purpose finance subsidiary of AE, Allegheny Capital Trust I (Capital Trust), of units comprised of $300 million principal amount of 11⁷/8 percent Notes due 2008 and warrants for the purchase of up to 25 million shares of AE’s common stock, exercisable at $12 per share. The warrants are mandatorily exercisable if AE’s common stock price equals or exceeds $15 per share over a specified averaging period occurring after June 15, 2006. The warrants are stapled to the notes and may be exercised only through the tender of the notes. The finance subsidiary obtained proceeds

required to purchase the units by issuing $300 million liquidation amount of its 11⁷/8 percent Mandatorily-Convertible Trust Preferred Securities to investors in a private placement. The holder of a preferred security is entitled to distributions on a corresponding principal amount of notes and may direct the exercise of warrants stapled to the notes in order to convert the preferred securities into AE common stock. AE guarantees Capital Trust’s payment obligations under the preferred securities. In accordance with GAAP, Allegheny’s consolidated balance sheet will reflect the notes as long-term debt. The notes and AE’s guarantee of Capital Trust’s payment obligations are subordinated only to indebtedness arising under the agreements governing certain of AE’s indebtedness under the Borrowing Facilities.

Renegotiation and Sale of CDWR Contract. In June 2003, AE Supply entered into a settlement agreement with the State of California to resolve the state’s litigation regarding its power supply contracts with the CDWR. The terms of the settlement reduced the volume of power to be delivered from 2005-2011 and reduced the sale price of off-peak power to be delivered from 2004-2011, which in turn substantially reduced the value of the contract. (See Note 26 to the consolidated financial statements under “Other Litigation-CDWR” for additional information). On September 15, 2003, Allegheny closed the sale of the CDWR contract and associated hedge transactions, to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc., for approximately $354 million. Allegheny has applied $214 million of the sale proceeds to required payments under agreements entered into to terminate tolling agreements with Williams Energy Marketing and Trading Company (Williams) and Las Vegas Cogeneration II (LV Cogen), a unit of Black Hills Corporation, as described below. Allegheny will apply an additional $28 million of the proceeds to make required payments in March and September of 2004 under the agreement with Williams. Approximately $26 million will be held in a pledged account for the benefit of AE Supply’s creditors. This arrangement is intended to enhance AE Supply’s ability to refinance certain secured borrowings. Approximately $71 million of the sale proceeds were placed in escrow for the benefit of J. Aron & Company, pending Allegheny’s fulfillment of certain post-closing requirements. When the escrowed funds are released, approximately $50 million will be added to the pledged account and AE Supply will receive the balance. The remaining $15 million of sale proceeds will be used to partially offset certain of the hedges related to the CDWR contract and to pay fees and expenses associated with the transaction.

Termination of LV Cogen Toll. In mid-September, 2003, AE Supply terminated its 222 MW tolling agreement with LV Cogen. Allegheny made a $114 million termination payment to LV Cogen after the closing of the sale of the CDWR contract.

As of December 31, 2002, the fair value of the CDWR contract, and related hedges that were sold to J. Aron & Company, plus the Williams and LV Cogen tolling agreements, was $554.5 million. From January 1, 2003, through the date that these contracts were either sold or agreements were reached to terminate the contracts, the aggregate fair value of the contracts decreased by approximately $462.7 million to $91.8 million. As a result of the sale of the CDWR contract and related hedges and the terminations of the Williams and LV Cogen tolling agreements, Allegheny incurred a net loss of approximately $50.4 million, before income taxes, in the third

quarter of 2003. This loss was determined excluding the approximately approximately $70.8 million of sale proceeds that were placed in escrow pending Allegheny’s fulfillment of certain post-closing requirements. Allegheny expects to meet these requirements in the fourth quarter of 2003, at which time the net loss would be revised from approximately $50.4 million, before income taxes, to a net gain of approximately $20.4 million, before income taxes.

After completing these major transactions, Allegheny’s remaining trading exposures to the Western U.S. market will consist of several shorter-term trades that hedged the CDWR contract and several long-term hedges of the LV Cogen tolling agreement. Allegheny continues to seek to unwind these remaining positions.

Asset Sales: In 2002, Allegheny announced that it was considering asset sales as part of an overall strategy to address its liquidity requirements. Allegheny has achieved the sale of its most significant assets with a nexus to the Western United States Allegheny has also closed the sale of its interest in the Conemaugh Generating Station, as described below. Allegheny continues to consider the sale of additional assets, especially non-core assets.

Land Sales. Effective February 14, 2002, West Penn, through its subsidiary West Virginia Power and Transmission Company, sold 12,000 acres of land in Canaan Valley, W.Va., to the U.S. Fish & Wildlife Service for $16 million. Effective December 18, 2002, it also sold a 2,468-acre track of land for $6.9 million and made a charitable contribution of a 740 acre tract in Canaan Valley, W.Va., to Canaan Valley Institute.

Restructuring and Cost-Reducing Initiatives: Allegheny has taken several actions to align its operations with its strategy and reduce its cost structure.

Elimination of Preemptive Rights. On March 14, 2003, AE’s common stockholders approved an amendment to AE’s articles of incorporation eliminating common stockholders’ preemptive rights. The elimination of preemptive rights removes an obstacle to AE’s ability to privately place equity or convertible securities.

Improving Internal Controls and Reporting: Comprehensive Accounting Review. Commencing in the third quarter of 2002, Allegheny undertook a comprehensive and extended review of its financial information and internal controls and procedures. This review included continuous efforts by Allegheny’s top management and directors and extensive involvement of independent auditors and other outside service firms. Allegheny continues to address its controls environment and reporting procedures, as well as its SEC filing and other outstanding reporting obligations. See Item 14, “Controls and Procedures,” for a detailed discussion.

Associated Risks: There are many attendant risks, both with Allegheny’s current liquidity situation and the measures that have been undertaken to remedy the situation in the short-term. These risks can be viewed as liquidity risks associated with the Borrowing Facilities, asset sales risks, and risks associated with the restructuring.

Liquidity Risks Associated with the Borrowing Facilities: These risks would include increased interest rate risk and additional borrowing costs. Also, required prepayments under the Borrowing Facilities will absorb a large portion of future estimated cash flows and will limit Allegheny’s ability to raise capital for purposes other than debt repayment.

Asset Sales Risks: If asset sales do occur, it is likely that they would not be at terms as favorable as the market conditions existing when the assets were originally acquired. This situation could expose Allegheny to a loss in value on those assets.

Restructuring Risks: In association with the workforce reductions, winding-down and relocation of the energy trading operations, and the cancellation of construction projects, Allegheny is faced with the risk of losing experienced personnel, diverting management resources away from continuing operations, and failing to realize anticipated cost reductions.

fundamental power generation and delivery businesses. Should the above actions not be accomplished, or should they prove inadequate, Allegheny will have to consider additional or other measures.

On March 16, 2001, AE Supply acquired an energy trading business. This acquisition increased the volume and scope of AE Supply’s energy commodity marketing and trading activities. The activities of the acquired business included the marketing and trading of electricity, natural gas, oil, coal, 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). It also included the use of option contracts for the purchase and sale of electricity at fixed prices in the future.

A portion of Allegheny’s energy trading activities involves long-term structured transactions. Since January 1, 2001, Allegheny has acquired or entered into certain long-term contracts as part of its energy trading activities. The following contracts that extend beyond five years were added to Allegheny’s energy trading portfolio during 2001 and 2002.

Allegheny records the contracts used in AE Supply’s wholesale marketing 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 operating 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. 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.

Allegheny has contracts that are unique due to their long-term nature and terms and are valued using proprietary pricing models. Inputs to the models include estimated forward natural gas and power prices, interest rates, estimates of market volatility for natural gas and power prices, and the correlation of natural gas and power 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 Allegheny’s financial position and results of operations if the judgments and assumptions underlying those models’ inputs prove to be wrong or inaccurate.

The fair value 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 FASB Interpretation No. 39. At December 31, 2002, the fair value of the energy trading commodity contract assets and liabilities was $1,211.5 million and $781.8 million, respectively. At December 31, 2001, the fair value of the energy trading commodity contract assets and liabilities was $1,529.3 million and $768.9 million, respectively.

Net unrealized losses of $358.3 million, before income taxes, were recorded in operating revenues to reflect the change in fair value of the energy trading commodity contracts for 2002. During the third quarter of 2002, Allegheny announced a restructuring of its energy trading activities as a result of depressed market conditions and various other factors that have negatively affected the merchant energy business, including Allegheny’s energy trading activities. Allegheny is significantly reducing its reliance on the wholesale energy trading business primarily by restricting activities to an asset-backed trading strategy using its low-cost generating assets located in the Mid-Atlantic and Midwest. As a result, Allegheny’s trading activities will focus on lowering risk, optimizing the value of its generating assets, improving cash flows, and reducing the effect of mark-to-market earnings.

During the fourth quarter of 2002, the value of Allegheny’s portfolio of energy trading contracts was reduced by an additional $216.4 million, before income taxes. This reduction in value resulted from a decrease in the liquidity and volatility of the energy markets in the Western United States and a decrease in Allegheny’s liquidity, which restricted its ability to extract value from the portfolio in the short-term. This decrease in market liquidity and volatility primarily affected the fair value of Allegheny’s contractual right to call up to 1,000 MW of generation in southern California and the agreement with LV Cogen for 222 MW of generating capacity.

Net unrealized gains of $608.3 million and $8.4 million, before income taxes, were recorded in operating revenues to reflect the change in fair value of the energy trading commodity contracts for 2001 and 2000, respectively.

As of December 31, 2002, the fair value of Allegheny’s commodity contracts with the CDWR of $1,037.5 million was approximately 9.8 percent of Allegheny’s total assets. As of December 31, 2001, the fair value of Allegheny’s commodity contracts with the CDWR of $1,320.9 million was approximately 11.9 percent of Allegheny’s total assets.

In June 2002, the EITF reached a consensus on Issue No. 02-3 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 was applicable to financial statements for periods ending after July 15, 2002. During 2002, Allegheny modified its reporting as a result of the EITF consensus to reflect the revenues from energy trading activities net of the cost of purchased energy and transmission related to contracts that require physical delivery. In addition, amounts for 2001 and 2000 were adjusted for comparability to reflect the adoption of the EITF consensus. As a result, Allegheny’s 2001 and 2000 operating revenues and cost of revenues are lower than previously reported, with no effect on consolidated net revenues or net income.

The following table provides a reconciliation of the impact on previously reported amounts of operating revenues and cost of revenues as a result of the application of EITF Issue No. 02-3 (in millions):

The EITF also reached consensus on other related items, which will have the following effects on Allegheny:

The implementation of EITF Issue No. 02-3 will result in Allegheny recording a cumulative effect of an accounting change of approximately $11.9 million, net of income taxes ($19.7 million, before income taxes) in the first quarter of 2003. This charge will represent the fair value of those contracts previously accounted for under EITF Issue No. 98-10 that no longer qualify for mark-to-market accounting.

In June 2003, AE Supply completed the sale of its 83-MW share of the coal-fired Conemaugh Generating Station to UGI Development Company, an indirect, wholly-owned subsidiary of UGI Corp., for approximately $46.3 million in cash and a contingent amount of $5.0 million. AE Supply could receive this contingent amount in full, in part, or not at all, depending upon AE Supply’s performance of certain post-closing obligations. The sale will result in an estimated loss for AE Supply of approximately $29.0 million, before income taxes, which has been calculated excluding the contingent amount.

On November 1, 2001, Allegheny Ventures acquired Fellon-McCord, an energy consulting and management services company, and Alliance Energy Services, a provider of natural gas and other energy-related services to large commercial and industrial customers. Allegheny, which accounted for this transaction as a purchase, completed this acquisition for $30.8 million in cash, including direct costs of the acquisition, plus a maximum of $18.7 million in contingent consideration to be paid over a three-year period starting from the acquisition date. This $18.7 million in contingent consideration was recorded in December 2002 and paid on January 2, 2003, subject to change of control provisions in the original acquisition agreement (see discussion below regarding the sale of Fellon-McCord and Alliance Energy Services in December 2002). Taking into account purchase price adjustments made in 2002 and the contingent consideration recorded in December 2002, Allegheny recorded $1.2 million as the fair value of net assets acquired and $48.3 million as the excess of cost over net assets acquired (goodwill). Pursuant to a participation agreement entered into as part of the acquisition of Mountaineer, on March 1, 2002, Allegheny Ventures sold a 20-percent indirect interest in Alliance Energy Services to Energy Corporation of America (ECA). Effective December 31, 2002, Allegheny Ventures sold Fellon-McCord and Alliance Energy Services to a third party for $21.8 million, $21.1 million of which was in the form of a note receivable settled in cash on January 2, 2003, and $0.7 million of which is to be received in the future. Allegheny recorded a loss on this sale of $31.5 million, before minority interest and income taxes, ($18.8 million, net of income taxes). In compliance with SFAS No. 142, the goodwill arising from the acquisition of Fellon-McCord and Alliance Energy Services was not amortized.

On May 3, 2001, AE Supply completed the acquisition of 1,710 MW of natural gas-fired generating capacity in the Midwest (Midwest Assets). The $1.1-billion purchase price was financed with short-term debt of $550.0 million and a portion of the proceeds from AE’s common stock offering on May 2, 2001.

On March 16, 2001, AE Supply acquired Merrill Lynch and Co., Inc.’s (Merrill Lynch) energy commodity marketing and trading unit for $489.2 million plus the issuance of a nearly two-percent equity membership interest in AE Supply. The acquired business conducts AE Supply’s wholesale marketing, energy trading, fuel procurement, and risk management activities.

The acquisition from Merrill Lynch included the following: the majority of the existing energy trading contracts of the energy trading business; employees engaged in energy trading activities that accepted employment with AE Supply; rights to certain intellectual property; memberships in exchanges and clearinghouses; and other tangible property.

The identifiable assets acquired were recorded at estimated fair values at the date of acquisition. Consideration paid and assets acquired were as follows:

The acquisition was recorded using the purchase method of accounting and, accordingly, the consolidated statement of operations includes its operating results beginning March 16, 2001. From March 16, 2001, to December 31, 2001, the goodwill was amortized by the straight-line method using a 15-year amortization period.

On August 18, 2000, Monongahela completed the purchase of Mountaineer, a natural gas sales and T&D company serving southern West Virginia and the northern and eastern panhandles of West Virginia, from ECA for approximately $325.7 million, including the assumption of $100.1 million of existing long-term debt. The acquisition included the assets of Mountaineer Gas Services, Inc. (MGS) which operates natural gas-producing properties, natural gas-gathering facilities, and intrastate transmission pipelines. The acquisition increased Allegheny’s natural gas customers in West Virginia by approximately 200,000 in a region where Allegheny already provides energy services.

The acquisition has been recorded using the purchase method of accounting. Since the assets and liabilities acquired relate to a regulated business, their fair values were deemed to be equivalent to their net book values. The table below shows the allocation of the purchase price to assets and liabilities acquired:

Until December 31, 2001, Allegheny amortized the goodwill for the Mountaineer acquisition on a straight-line basis over 40 years.

Effective January 1, 2002, Allegheny adopted SFAS No. 142 and, accordingly, ceased the amortization of goodwill and accounted for goodwill on an impairment-only approach. See Note 7 for additional information regarding Allegheny’s adoption of, and ongoing accounting related to, SFAS No. 142, including the write-off of goodwill associated with the sale of Fellon-McCord and Alliance Energy Services and the impairment of goodwill associated with the Mountaineer acquisition.

In the fourth quarter of 2002, circumstances surrounding the St. Joseph generating facility, a 630-MW merchant power plant under construction, indicated that the carrying amount of the facility would not be recoverable through operations. Allegheny, along with AE Supply, determined that the completion of the construction of the St. Joseph’s generating facility was not possible given their liquidity constraints and, therefore, could not proceed with the construction. AE Supply terminated construction of the St. Joseph’s generating facility and recorded an impairment charge, in accordance with SFAS No. 144, of $192.0 million, before income taxes ($118.4 million, net of income taxes). This impairment charge included amounts to record closure and cancellation costs associated with the facility.

In 2002, AE Supply cancelled the planned construction and investment in a planned 79-MW barge-mounted generation project, a planned 1,080-MW natural gas-fired generation facility, and certain other early-stage development generation projects. In accordance with SFAS No. 144, AE Supply recorded impairment charges with respect to these projects, as the carrying amounts of each project were determined not to be recoverable through operations. The impairment charges were the result of the write-down of the projects to their estimated fair values and the recording of the estimated costs to cancel the projects. The impairment charges associated with these generation projects were approximately $52.0 million, before income taxes ($30.8 million, net of income taxes).

The estimated fair values of these generation projects were determined using discounted future projected cash flows of the projects, as well as indications from unrelated third parties regarding the value of the projects. The total impairment charges related to cancelled generation projects of $244.0 million, before income taxes ($149.2 million, net of income taxes) are recorded in “Operation expense” on the consolidated statement of operations.

In 2002, circumstances surrounding several unregulated investments indicated that their carrying amounts may not be recoverable. Therefore, in accordance with SFAS No. 144, an impairment charge of $44.7 million, before income taxes ($26.5 million, net of income taxes) was recorded to write-off the unregulated investments. The impairment charges on these investments are recorded in “Other income and expenses” on the consolidated statement of operations.

On January 1, 2002, Allegheny adopted SFAS No. 141, “Business Combinations,” and SFAS No. 142. 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 Allegheny’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, Allegheny 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 Allegheny, SFAS No. 142 transitional provisions required Allegheny to test its goodwill for impairment as of January 1, 2002, and recognize any transitional goodwill impairment loss as the cumulative effect of a change in accounting principle. Allegheny completed its transitional goodwill impairment test, using a discounted cash flow methodology to determine the estimated fair value of its reporting units, and recorded an impairment loss of $130.5 million, net of income taxes ($210.1 million, before income taxes), all of which related to the Delivery and Services segment.

The transitional goodwill impairment loss consists of $170.0 million related to Allegheny’s acquisition of Mountaineer in 2000, $25.0 million related to Allegheny’s acquisition of WVP in 1999, and $15.1 million of other regulated utility goodwill related to activity recorded prior to 1966. The impairment amounts resulted from factors that are unique to these rate regulated entities and the ratemaking process, including the fact that none of the $210.1 million of goodwill was being recovered in rates or included in rate base.

SFAS No. 142 transitional provisions also were completed with respect to Allegheny’s other intangible assets, resulting in no impairments or changes to amortizable lives.

Due to strategic changes announced by Allegheny and certain events affecting Allegheny in the third quarter of 2002, including the reduction of its wholesale energy trading activities, the cancellation of a number of generation projects, and the downgrade of Allegheny’s credit ratings by credit rating agencies, Allegheny initiated an impairment test related to the $367.3 million of goodwill associated with its Generation and Marketing segment. The impairment test used a discounted cash flow methodology to determine the fair value of the Generation and Marketing segment and indicated no impairment of goodwill. This test result reflects that Allegheny’s fleet of generating stations, comprised primarily of low-cost coal-fired steam generating stations, has a fair value in excess of the carrying value of those assets sufficient to cover the decline in value of its energy trading activities and the goodwill associated with the 2001 acquisition of the energy trading business.

As a result of Allegheny’s sale of Fellon-McCord and Alliance Energy Services in December 2002, the $48.3 million of goodwill carried on the books of these entities and reflected in Allegheny’s Delivery and Services segment was written off in December 2002 in conjunction with the recording of the sale.

The carrying amount of, and changes in, goodwill attributable to each reportable segment are as follows:

The components of other intangible assets, excluding an intangible asset of $38.6 million related to an additional minimum pension liability recorded in the fourth quarter of 2002, as discussed in Note 17, were as follows:

The decrease in the gross carrying amount and accumulated amortization of amortized natural gas retail contracts during 2002 related to the sale of Alliance Energy Services. Amortization expense for other intangible assets for 2002 and 2001 was $31.7 million and $11.8 million, respectively. Amortization expense is estimated to be $1.6 million annually for 2003 through 2007.

If the provisions of SFAS No. 142 had been applied for 2001 and 2000, consolidated income before extraordinary charge and cumulative effect of accounting change, consolidated net income, and basic and diluted earnings per share would have been as follows:

In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction and a reorganization of Allegheny’s energy trading division. For the year ended December 31, 2002, Allegheny recorded a charge for the restructuring and workforce reduction of $128.6 million, before income taxes ($77.7 million, net of income taxes). In addition, as a result of the restructuring, Allegheny recorded a charge of $7.9 million, before income taxes ($4.9 million, net of income taxes) for impairment of leasehold improvements.

Allegheny has achieved workforce reductions of approximately 10 percent primarily through a voluntary early retirement option (ERO) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits and required eligible employees to make an election. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” For the year ended December 31, 2002, approximately 600 eligible employees accepted the ERO program, resulting in a charge of $82.6 million, before income taxes ($49.5, net of income taxes). Allegheny offered a Staffing Reduction Separation Program (SRSP) for employees whose positions are being eliminated as part of the workforce reductions and severance for certain energy trading employees. The severance and other employee-related costs are accounted for in accordance with 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).” For the year ended December 31, 2002, Allegheny recorded a charge of $25.0 million, before income taxes ($15.3 million, net of income taxes) related to approximately 80 employees whose positions have been or are being eliminated. Allegheny has essentially completed these planned workforce reductions. Workforce reduction costs are recorded in “Workforce reduction expenses” on the consolidated statement of operations. The reorganization of Allegheny’s energy trading division includes the relocation of the trading operations and resulted in a charge of approximately $21.0 million, before income taxes ($12.9, net of income taxes), related to costs associated with the relocation.

The following table provides the details of Allegheny’s pre-tax expenses and liabilities related to the restructuring at December 31, 2002:

Effective January 1, 2001, Allegheny adopted SFAS No. 133, which established accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives), and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The standard requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in earnings or other comprehensive income and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

income as a change in accounting principle as provided by SFAS No. 133. AE Supply’s risk management objectives regarding these cash flow hedge contracts were as follows: 1) to provide electricity in situations where the customers’ demand for electricity exceeded Allegheny’s electric generating capacity and 2) to protect Allegheny from price volatility for electricity.

The amounts accumulated in other comprehensive income related to these contracts were reclassified to earnings during July and August of 2001, when the hedged transactions were executed. As a result, a loss of $5.0 million, before income taxes ($3.1 million, net of income tax), was reclassified to purchased energy and transmission expense from other comprehensive income during the third quarter of 2001.

On March 19, 2002, AE Supply 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. In April 2002, these contracts were settled for a loss of $1.6 million, before income taxes ($1.0 million, net of income taxes). The unrealized loss was recorded in other comprehensive income. In April 2002, AE Supply began reclassifying to earnings the amounts in accumulated other comprehensive income for these treasury lock agreements over the life of the 10-year debt. For 2002, $.1 million, before income taxes ($.1 million, net of income taxes) was reclassified from accumulated other comprehensive income to earnings.

On August 1, 2000, Allegheny issued a $165.0-million 7.75-percent fixed-rate note and a $135.0-million 7.75-percent fixed-rate note. Each note matures on August 1, 2005, and requires semi-annual interest payments on August 1 and February 1. On April 24, 2002, Allegheny entered into an interest rate swap to convert the notes’ fixed rates to variable rates for the notes’ remaining terms. Under the term of the swap, Allegheny receives interest at a fixed rate of 7.75 percent and pays interest at a variable rate equal to the three-month LIBOR plus a fixed spread. Allegheny designated the swap as a fair-value hedge of changes in the general level of market interest rates. During September 2002, the interest rate swap was terminated by Allegheny at its fair value of $11.3 million. As a result, Allegheny has discontinued its fair value hedge accounting. The increase in the carrying amount of the fixed-rate notes of $11.3 million as a result of the fair value hedge accounting is being amortized over the remaining life of the notes. For 2002, $1.5 million, before income taxes ($.9 million, net of income taxes), was amortized to the consolidated statement of operations.

On November 1, 2001, Allegheny Ventures acquired Fellon-McCord and Alliance Energy Services, which were both subsequently sold in December 2002. Alliance Energy Services was engaged in the purchase, sale, and marketing of natural gas and other energy-related services to various commercial and industrial customers across

the United States. Alliance Energy Services, on behalf of its customers, used both physical and financial derivative contracts, including forwards, NYMEX futures, options, and swaps, in order to minimize market risk associated with its purchase and sales activities. These derivative contracts were accounted for as cash flow hedges.

For 2002, an unrealized gain of $31.2 million, net of reclassifications to earnings, income taxes, and minority interest, was recorded to other comprehensive income for these contracts. For 2001, an unrealized loss of $18.9 million, net of reclassifications to earnings and income taxes, was recorded to other comprehensive income for these contracts. These hedges were highly effective during 2002 and 2001.

The consolidated statement of comprehensive income provides the components of comprehensive income for the years ended December 31, 2002, 2001, and 2000.

For 2002, Allegheny recorded a minimum pension liability of $88.1 million, before income taxes ($52.5 million, net of income taxes), of which $49.5 million, before income taxes ($29.5 million, net of a deferred income tax asset of $20 million), was included as a reduction to other comprehensive income.

Allegheny holds stocks classified as available-for-sale marketable securities in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and records unrealized holding gains and losses from the temporary decline in the fair value of available-for-sale securities in other comprehensive income. For 2002, Allegheny determined that its available-for-sale marketable securities were permanently impaired. As a result, the consolidated balance sheet does not include any value for these securities at December 31, 2002. The fair value of Allegheny’s available-for-sale securities was $.3 million and $1.4 million at December 31, 2001, and 2000, respectively. For 2002, other comprehensive loss includes net unrealized losses of $.2 million, before income taxes ($.1 million, net of income taxes), and reclassifications to earnings of $2.4 million, before income taxes ($1.5 million, net of income taxes), for impairments on stock holdings considered other than temporary. For 2001, other comprehensive income includes net unrealized losses of $3.3 million, before income taxes ($1.9 million, net of income taxes) and reclassifications to earnings of $3.3 million, before income taxes ($1.8 million, net of income taxes), for impairments on stock holdings considered other than temporary. For 2000, other comprehensive income includes net unrealized losses of $2.2 million, before income taxes ($1.3 million, net of income taxes) on available for sale securities.

For 2002, other comprehensive loss also includes net unrealized gains of $46.4 million, before minority interest and income taxes ($27.6 million, net of minority interest and income taxes), and reclassifications to earnings of net realized gains of $16.8 million, before minority interest and income taxes ($9.7 million, net of minority interest and income taxes), for a total change in other comprehensive income of $29.6 million, before minority interest and income taxes ($17.9 million, net of minority interest and income taxes), for cash flow hedges. For 2001, other comprehensive income includes net unrealized losses of $45.7 million, before income taxes ($27.7 million, net of income taxes) and reclassifications to earnings of net realized losses of $14.6 million, before income taxes ($8.9 million, net of income taxes), for a total change in other comprehensive income of $31.1 million, before income taxes ($18.8 million, net of income taxes). See Note 9 for additional details relating to Allegheny’s cash flow hedges.

Allegheny manages and evaluates its operations in two business segments: 1) Delivery and Services and 2) Generation and Marketing. Prior to the second quarter of 2002, Allegheny’s reported segments were regulated utility operations, unregulated generation operations, and other unregulated operations. Business segments have been changed to reflect current internal management reporting. Prior period segment information has been restated for comparability.

The Delivery and Services segment operates regulated electric and natural gas T&D systems. It also invests in and develops fiber and data services and energy-related projects. This segment includes the results of Allegheny Ventures, an unregulated subsidiary, which, prior to the second quarter 2002, was reported as the other unregulated operations segment.

The Generation and Marketing segment develops, owns, operates, and manages regulated and unregulated electric generating capacity. It also markets and trades electricity, natural gas, oil, coal, and other energy-related commodities using primarily over-the-counter and exchange-traded contracts. This segment includes intersegment sales to provide energy to Allegheny’s regulated subsidiaries, including sales to Monongahela for its West Virginia regulatory jurisdiction that, prior to the second quarter 2002, were reported in the regulated utility operations segment.

Allegheny accounts for intersegment sales based on cost or regulatory commission-approved tariffs or contracts.

Business segment information is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts.

See Note 14 for a discussion of the extraordinary charge, net and Notes 7 and 9 for a discussion of the cumulative effect of accounting changes, net.

On May 2, 2001, Allegheny completed a public offering of its common stock, selling a total of 14.3 million shares priced at $48.25 per share. A portion of the net proceeds of approximately $667.0 million was used to partially fund AE Supply’s acquisition of the Midwest Assets and for other corporate purposes. Of the 14.3 million shares of common stock sold, 12 million shares related to treasury stock that had been purchased by Allegheny in 1999, under Allegheny’s stock repurchase program, at an aggregate cost of $398.4 million.

Also during 2002 and 2001, Allegheny issued 1.3 million and .6 million shares of common stock for $26.7 million and $23.2 million, respectively, primarily under its Dividend Reinvestment and Stock Purchase Plan, Long-term Incentive Plan, and its Employee Stock Ownership and Savings Plan. During 2002, Allegheny repurchased 11.6 thousand shares of common stock for $.4 million that were forfeited by employees under these plans.

See Note 3, “Debt Financing and Liquidity Strategy,” for a description of the defaults under Allegheny’s current debt agreements. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was $3,662.2 million as of December 31, 2002.

Contractual maturities for debentures, notes and bonds in millions of dollars for the next five years, excluding unamortized debt discounts and premiums and terminated interest rate swaps that were accounted for as fair value hedges under SFAS No. 133, are: 2003, $253.4; 2004, $161.1; 2005, $376.4; 2006, $479.2; 2007, $628.7; and, thereafter, $2,142.0. At December 31, 2002, substantially all of the properties of Monongahela are held subject to the lien securing its first mortgage bonds. Some properties of AE Supply and Monongahela are also subject to a lien securing certain pollution control and solid waste disposal notes. See Note 27 for a discussion of the liens provided by AE Supply under the Borrowing Facilities that were entered into in February 2003.

During 2002, Allegheny made the following repayments and redemptions of debentures, notes, bonds, and QUIDS: West Penn Funding, LLC, repaid $70.3 million of transition bonds; AE Supply repaid $80.0 million of floating rate medium-term debt; West Penn redeemed $70.0 million principal amount of 8.0-percent QUIDS and repaid $33.6 million of 5.6 percent fixed-rate medium-term debt; Monongahela redeemed $25.0 million of 7.4 percent fixed-rate first mortgage bonds; Mountaineer made repayments of $3.3 million on 7.6 percent fixed-rate unsecured notes; a subsidiary of Allegheny Communications Connect (ACC) repaid $10.5 million of floating rate medium-term debt; and AE Supply and Monongahela redeemed $5.6 million of pollution control bonds per their original terms.

See Note 26, under “Leases,” for additional information regarding debt recorded on Allegheny’s consolidated balance sheet at December 31, 2002, from an operating lease transaction for a generating facility.

On November 6, 2001, Potomac Edison issued debt of $100.0 million five-percent notes due on November 1, 2006. Potomac Edison used the net proceeds from these notes, together with other corporate funds, for the following purposes: to redeem $50.0 million principal amount of Potomac Edison’s first mortgage bonds, eight-percent series due June 1, 2006, at the optional redemption price of 100 percent of their principal amount plus accrued interest to the redemption date; to redeem $45.5 million principal amount of Potomac Edison’s eight-percent QUIDS due September 30, 2025, at a redemption price of 100 percent of their principal amount plus accrued interest to the redemption date; and to add to Potomac Edison’s general funds.

On September 21, 2001, Monongahela redeemed $40.0 million of eight-percent QUIDS due June 30, 2025. On October 2, 2001, Monongahela issued debt of $300.0 million five-percent first mortgage bonds due October 1, 2006. The first mortgage bonds were used to replenish funds used to redeem the QUIDS, refinance debt that was due to mature in October 2001, refinance certain debt that carried a higher interest rate, and provide additional funds for other corporate purposes.

On June 7, 2001, ACC borrowed $10.5 million under a variable rate secured credit facility with a maturity date of June 30, 2006. The proceeds from this financing were loaned to AFN, LLC, a limited liability company of which ACC is a member, for general corporate purposes.

On March 9, 2001, AE Supply issued $400.0 million of unsecured 7.80-percent notes due 2011 to pay for a portion of the cost of acquiring an energy trading business.

In 2001, Allegheny redeemed $100.0 million of first mortgage bonds, $85.5 million of QUIDS, $100.0 million of a senior secured credit facility, and $60.2 million of transition bonds, and made repayments on unsecured notes of $10.5 million.

During 2001, Monongahela redeemed first mortgage bonds that contained a common dividend restriction clause. With this redemption, Monongahela is no longer subject to restrictions on its common dividends.

Mountaineer is restricted in its ability to declare dividends. The restriction clause requires Mountaineer to maintain a minimum net worth of at least $53.0 million.

Allegheny is restricted from paying dividends on its common stock under the Borrowing Facilities until April 2005.

Allegheny follows EITF Issue No. 97-4, “Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statement Nos. 71 and 101,” which provides that, when a rate order is issued that contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated, the entity should cease to apply SFAS No. 71 to that separable portion of its business.

As required by EITF Issue No. 97-4, Monongahela and Potomac Edison discontinued the application of SFAS No. 71 for their West Virginia jurisdiction’s electric generation operations in the first quarter of 2000 and

for their Ohio and Virginia jurisdictions’ electric generation operations in the fourth quarter of 2000. Monongahela and Potomac Edison recorded after-tax charges in 2000 of $63.1 million and $13.9 million, respectively, to reflect the unrecoverable net regulatory assets that will not be collected from customers and to record a rate stabilization obligation. This charge is classified as an extraordinary charge under the provisions of SFAS No. 101, “Accounting for the Discontinuation of Application of FASB Statement No. 71.”

On May 29, 1998, the Pennsylvania Public Utility Commission (Pennsylvania PUC) issued an order approving a transition plan for West Penn. This order was subsequently amended by a settlement agreement approved by the Pennsylvania PUC on November 19, 1998. West Penn recorded an extraordinary charge under the provisions of SFAS No. 101 in 1998 to reflect the disallowances of certain costs in the Pennsylvania PUC’s May 29, 1998, order, as revised by the Pennsylvania PUC-approved November 19, 1998, settlement agreement. This charge included an estimated amount for an adverse power purchase commitment, which reflects a commitment to purchase power at above-market prices. On December 31, 2002, Allegheny’s reserve for adverse power purchase commitments was $255.2 million, based on Allegheny’s forecast of future energy revenues and other factors.

Based on the forecast mentioned above, Allegheny’s reserve for adverse power purchase commitments decreased as follows for 2002, 2001, and 2000:

The above decreases in the reserve for adverse power purchase commitments are recorded as expense reductions in “Purchased energy and transmission” on the consolidated statement of operations. A change in the estimated energy revenues or other factors could have a material effect on the amount of the estimated reserve for adverse power purchase commitments.

As of December 31, 2002 and 2001, Allegheny had no generating assets subject to SFAS No. 71. The consolidated balance sheet includes the amounts listed below for generating assets not subject to SFAS No. 71.

In March 2003, the West Virginia Legislature passed House Bill (H.B.) 2870, which clarified the jurisdiction of the Public Service Commission of West Virginia (West Virginia PSC) over electric generating facilities in West Virginia. Concurrent with the passage of H.B. 2870, Monongahela’s outside counsel advised management that deregulation of generating assets in West Virginia was no longer probable and confirmed that the West Virginia PSC will have jurisdiction and rate authority over Monongahela’s generating assets in West

Virginia. Monongahela therefore concluded that deregulation of its West Virginia generating assets is no longer probable and the generation operations in West Virginia meet the requirements of SFAS No. 71.

Monongahela will reapply the provisions of SFAS No. 71 to its West Virginia jurisdictional generating assets in the first quarter of 2003. Monongahela currently estimates that it will recognize an extraordinary gain as a result of the reapplication of SFAS No. 71 of approximately $57.1 million, net of income taxes, primarily as the result of the elimination of its transition obligation and the reestablishment of regulatory assets related to deferred income taxes.

Potomac Edison had recorded a transition obligation on its books associated with West Virginia deregulation. Potomac Edison also will reapply the provisions of SFAS No. 71 in the first quarter of 2003 and will recognize an extraordinary gain of approximately $8.6 million, net of income taxes, as a result of the elimination of its transition obligation.

The total provision for income tax (benefit) expense is different from the amount produced by applying the federal statutory income tax rate of 35 percent to financial accounting income, as set forth below:

The provision for income taxes for the extraordinary charge and the cumulative effects of accounting changes is different from the amount produced by applying the federal statutory income tax rate of 35 percent to the gross amount, as set forth below:

Federal income tax returns through 1997 have been substantially examined by the Internal Revenue Service and settled. At December 31, the deferred income tax assets and liabilities consisted of the following:

Allegheny recorded as deferred income tax assets the effect of net operating losses, which will be realized through future operations and through the reversal of existing temporary differences. These net operating loss carryforwards expire in varying amounts through 2022.

To provide interim financing and support for outstanding commercial paper, lines of credit had been established with several banks. Allegheny and its regulated subsidiaries had fee arrangements on all of their lines of credit and no compensating balance requirements. At December 31, 2002, $1,229.9 million of the $1,300.0 million lines of credit with banks were drawn. All of the $70.1 million remaining lines of credit were unavailable to be drawn upon. At December 31, 2001, $126 million of the $865 million lines of credit with banks were drawn. Of the $739 million remaining lines of credit, $474 million was supporting commercial paper and $265

million was unused. These facilities, which were refinanced in February 2003, required the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio, as defined under the credit agreements. On October 8, 2002, Allegheny announced that AE, AE Supply, and AGC were in technical default under these facilities after AE Supply declined to post additional collateral in favor of several trading counterparties. As of December 31, 2002, Allegheny had obtained waivers and amendments for these facilities. See Note 27 for additional details regarding the Borrowing Facilities that were entered into in February 2003.

In addition to bank lines of credit, an internal money pool accommodates intercompany short-term borrowing needs, to the extent that certain of Allegheny’s subsidiaries have funds available.

Net periodic cost (income) for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents included the following components:

Approximately 12.6 percent of the above cost (income) amounts were allocated to construction work in progress, a component of property, plant, and equipment, in 2002.

The estimated discount rates and rates of compensation increases used in determining the benefit obligations at September 30, 2002, 2001, and 2000, and the expected long-term rates of return on assets in each of the years 2002, 2001, and 2000 were as follows:

For measuring obligations related to postretirement benefits other than pensions, a health care cost trend rate of 10.0 percent beginning with 2003 and grading down by .5 percent each year to an ultimate rate of 5 percent, and plan provisions that limit future medical and life insurance benefits, were assumed. Because of the assumption of plan provisions that limit future benefits, changes in the assumed health care cost trend rate would have a limited effect on the amounts displayed above. A one-percentage-point change in the assumed health care cost trend rate would have the following effects:

The amounts accrued (prepaid) at December 31, using a measurement date of September 30, included the following components:

The pension unrecognized transition asset was amortized over 14 years, beginning January 1, 1987, and the postretirement benefits other than pensions unrecognized transition obligation is being amortized over 20 years, beginning January 1, 1993.

During 2002, Allegheny recognized an additional pension liability of approximately $88.1 million, before income taxes. As a result, a $38.6 million intangible asset was recorded to reflect the amount of unrecognized

prior service costs. The remaining $49.5 million ($29.5 million, net of a deferred income tax asset of $20.0 million) was charged to other comprehensive income in accordance with SFAS No. 130.

In 2002, Allegheny recorded an adjustment to correct its accounting for SERP as discussed in Note 2. The amounts displayed in the tables above include the appropriate amount of SERP costs for 2002. The adjustment of SERP costs for years prior to 2002, which were recorded in 2002, are excluded from the 2002 amounts in these tables. The SERP obligation included in the table above as of December 31, 2002 was $20.7 million. As the SERP is an unqualified pension plan, Allegheny is not obligated to fund the SERP obligation.

Under Allegheny’s Long-term Incentive Plan, options may be granted to officers and key employees. Ten million shares of Allegheny’s common stock have been authorized for issuance under the Long-term Incentive Plan. The Long-term Incentive Plan, which was implemented during 1998, provides vesting periods of one to three years, with options remaining exercisable until 10 years from the date of grant. Options are granted at the quoted market price of Allegheny’s common shares on the date of grant. There were 1,204,671 exercisable options at December 31, 2002.

The weighted average fair value of the 2002, 2001, and 2000 options was $7.81, $8.94, and $10.24 per share, respectively. The fair values were estimated at the date of grant using the Black-Scholes option-pricing model, with the following weighted average assumptions:

A summary of the status of the stock options granted under Allegheny’s Long-term Incentive Plan as of December 31, 2002, is as follows:

Under Allegheny’s Long-term Incentive Plan (formerly the Performance Share Plan), certain officers of Allegheny and its subsidiaries may receive awards based on meeting specific shareholder and customer performance rankings. Allegheny recognized compensation (credit) expense in 2002, 2001, and 2000 of $(2.0) million, $2.0 million, and $2.6 million, respectively.

The following table provides a reconciliation of the numerators and the denominators for the basic and diluted per-share computations:

Certain of Allegheny’s regulated operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets, net of regulatory liabilities, reflected in the consolidated balance sheet at December 31 relate to:

SFAS No. 109, “Accounting for Income Taxes,” requires Allegheny’s regulated utility subsidiaries to record a deferred income tax liability for tax benefits passed through to customers when temporary differences originate. These deferred income taxes relate to temporary differences involving regulated utility property, plant, and equipment and the related provision for depreciation. Allegheny records a regulatory asset for these income taxes, since the amounts are recoverable from customers when the taxes are paid by Allegheny over the remaining depreciable lives of the property, plant, and equipment. Since the deferred income tax liability recorded under SFAS No. 109 represents a non-cash item, no return is allowed on the income taxes regulatory asset.

In 1998, Allegheny recorded a regulatory asset for Pennsylvania stranded cost recovery, representing the portion of transition costs determined by the Pennsylvania PUC to be recoverable by West Penn under its deregulation plan. The CTC regulatory asset is being recovered over the transition period that will end in 2008. CTC rates include return on, as well as recovery of, transition costs.

of under-recovery of CTC during the transition period, if any, will be determined at the end of the transition period, which extends through 2008. On an annual basis, the Pennsylvania PUC has approved the amount of CTC true-up recorded as a regulatory asset by Allegheny.

See “West Virginia Regulation” in Note 14 for a discussion regarding Monongahela’s and Potomac Edison’s reapplication of the provisions of SFAS No. 71 to their West Virginia jurisdictional generating assets in the first quarter of 2003.

See “Asset Retirement Obligations” in Note 25 for a discussion of a regulatory liability identified in conjunction with the application of a new accounting pronouncement.

The carrying amounts and estimated fair values of financial instruments, other than commodity contracts that were recorded at fair value in assets and liabilities, at December 31 were as follows:

The carrying amounts of temporary cash investments and short-term debt approximate the fair values because of the short maturities of those instruments. The fair value of the life insurance contracts was estimated based on cash surrender value. The fair value of the available-for-sale securities, debentures, notes, bonds, and QUIDS was estimated based on actual market prices or market prices of similar issues.

Certain of Allegheny’s subsidiaries jointly own electric generating facilities with third parties. Allegheny’s subsidiaries record their proportionate share of operating costs, assets, and liabilities related to these generating facilities in the corresponding lines in the consolidated financial statements. As of December 31, 2002, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:

Other income and expenses represent nonoperating revenues and expenses before income taxes. The following table summarizes Allegheny’s other income and expenses for 2002, 2001, and 2000:

revenues reflect certain reclassifications to comply with EITF Issue No. 02-3, as discussed in Note 4, and for net revenues and operating income, reflect reclassifications made in Allegheny’s presentation of its Statement of Operations after the Forms 10-Q for the first and second quarters of 2002 were filed. The reclassifications were made to provide consistent presentations among Allegheny’s various SEC registrants. In aggregate, the reclassifications had no effect on previously reported consolidated (loss) income before cumulative effect of accounting change and consolidated net loss.

The corrections of accounting errors related to the first and second quarters quarter of 2002 were primarily as follows:

Had Allegheny adjusted 2001 for the correction of the accounting errors discussed in Note 2 that were recorded in the first quarter of 2002, the 2001 quarterly consolidated net income and earnings per share would have been as follows:

SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets, was adopted by Allegheny on January 1, 2003. SFAS No. 143 requires that the fair value of asset retirement costs for which Allegheny has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or records a gain or loss if settled at a different amount.

Allegheny has completed a detailed assessment of the specific applicability of SFAS No. 143 and recorded retirement obligations primarily related to ash landfills, underground and aboveground storage tanks, and natural gas wells. Allegheny also has identified a number of retirement obligations associated with certain other assets that have not been recorded, because the fair value of such obligations cannot be reasonably estimated, due primarily to the indeterminate lives of the assets.

The effect of adopting SFAS No. 143, effective January 1, 2003, on Allegheny’s consolidated statement of operations will be a cumulative effect adjustment to decrease net income by $10.0 million ($16.3 million, before income taxes). The effect of adopting SFAS No. 143 on Allegheny’s consolidated balance sheet will be a $3.4-million increase in property, plant, and equipment, net and the recognition of a $19.7-million liability for asset retirement obligations.

Allegheny’s regulated utility subsidiaries—Monongahela, Potomac Edison, and West Penn—have recorded in accumulated depreciation removal costs collected from customers related to assets that do not have associated retirement obligations under SFAS No. 143. These estimated removal costs, totaling $356.5 million at December 31, 2002, represent a regulatory liability and remain in accumulated depreciation.

See Note 3 for the effect of Allegheny’s adoption of EITF Issue No. 02-3. See Note 26, under “Guarantees” and “Variable Interest Entities,” for the effect of Allegheny’s adoption of FASB Interpretation Nos. (FIN) 45 and 46, respectively. See Note 27 for the effect of Allegheny’s adoption of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.”

The subsidiaries have entered into commitments for their construction and capital programs for which expenditures are estimated to be $362.0 million (unaudited) for 2003 and $304.3 million (unaudited) for 2004. Construction expenditure levels in 2005 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 (CAAA) and the extent to which environmental initiatives currently being considered become mandated. Allegheny estimates that its management of emission allowances will allow it to comply with Phase II sulfur dioxide (SO₂) limits through 2005. Studies to evaluate cost-effective options to comply with Phase II SO₂ limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.

In 2002, Allegheny announced a series of initiatives to preserve cash and reduce expenses and respond to the challenges it faces in the current marketplace. These initiatives included the cancellation of several generation projects resulting in a write-off of $244.0 million, before income taxes. (See Note 6 for additional information regarding asset impairments).

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

Clean Air Act and CAAA Matters: The EPA has issued a NO_x State Implementation Plan (SIP) call rule that requires the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Maryland, Pennsylvania, and West Virginia, beginning in May 2003. Allegheny’s compliance with such stringent regulations has required and will require the installation of expensive post-combustion control technologies on most of its power stations. During 2000, Pennsylvania and Maryland promulgated final rules to implement the EPA’s NO_x SIP call requirements, beginning in May 2003. During 2001, the West Virginia Department of Environmental Protection issued a final rule to implement the EPA’s NO_x SIP call requirements, beginning in May 2004. The EPA approved the West Virginia SIP in July of 2002. The EPA’s NO_x SIP call had been subject to litigation but, in 2000, the D.C. Circuit Court of Appeals issued a decision that upheld the regulation. The court issued a subsequent order that postponed the initial compliance date of the NO_x SIP call from May 2003 to May 2004. Maryland and Pennsylvania did not delay the May 2003 implementation dates of their respective SIP, nor are they legally required to do so. AE Supply and Monongahela are in the process of installing NO_x controls to meet the Pennsylvania, Maryland, and West Virginia SIP. AE also has the option to purchase, in some cases, alternate fuels, NO_x allowances, or power on the market, if needed, to supplement our compliance strategy. AE Supply and Monongahela expects to be in compliance with NO_x limits established by the SIP. Allegheny’s construction forecast includes the expenditure of $58.5 million (unaudited) of capital costs during the 2003 through 2004 period to comply with these regulations.

Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in most cases. AE believes that its subsidiaries’ generating facilities have been operated in accordance with the Clean Air Act and the rules implementing it. The experience of other energy companies, however, suggests that in recent years, the EPA has narrowed its view regarding the scope of the definition of “routine maintenance”, under its rules, thereby broadening the range of actions subject to compliance with new source review standards. Under previous EPA interpretations these same actions did not trigger application of those standards. Section 114 information requests concerning facility modifications are often followed by enforcement actions. The EPA contacted AE and requested a meeting, which was held on July 16, 2003. Additional meetings will likely be scheduled in the next few months. At this time, AE is not able to determine what effect the EPA’s inquiry may have on its operations. If new source review standards are applied to AE generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. However, the recent preliminary judicial decision in the EPA vs. Duke energy case, as well as the final Routine Maintenance, Repair and Replacement Rule recently released by the EPA, are more consistent with

the energy industry’s historical compliance approach. Therefore, at this time, AE and its subsidiaries are not able to determine the effect these actions may have on them with regard to compliance costs.

The Attorneys General of New York and Connecticut, in letters dated September 15, 1999, and November 3, 1999, respectively, notified AE of their intent to commence civil actions against AE and/or its subsidiaries alleging violations at the Fort Martin Power Station under the federal Clean Air Act, which requires power plants that make major modifications to comply with the same New Source Review emission standards applicable to new power plants. Other governmental agencies may commence similar actions in the future. Fort Martin Power Station is located in West Virginia and is now jointly owned by AE Supply and Monongahela. Both Attorneys General stated their intent to seek injunctive relief and penalties. In addition, the Attorney General of the State of New York indicated that he may 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, AE and its subsidiaries are not able to determine what effect, if any, these actions may have on them.

Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) Claim: On March 4, 1994, Monongahela, Potomac Edison, and West Penn (the Distribution Companies) received notice that the EPA had identified them as potentially responsible parties (PRPs) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site. Initially approximately 175 PRPs were involved, however, the current number of active PRPs is approximately 80. The costs of remediation will be shared by all responsible parties. In 1999, a PRP group that included the Distribution Companies entered into a consent order with the EPA to remediate site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30 million. However, Allegheny estimates that its share of the cleanup liability will not exceed $1.0 million, which has been accrued as a liability at December 31, 2002.

Claims Related to Alleged Asbestos Exposure: Monongahela, Potomac Edison, and West Penn have also been named as defendants along with multiple other defendants in pending asbestos cases involving multiple plaintiffs. While Allegheny believes that all of the cases are without merit, Allegheny cannot predict the outcome of the litigation. Allegheny has accrued a reserve of $4.0 million as of December 31, 2002, related to the asbestos cases as the potential cost to settle the cases to avoid the anticipated cost of defense. During 2002, Allegheny received $2.4 million of insurance recoveries (net of $.5 million of legal fees) related to these asbestos cases. During 2001, Allegheny received $.7 million of insurance recoveries related to these asbestos cases.

Nevada Power Contracts: On December 7, 2001, Nevada Power Company (NPC) filed a complaint with the FERC against AE Supply, which sought FERC action to modify prices payable to AE Supply under three trade confirmations dated December 4, 2000, January 16, 2001 and February 7, 2001 between Merrill Lynch and NPC, and entered into under the Western Systems Power Pool Master Agreement. The transactions related to power sales during 2002. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with AE Supply under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers.

Sierra/Nevada: On April 2, 2003, NPC and Sierra Pacific Resources, Inc., (together Sierra/Nevada) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, Merrill). The complaint alleged that Allegheny and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (Nevada PUC) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180.0 million of NPC’s deferred energy expenses. Sierra/Nevada asserted three causes of action against Allegheny arising from the alleged fraudulent conduct. These include: (1) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages, (2) conspiracy, and (3) violations of the Nevada state RICO act. Sierra/Nevada filed an amended complaint on May 30, 2003 in which they assert a fourth cause of action against Allegheny for wrongful hiring and supervision. Sierra/Nevada seeks $180.0 million in compensatory damages plus attorneys fees. Under the RICO count, Sierra/Nevada seeks in excess of $850.0 million.

Settlement of Litigation Related to Power Supply Contracts with the CDWR: In March and April 2001 AE Supply entered into two ten-year power sales agreements pursuant to a master power purchase and sale agreement (together, the CDWR contract) with the CDWR, the electricity buyer for the State of California. The CDWR contract constituted one of Allegheny’s key assets. In February 2002, the California Public Utilities Commission (California PUC) and the California Electricity Oversight Board (CAEOB) filed complaints with the FERC seeking to abrogate the contracts. In January 2003, the CDWR filed a lawsuit in California Superior Court alleging that AE Supply breached the contracts, and seeking a judicial determination that the contracts were terminated along with monetary damages.

On June 10, 2003, AE Supply and CDWR entered into a settlement agreement with renegotiated terms and conditions of the CDWR contract. The settlement reduces the off-peak power prices payable by CDWR under the contracts from $61 per MWh from 2004 to 2011 to $60 in 2004, $59 in 2005 and $58 in 2006 through 2011. The settlement terms also reduce the volume of power to be purchased from 1,000 MW from 2005-2011 to 750 MW in 2005 and 800 from 2006 through 2011. The renegotiated contract also states that the parties waive all rights to challenge the validity of the agreement or whether it is just and reasonable for its duration. These modifications significantly reduced the value of the CDWR contract, in the range of $160-$190 million. The terms of the settlement also provide that the California PUC and CAEOB agree to drop their complaints against AE Supply at FERC, and CDWR and the California Attorney General agree to drop their lawsuit filed in California Superior Court. The parties agreed that all litigation will be withdrawn with prejudice.

The settlement agreement has been approved by the California PUC. The FERC issued an order approving the settlement on July 11, 2003. On August 15, 2003, the CDWR filed a notice of entry of dismissal with prejudice with the California Superior Court in Sacramento, and the clerk of the court entered the dismissal as requested.

Putative Class Actions Under California Statutes: Nine related putative class action lawsuits against AE Supply, and more than two dozen other named defendant power suppliers were filed in various California superior courts during 2002. These class action suits were removed to federal court and transferred to the U.S. District Court for the Southern District of California. Eight of the suits were commenced by consumers of wholesale electricity in California. The ninth, Millar v. Allegheny Energy Supply Co., et al., was filed on behalf of California taxpayers. The complaints allege, among other things, that AE Supply and the other defendant power suppliers violated California’s antitrust statute and the California unfair business practices statute by allegedly manipulating the California electricity market over a period of years. The suits also challenge the validity of various long-term power contracts with the State of California, including the CDWR contract.

On August 25, 2003, AE Supply’s motion to dismiss seven of the eight consumer class actions with prejudice was granted by the U.S. District Court. AE Supply has not been served in the eighth consumer class action, Kurtz v. Duke Energy Trading and Marketing, LLC. This case is still pending in the U.S. District Court. The allegations in this complaint are substantively identical to those in the dismissed actions.

The District Court separately granted plaintiffs’ motion to remand in the taxpayer action, Millar, on June 8, 2003. AE Supply and the other defendants plan to file a demurrer as soon as plaintiffs file a notice of return to California superior court.

In May of 2002 a California state legislator brought a claim on behalf of California taxpayers against AE Supply and 30 other power suppliers, as well as Vikram Budhraja, a contract negotiator for the CDWR. The suit, styled as McClintock v. Budhraja, et al. and brought in California Superior Court in Los Angeles County, alleges, among other things, that Budhraja had a conflict of interest during negotiations. AE Supply has not been served in this action. Plaintiffs seek a judicial declaration that the energy contracts are void and unenforceable as a matter of law, as well as judicial intervention to prohibit further performance on the energy contracts by any defendant. AE Supply continues to monitor the status of the Kurtz and Budhraja lawsuits.

Putative Shareholder, Derivative, and Benefit Plan Class Actions: From October 2002 through December 2002, plaintiffs claiming to represent purchasers of AE’s securities filed 14 putative class-action lawsuits against AE and several of its former senior managers in U.S. District Courts for the Southern District of New York and the District of Maryland. The complaints allege that AE and senior management violated federal securities laws when AE purchased Merrill Lynch’s energy marketing and trading business with the knowledge that the business was built on illegal wash or round-trip trades with Enron, which the complaints allege artificially inflated trading revenue, volume and growth. The complaints assert that AE’s fortunes fell when Enron’s collapse exposed what plaintiffs claim were illegal trades in the energy markets. The complaints do not specify requested relief.

In June 2003, a shareholder derivative action was filed against AE’s Board of Directors and several former senior managers in the Supreme Court of the State of New York for the County of New York. The suit alleges that the Board and senior management breached fiduciary duties to AE that have exposed AE to the securities class-action lawsuits.

Suits Related to Gleason Generating Facility: Allegheny Energy Supply Gleason Generating Facility, LLC, a subsidiary of AE Supply, is the defendant in suits brought in the Circuit Court for Weakley County, Tennessee, by residents living in the vicinity of the generating facility in Gleason, Tennessee. The original suit was filed on September 16, 2002. AE Supply purchased the peaking facility in 2001. The plaintiffs are asserting claims based on trespass and/or nuisance, claiming personal injury and property damage as a result of noise from the generating facility during operation. They seek a restraining order with respect to the operation of the plant and damages of $200 million.

The Gleason Facility has demanded indemnification and a defense from Siemens Westinghouse, the manufacturer of the turbines used in the facility, pursuant to the terms of the equipment purchase agreement. On October 17, 2002, Siemens Westinghouse filed a request for a declaratory judgment in the Court of Common Pleas of Allegheny County, Pennsylvania seeking a declaration that the prior owner released Siemens Westinghouse from this liability through a release executed after Allegheny purchased the Gleason facility.

AE has also undertaken property purchases and other mitigation measures. AE cannot predict the outcome of this suit or whether it will be able to recover amounts from Siemens Westinghouse.

Litigation Against Merrill Lynch: AE and AE Supply entered into an asset purchase agreement with Merrill Lynch and affiliated parties in 2001 whereby AE and AE Supply purchased Merrill Lynch’s energy marketing and trading business for approximately $489 million and an equity interest in AE Supply of nearly two-percent. The asset purchase agreement provides that Merrill Lynch would have the right to require AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest calculated from March 16, 2001, in the event that certain conditions were not met.

On October 23, 2002, AE filed a motion to stay Merrill Lynch’s federal court action in favor of AE and AE’s action in New York state court. On May 29, 2003, the United States District Court for the Southern District of New York denied AE’s motion to stay Merrill Lynch’s action and ordered that AE and AE Supply assert its claims against Merrill Lynch, which were initially brought in New York state court as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply dismissed its New York State action and, on June 13, 2003, AE and AE Supply filed counterclaims against Merrill Lynch in the United States District Court for the Southern District of New York. Much like AE and AE Supply’s complaint in New York state court, the counterclaims allege that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims seek

damages in excess of $605 million and rescission of the agreement, among other relief. Merrill Lynch has moved to dismiss Allegheny’s counterclaims. On August 29, 2003, AE and AE Supply filed amended counterclaims that, among other things, add a claim against Merrill Lynch for negligent misrepresentation, and have opposed the motion to dismiss. AE and AE Supply cannot predict the outcome of this suit.

In the normal course of business, Allegheny becomes involved in various other legal proceedings. Allegheny does not believe that the ultimate outcome of these proceedings will have a material effect on its consolidated financial position, results of operations and cash flows.

EPMI Adversary Proceeding: On May 9, 2003, Enron Power Marketing, Inc. (EPMI), a Chapter 11 debtor, commenced an adversary proceeding against AE Supply in its bankruptcy case that is pending in the U.S. Bankruptcy Court for the Southern District of New York. The complaint alleges that AE Supply owes EPMI (1) $27,646,725 for accounts receivable due and owing for energy delivered prior to the commencement of EPMI’s bankruptcy case, and (2) $8,250,000 in cash collateral previously posted by EPMI to AE Supply, less any amounts owed to AE Supply as a result of EPMI’s default under a master trading agreement entered into between the parties and certain transactions arising thereunder. By the complaint, EPMI also seeks certain declaratory relief, including a declaration that the arbitration provision found in the master trading agreement is unenforceable. On August 1, 2003, AE Supply filed an answer asserting affirmative defenses. AE Supply is unable to predict the outcome of this matter.

Allegheny has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles, computer equipment, communication lines, and electric generation facilities.

The carrying amount of assets recorded under capitalized lease agreements included in property, plant, and equipment at December 31 consist of the following:

At December 31, 2002 and 2001, obligations under capital leases were as follows:

Total capital and operating lease rent payments of $38.0 million in 2002, $40.4 million in 2001, and $33.5 million in 2000 were recorded as rent expense in accordance with SFAS No. 71. Allegheny’s estimated future minimum lease payments for operating leases with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are $23.1 million in 2003; $31.8 million in 2004; $303.2 million in 2005; $5.4 million in 2006; $4.6 million in 2007; and $33.6 million thereafter. Allegheny’s estimated future minimum lease payments for capital leases with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are $9.3 million in 2003; $11.3 million in 2004; $8.8 million in 2005; $7.4 million in 2006; $6.3 million in 2007; and $11.3 million thereafter. At December 31, 2002, the present value of estimated future minimum lease payments for capital leases included in the consolidated balance sheet was $47.5 million, and reflected a difference of $6.9 million from the total annual payments disclosed above due to interest expense.

In November 2001, AE Supply entered into an operating lease transaction to finance construction of a 630-MW generating facility in St. Joseph County, Indiana. As of December 31, 2002, AE Supply recorded the facility on its consolidated balance sheet, as it was deemed the owner of the facility under EITF Issue No. 97-10, “The Effect of Lessee Involvement in Asset Construction,” as a result of lessor reimbursement for construction expenditures. As a result, AE Supply recorded approximately $415.5 million of debt related to this obligation, including costs associated with terminating the project, on its consolidated balance sheet at December 31, 2002. In February 2003, AE Supply purchased the project by assuming $380.0 million of the lessor’s long-term debt and paying an additional $35.5 million. Following the purchase of the facility, Allegheny terminated the project resulting in a write-off of $192.0 million, before income taxes ($118.4 million, net of income taxes).

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities,” which addresses consolidation by business enterprises of variable interest entities, commonly referred to as “special purpose entities.” FIN 46 requires consolidation where there is a controlling financial interest in a variable interest entity or where the variable interest entity does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties. Allegheny will apply the provisions of FIN 46 prospectively for all variable interest entities created after January 31, 2003. For variable interest entities created prior to January 31, 2003, Allegheny will be required to consolidate all variable interest entities in which it is the primary beneficiary, as of the third quarter of 2003. Other than AE Supply’s new generating facility in Springdale, Pennsylvania, which was purchased in February 2003 and subsequently consolidated, Allegheny does not believe that FIN 46 will have a material effect on its consolidated results of operations and financial position.

Under PURPA, electric utility companies, such as Allegheny’s regulated utility subsidiaries, are required to interconnect with, provide back-up electric service to, and purchase electric capacity and energy from qualifying power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by the FERC. The appropriate state public service commission or legislature establishes the rates paid for electric energy purchased from such qualifying facilities.

Allegheny’s regulated utilities are committed to purchasing the electrical output from 479 MW of qualifying PURPA capacity. Payments for PURPA capacity and energy in 2002 and 2001 totaled $205.0 million and $201.8 million, respectively, before amortization of West Penn’s adverse power purchase commitment, according to these contracts. The average cost to Allegheny’s regulated utility subsidiaries of these power purchases was approximately 5.6 cents per kilowatt-hour (kWh) and 5.4 cents per kWh for 2002 and 2001, respectively. Allegheny’s regulated utility subsidiaries are currently authorized to recover these costs in their retail rates.

The table below reflects Allegheny’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2002. Actual values can vary substantially depending upon future conditions.

Allegheny has entered into various long-term commitments for the procurement of fuel, primarily coal and lime, to supply its generating facilities. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Allegheny’s fuel consumed for electric generation was $591.5 million, $560.4 million, and $532.8 million in 2002, 2001, and 2000, respectively. In 2002, Allegheny purchased approximately 58.9 percent of its fuel from one vendor. Total estimated long-term coal and lime obligations at December 31, 2002, were as follows:

Letters of credit are purchased guarantees that ensure Allegheny’s performance or payment to third parties, in accordance with certain terms and conditions and amounted to $126.6 million of the $612.7 million available as of December 31, 2002.

In November 2002, the FASB issued FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others,” which requires disclosures by a guarantor concerning its obligations under certain guarantees that it has issued. FIN 45 also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issued or modified after December 31, 2002. Allegheny does not anticipate FIN 45 will have a material effect on its consolidated results of operations and financial position.

At December 31, 2002, Allegheny and its subsidiaries provided guarantees, either directly or indirectly, of $193.3 million for contractual obligations of affiliated companies, as discussed by major category below. This

does not include approximately $126.6 million of letters of credit. Under the terms of the guarantees, Allegheny would be required to perform should an affiliate be in default of its obligation, generally for an amount not to exceed the amount disclosed. The term of these guarantees coincide with the term of the underlying agreement. There are no amounts being carried as liabilities on the consolidated balance sheet for Allegheny’s obligations under these guarantees.

Of the guarantees provided to third parties, approximately $146.0 million relate to guarantees associated with the purchase, sale, exchange, or transportation of wholesale natural gas, electric power, and related services.

Allegheny provided loan guarantees of $42.8 million to third parties for loans and other financing related guarantees.

Allegheny provided guarantees of $4.5 million to third parties pursuant to two lease agreements that were signed in 2001 and in 2002.

In December 2001, AE Solutions entered into an agreement to provide design, construction, and installation services for seven natural gas-fired turbine generators for the SMEPA. The seven units, with a combined output of approximately 450 MW, will be located at three sites in southern Mississippi. The units will be owned by SMEPA. Construction started in May 2002, with installation of all of the units to be completed by May 2006. The agreement allows for liquidated damages, for a maximum amount of $10 million, in the event Allegheny Energy Solutions fails to meet either specified delivery dates or the generators fail to meet specified performance requirements.

In June 2003, AE Supply amended its partnership agreement with UGI Hunlock Development Company (UGI) with regards to its equity method investment in Hunlock Creek Energy Ventures (Hunlock Creek), a 48 MW coal-fired generating facility and a 44 MW gas-fired combustion turbine. This amendment provides a put option that allows UGI to require AE Supply to purchase either or both the existing coal-fired facility and combustion turbine owned by Hunlock Creek for a specified purchase price. AE is currently a 50% owner in Hunlock Creek. The amendment provides a purchase price for the coal-fired facility equivalent to full value of $15 million, plus the value of all related inventory. The purchase price for the combustion turbine will be made at its book value at the time of exercise of the option. The option can be exercised for a period of 90 days commencing January 1, 2006.

In February and March 2003, AE, AE Supply, Monongahela, and West Penn entered into agreements (Borrowing Facilities) totaling $2,447.8 million with various credit providers to refinance and restructure the bulk of AE and AE Supply’s short-term debt.

In addition, $380.0 million of indebtedness related to the discontinued St. Joseph, Indiana generating project, in the form of A-Notes, was restructured and assumed by AE Supply. Of this debt, $343.7 million is secured by substantially all the assets of AE Supply, other than its new generating facility in Springdale, Pennsylvania. The secured portion of this debt bears an interest rate of 10.25 percent, and the unsecured portion bears interest at 13.0 percent. This debt matures in November 2007.

The $420.0 million committed and borrowed by AE Supply under the $470.0 million facility represents new liquidity. The Borrowing Facilities at AE Supply also refinanced $1,637.8 million of existing debt and letters of credit, including $894.9 million outstanding under various credit agreements, $270.1 million outstanding related to the construction of AE Supply’s generating facility in Springdale, Pennsylvania, which went into commercial operation in July 2003. The Borrowing Facilities at AE, Monongahela, and West Penn refinanced $340.0 million of existing debt and letters of credit.

amounts not so secured increased to a spread of 10.5 percent over the applicable LIBOR-based rate or the designated money center bank’s base rate for the Refinancing Credit Facility and the Springdale Credit Facility and 13.0 percent for the unsecured portion of the $380.0 million A-Note debt retroactively to February 25, 2003, the closing date of the Borrowing Facilities. The total amounts unsecured under the Refinancing Credit Facility, the Springdale Credit Facility and the A-Note debt are approximately $94.3 million, $175.8 million and $36.3 million, respectively.

AE Supply borrowed $2,057.8 million under the Borrowing Facilities and the restructured A-Notes. Of the total, either AE Supply’s new generating facility in Springdale, Pennsylvania or substantially all of AE Supply’s assets secures $1,927.2 million. A 30 percent limitation of available secured debt in AE Supply’s indenture will also make it difficult, if not impossible, for AE Supply to borrow additional funds until some of the secured debt under the Borrowing Facilities is repaid.

The interest rates payable by AE Supply under certain parts of the Borrowing Facilities are tied to AE Supply’s credit ratings. Should AE Supply’s credit ratings improve from its current ratings to certain specified higher ratings, the rate of interest AE Supply would be required to pay under the Refinanced Credit Facility and the Springdale Credit Facility could decrease by .5 percent to 1.0 percent for the secured portion of those credit facilities.

Allegheny is required to meet certain financial tests, as defined in the Borrowing Facilities agreements, including:

AE Supply also is required to meet certain financial tests, as defined in the Borrowing Facilities agreements, including:

Effective July 22, 2003, Allegheny and AE Supply were granted waivers from compliance with all of the above financial tests for the first and second quarters of 2003. Effective August 22, 2003, Allegheny and AE Supply received additional waivers of the financial tests for the third quarter of 2003.

The Borrowing Facilities also have provisions requiring prepayments out of the proceeds of asset sales and debt and equity issuances, as follows:

The Borrowing Facilities also contain restrictive covenants that limit Allegheny’s ability to: borrow funds; incur liens; enter into a merger or other change of control transaction; sell assets; make investments; prepay indebtedness; amend contracts; pay dividends and other distributions on Allegheny’s equity; and operate Allegheny’s business, by requiring it to adhere to an agreed business plan.

On July 24, 2003, Allegheny obtained $291 million ($275 million after deducting various fees and placement agents’ commissions) from the issuance to a special purpose finance subsidiary of AE, Allegheny Capital Trust I (Capital Trust), of units comprised of $300 million principal amount of 11⁷/8 percent Notes due 2008 and warrants for the purchase of up to 25 million shares of AE’s common stock, exercisable at $12 per share. The warrants are mandatorily exercisable if AE’s common stock price equals or exceeds $15 per share over a specified averaging period occurring after June 15, 2006. The warrants are stapled to the notes and may be exercised only through the tender of the notes. The finance subsidiary obtained proceeds required to purchase the units by issuing $300 million liquidation amount of its 11⁷/8 percent Mandatorily-Convertible Trust Preferred Securities to investors in a private placement. The holder of a preferred security is entitled to distributions on a corresponding principal amount of notes and may direct the exercise of warrants stapled to the notes. AE guarantees Capital Trust’s payment obligations under the preferred securities. The notes and AE’s guarantee of Capital Trust’s payment obligations are subordinated only to indebtedness arising under the agreements governing certain of Allegheny’s indebtedness under the Borrowing Facilities.

In May 2003, the FASB issued SFAS No. 150, which requires certain financial instruments that have historically been classified as equity to be classified as liabilities (or as an asset in certain circumstances.) SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. In accordance with SFAS No. 150, Allegheny will classify its $300 million 11⁷/8 percent convertible trust preferred securities, issued on July 24, 2003, as a liability.

The management of Allegheny Energy, Inc. (the Company) is responsible for the information and representations in the Company’s financial statements. The Company prepares the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management’s best estimates and judgments of known conditions.

The Company is responsible for maintaining an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Company’s assets are protected. As discussed in Item 14 of the Company’s Annual Report on Form 10-K, the Company’s management has concluded that the Company’s internal controls are not adequate. Management and the Audit Committee of the Board of Directors are committed to devoting the additional resources necessary to ensure that the Company’s reporting is accurate until internal controls are improved and are adequate.

The Company’s staff of internal auditors conducts periodic reviews designed to assist management in maintaining effective internal control procedures. PricewaterhouseCoopers LLP, an independent accounting firm, audits the financial statements and expresses its opinion on them. The independent auditors perform their audit in accordance with auditing standards generally accepted in the United States of America.

The Audit Committee of the Board of Directors, which consists of outside Directors, meets regularly with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to all of the Company’s records and to the Audit Committee.

In our opinion, the accompanying consolidated balance sheets, consolidated statements of capitalization and common equity and the related consolidated statements of operations, cash flows and comprehensive income, present fairly, in all material respects, the financial position of Allegheny Energy, Inc. and its subsidiaries (the Company) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the financial statements, the Company is not in compliance with reporting obligations contained in certain of its debt covenants and, as a result, certain debt has been classified as current which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 3. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 2 to the financial statements, the consolidated balance sheet as of December 31, 2001, has been restated.

As discussed in Note 7 to the financial statements, on January 1, 2002, the Company adopted Financial Accounting Standards Board Statement No. 142, “Goodwill and Other Intangible Assets.”

As discussed in Note 9 to the financial statements, on January 1, 2001, the Company adopted Financial Accounting Standards Board Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

AE Supply is a majority owned subsidiary of Allegheny Energy, Inc. (AE, and collectively with AE’s consolidated subsidiaries, Allegheny). AE is a public utility holding company.

AE Supply was formed in November 1999 in order to consolidate Allegheny’s deregulated energy supply business. On November 18, 1999, one of AE Supply’s affiliates, West Penn Power Company (West Penn), transferred its generating capacity of 3,778 megawatts (MW) to AE Supply at net book value, as allowed by the final settlement in West Penn’s Pennsylvania restructuring case. In 1999 AE Supply also purchased 276 MW of merchant capacity at Fort Martin Unit No. 1 from another affiliate, AYP Energy, Inc. (AYP Energy). On August 1, 2000, AE Supply’s affiliate, The Potomac Edison Company (Potomac Edison), transferred its generating assets, except certain hydroelectric facilities located in Virginia, to AE Supply at net book value. This transfer totaled approximately 2,100 MW of generating capacity. In addition, on June 1, 2001, AE Supply’s affiliate, Monongahela Power Company (Monongahela), transferred its Ohio and Federal Energy Regulatory Commission (FERC) jurisdictional generating assets to AE Supply at net book value. This transfer totaled 352 MW of generating capacity.

The transfers from West Penn, Potomac Edison, and Monongahela included their ownership interest in Allegheny Generating Company (AGC). AGC owns and sells its generating capacity of 960 MW to its parents, AE Supply and Monongahela. The transfers from West Penn, Potomac Edison, and Monongahela also included their entitlement to 202 MW of generating capacity from Ohio Valley Electric Corporation (OVEC).

In March 2001, AE Supply acquired Global Energy Markets, the energy commodity marketing and trading business of Merrill Lynch Capital Services, Inc. (Merrill Lynch).

AE Supply operates under a single business segment, Generation and Marketing. In 2002, the majority of revenues were from bulk power sales to affiliates. AE Supply’s operations may be subject to federal regulation, but are not subject to state regulation of rates.

Certain amounts in the December 31, 2001, consolidated balance sheet and in the December 31, 2001 and 2000, consolidated statement of operations and consolidated statement of cash flows have been reclassified for comparative purposes. Significant accounting policies of AE Supply and its subsidiaries are summarized below.

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires AE Supply to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. On a continuous basis, AE Supply evaluates its estimates, including those related to the calculation of the fair value of commodity contracts and derivative instruments, unbilled revenues, provisions for depreciation and amortization, adverse power purchase commitments, regulatory assets, income taxes, pensions and other postretirement benefits, and contingencies related to environmental matters and litigation. AE Supply bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

AE Supply’s accounting for commodity contracts, which requires some of its more significant judgments and estimates used in the preparation of its consolidated financial statements, is discussed under “Revenues” below and in Note 4. The accounting for derivative instruments is discussed in Note 9.

Revenues from the sale of unregulated generation are recorded in the period in which the electricity is delivered and consumed by customers.

AE Supply records contracts entered into in connection with energy trading at fair value on the consolidated balance sheet, with changes in fair value recorded as a component of operating revenues on the consolidated statement of operations.

These amounts could be materially different from amounts that might be realized in an actual sale transaction. Fair values are subject to change in the near term and reflect management’s best estimate based on various factors.

For energy trading, AE Supply enters into physical energy commodity contracts and energy-related financial contracts. The sales and purchases made under commodity contracts for energy trading are recorded in operating revenues in accordance with Emerging Issues Task Force (EITF) Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts.”

AE Supply has netting agreements with various counterparties, which provide the right to set-off amounts due from and to the counterparty. To the extent of those netting agreements, AE Supply records the fair value of commodity contract assets and liabilities and accounts receivable and accounts payable with counterparties on a net basis.

Property, plant, and equipment are stated at original cost. West Penn, Potomac Edison, and Monongahela’s Ohio and FERC jurisdictional generating assets were transferred to AE Supply at book value from 1999 through June 2001. Gains or losses on asset dispositions are included in the determination of net income.

AE Supply capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over the expected useful life of the software beginning upon a project’s completion.

AE Supply adopted the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. Long-lived assets owned by AE Supply are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, resulting in the asset being written down to its fair value. The fair value is determined by the use of quoted market prices, appraisals, or the use of other valuation techniques, such as expected discounted future cash flows. See Note 6 for information related to asset impairment charges during 2002.

AE Supply capitalizes interest costs in accordance with the provisions of SFAS No. 34, “Capitalization of Interest Costs.” The interest capitalization rates in 2002, 2001, and 2000 were 6.22 percent, 6.37 percent, and 5.75 percent, respectively. AE Supply capitalized interest of $7.7 million in 2002, $8.2 million in 2001, and $5.9 million in 2000.

Depreciation expense is determined generally on a straight-line method based on the estimated service lives of depreciable properties and amounted to approximately 2.5 percent of average depreciable property in 2002, 2.1 percent in 2001, and 2.7 percent in 2000. Estimated service lives for generation property range from seven to 50 years, transmission property range from seven to 32 years, and all other property range from two to 37 years. Depreciation expense was $117.3 million, $94.8 million, and $55.3 million, for 2002, 2001, and 2000, respectively.

Maintenance expenses represent costs incurred to maintain the power stations, transmission property, and general plant, and reflect routine maintenance of equipment, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations. Maintenance costs are expensed in the year incurred.

AE Supply records the acquisition cost in excess of fair value of tangible and intangible assets acquired, less liabilities assumed, as goodwill. See Note 5 for information regarding AE Supply’s recent acquisitions. Effective January 1, 2002, with the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets,” AE Supply ceased amortization of goodwill and now tests goodwill for impairment at least annually. SFAS No. 142 also requires that other intangible assets with indefinite lives not be amortized, but, rather, be tested for impairment at least annually. Other intangible assets with finite lives are to be amortized over their useful lives and tested for impairment when events or circumstances warrant. See Note 7 for additional information regarding AE Supply’s adoption of SFAS No. 142 and ongoing accounting for goodwill and other intangible assets.

exercise significant influence, but not control, over the investee. The income or loss from unregulated investments is recorded in other income and expenses, net in the consolidated statement of operations.

AE Supply has various operating transactions with affiliates. It is AE Supply’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented net on the consolidated balance sheet and consolidated statement of cash flows. See Note 19 for additional information on related party transactions.

AE Supply joins with Allegheny and its affiliates in filing a consolidated federal income tax return. The consolidated income 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 income tax liability.

Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the financial statement and tax basis of assets and liabilities computed using the most current tax rates. See Note 13 for additional information regarding income taxes.

AE Supply has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant, and equipment.

Substantially all of the employees of Allegheny are employed by Allegheny Energy Service Corporation (AESC), a wholly-owned subsidiary of Allegheny, which performs services at cost for AE Supply and its affiliates in accordance with the PUHCA. Through AESC, AE Supply is responsible for its proportionate share of postretirement benefit costs.

AESC provides a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on each employee’s years of service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act of 1974 (ERISA) and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities, short-term investments, and insurance contracts.

amount that can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self-insured.

Other Comprehensive income, consisting of unrealized gains and losses, net of income taxes, from cash flow hedges, is presented in the consolidated financial statements as required by SFAS No. 130, “Reporting Comprehensive Income.”

As a result of Allegheny’s comprehensive accounting review, Allegheny identified, prior to closing its books for 2002, various errors relating to the financial statements for 2001, 2000, and years prior to 2000. Except for certain classification adjustments to the consolidated balance sheet as of December 31, 2001, Allegheny’s management concluded that these errors for AE Supply were not material, either individually or in the aggregate, to the current year or any prior years’ financial statements. Accordingly, prior year financial statements have not been restated, except for the consolidated balance sheet as of December 31, 2001. These adjustments related to AE Supply, which increase the 2002 net loss, aggregate approximately $9.3 million, net of income taxes, and have been recorded in the first quarter of 2002 as an increase to the loss. The nature and amounts of these adjustments are primarily as follows:

In addition, Allegheny identified the following adjustment affecting only years prior to the year 2002:

The years to which the (charges) income, net of income taxes, relate are as follows:

AE Supply’s management concluded that the consolidated balance sheet as of December 31, 2001, required restatement to correct amounts previously reported as commodity contract assets and liabilities and the related deferred income taxes. At December 31, 2001, commodity contracts were incorrectly classified between assets and liabilities due to errors in AE Supply’s process for identifying those commodity contracts that included the right to setoff. As a result, the amounts previously reported by Allegheny as commodity contract assets and liabilities did not comply with the requirements of FASB Interpretation No. (FIN) 39, “Offsetting of Amounts Related to Certain Contracts,” since the amounts did not accurately reflect Allegheny’s legal right, by contract or otherwise, to offset the commodity contract assets and liabilities. In order to correct the errors, AE Supply has restated the following assets and liabilities as of December 31, 2001 after correcting its process for identifying commodity contracts that include the right of setoff.

The balance sheet reclassification restatements displayed above had no impact on 2001 consolidated members’ equity, cash flows, or the results of operations.

While certain changes in policies and procedures have been instituted, additional changes are needed to improve the internal control structure of Allegheny.

Regarding its internal controls for energy trading operations, Allegheny has revised its corporate energy risk policy to incorporate the best practices as defined by the Committee of Chief Risk Officers (CCRO) in its white papers issued in November 2002. As a result, the role and responsibilities of Allegheny’s corporate risk management function, which is independent from its energy trading operations, have been significantly expanded, to include the responsibility for determining the fair value of energy trading positions. Allegheny has established clear separation of duties for front, middle, and back office activities. Allegheny also reduced transaction and exposure limits for its energy trading operations.

In October 2002, Allegheny announced that AE, AE Supply, and AGC were in technical default under their principal credit agreements after AE Supply declined to post additional collateral in favor of several trading counterparties. The request for additional collateral resulted from a downgrade in Allegheny’s credit rating below investment grade by Moody’s. During the period November 2002 through February 2003, AE, AE Supply and AGC obtained waivers of, and amended, certain covenants to these principal credit facilities. The total debt classified as current, in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived by the Creditor,” in the accompanying consolidated balance sheet related to such defaults was approximately $1,437.0 million as of December 31, 2002. See the discussion below concerning other defaults on additional long-term debt that also resulted in the classification of that debt as current.

Allegheny and its subsidiaries, including AE Supply, have prepared their financial statements assuming that they will continue as going concerns. However, AE Supply’s noncompliance with its debt covenants and the classification of certain debt as current has caused its independent auditors, PricewaterhouseCoopers LLP, to issue a modified opinion that indicated there is substantial doubt about AE Supply’s ability to continue as a going concern (a “Going Concern” opinion).

On February 25, 2003, AE, AE Supply, Monongahela and West Penn entered into agreements (Borrowing Facilities) totaling $2,437.8 million with various credit providers to refinance and restructure the bulk of AE and AE Supply’s short-term debt. See Note 24 for additional details regarding the Borrowing Facilities.

The Borrowing Facilities at AE Supply require repayments of $250.0 million in the fourth quarter of 2003 and $200.0 million and $150.0 million, respectively, in the third and fourth quarters of 2004.

Allegheny had several debt agreements that required it to file copies of its annual or quarterly reports as filed with the SEC pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) with the debtholders. Allegheny is also required to deliver to or for the debtholders a certificate indicating that Allegheny has complied with all conditions and covenants under the agreements. On April 30, 2003, Allegheny provided certificates to the trustees under its indenture indicating that it was not in compliance with the covenants for filing its annual and quarterly reports that are contained in its First Mortgage Bonds and Debentures. The covenant breach of the First Mortgage Bonds and Debentures is deemed a default of these debt agreements, as well as a default under agreements governing certain other of Allegheny’s indebtedness, including pollution control and other indebtedness, that contain cross-acceleration provisions with the First Mortgage Bonds and Debentures, for Allegheny’s financial reporting purposes in accordance with EITF Issue No. 86-30.

The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was approximately $310.8 million as of December 31, 2002 for AE Supply. To date, the debtholders have not provided Allegheny with any notices of default under the agreements. Such notices, if received, would allow Allegheny either 30 or 60 days to cure its noncompliance before the debtholders could accelerate the due dates of the debt obligations.

Management plans to file its Annual Report on Form 10-K for the period ended December 31, 2003 on a timely basis.

In 2003, AE Supply’s cash flows are expected to be adequate to meet all of its payment obligations under the debt agreements, including the outstanding notes, and to fund other working capital needs. AE Supply’s projected cash flows from operations are not expected to be sufficient in 2004 to meet all of its payment obligations under its debt agreements, including the outstanding notes, or to fund its other liquidity needs. AE Supply is actively pursuing a liquidity strategy in an effort to obtain cash to meet its payment obligations. AE Supply cannot assure that its liquidity strategy will provide liquidity in a manner or time frame to meet its payment obligations under the Borrowing Facilities.

AE Supply has taken a number of recent actions to improve its financial condition. These steps include substantial senior management changes; the refinancing of principal credit facilities (as discussed above); exiting from Western United States energy markets; refocusing trading activities; asset sales; restructuring and cost-reducing initiatives; and improving internal controls and reporting.

Exiting from Western United States Energy Markets: AE Supply worked through 2003 to accomplish its effective exit from the Western U.S. power markets. Its positions based in the Western U.S. had been a substantial source of earnings and cash flow volatility and risk, and trading in these markets does not fit with Allegheny’s new business model.

Renegotiation and Sale of CDWR Contracts. In June 2003, AE Supply entered into a settlement agreement with the state of California to resolve the state’s litigation regarding its power supply contracts with the CDWR. The terms of the settlement reduced the volume of power to be delivered from 2005-2011 and reduced the sale price of off-peak power to be delivered from 2004-2011, which in turn substantially reduced the value of the contracts. (See Note 23 to the consolidated financial statements under “Other Litigation-CDWR” for additional information). In September 2003, AE Supply sold the CDWR contract, and associated hedge transactions, to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc. for approximately $354 million. Allegheny has applied $214 million of the sale proceeds to required payments under agreements entered into to terminate tolling agreements with Williams Energy marketing and Trading Company (Williams) and Las Vegas Cogeneration II (LV Cogen), a unit of Black Hills Corporation, as described below. Allegheny will apply an additional $28 million of the proceeds to make required payments in March and September of 2004 under the agreement with Williams. Approximately $26 million will be held in a pledged account for the benefit of AE Supply’s creditors. This arrangement is intended to enhance AE Supply’s ability to refinance certain secured borrowings. Approximately $71 million of the sale proceeds was placed in escrow for the benefit of J. Aron & Company, pending Allegheny’s fulfillment of certain post-closing requirements. When the escrowed funds are

released, approximately $50 million will be added to the pledged account and AE Supply will receive the balance. The remaining $15 million of sale proceeds will be used to partially offset certain of the hedges related to the CDWR contract and to pay fees and expenses associated with the transaction.

Agreement to Terminate Williams Toll. In July 2003, AE Supply entered into a conditional agreement with Williams to terminate its 1,000 MW tolling agreement with Williams. Under the agreement, AE Supply made an initial payment to Williams of approximately $2.4 million to satisfy certain amounts under a related hedge agreement. Allegheny made a $100 million payment to Williams after the close of the sale of the CDWR contracts. Allegheny will make two payments of $14 million to Williams in March and September of 2004. The tolling agreement will terminate when the final $14 million payment is made.

Termination of LV Cogen Toll. In mid-September , 2003, AE Supply terminated its 222 MW tolling agreement with LV Cogen. AE Supply made a $114 million termination payment to LV Cogen after the closing of the sale of the CDWR contracts.

As of December 31, 2002, the fair value of the CDWR contracts and related hedges that were sold to J. Aron & Company, plus the Williams and LV Cogen tolling agreements, was $554.5 million. From January 1, 2003, through the date that these contracts were either sold or agreements were reached to terminate the contracts, the aggregate fair value of the contracts decreased by $462.7 million to $91.8 million. As a result of the sale of the CDWR contracts and related hedges and the terminations of the Williams and LV Cogen tolling agreements, AE Supply incurred a net loss of $50.4 million, before income taxes, in the third quarter of 2003. This loss was determined excluding the approximately $70.8 million of sale proceeds that were placed in escrow pending AE Supply’s fulfillment of certain post-closing requirements. AE Supply expects to meet these requirements in the fourth quarter of 2003, at which time the net loss would be revised from $50.4 million, before income taxes, to a net gain of $20.4 million, before income taxes.

After completing these major transactions, AE Supply’s remaining trading exposures to the Western United States market will consist of several shorter-term trades that hedged the CDWR contracts and several long-term hedges of the LV Cogen tolling agreement. AE Supply continues to seek to unwind these remaining position.

Refocusing Trading Activities: Adoption of Asset-Based Trading Strategy. AE Supply is reorienting its trading operations from high-volume financial trading in national markets to asset optimization and hedging within its region. AE Supply is implementing this rebalancing over time as its liquidity allows. Effectively exiting the Western Untied States power markets, together with unwinding substantial non-core trading positions, has enabled AE Supply to reduce long-term trading-related cash out flows and collateral obligations. In the future, AE Supply will seek to concentrate its efforts in PJM, the Midwest, and Mid-Atlantic markets where it has a physical presence and greater market knowledge. Ultimately, AE Supply intends to conduct asset optimization and hedging activities with the primary objective of locking in cash flows associated with AE Supply’ portfolio of core physical generating and load positions.

Asset Sales: In 2002, Allegheny received permission from the SEC to sell a portfolio of its nonstrategic assets, securities of its direct and/or indirect subsidiaries, and/or assets of subsidiaries, which may include sales

of utility assets and/or securities of public utility companies. AE Supply has achieved the sale of its most significant assets with a nexus to the Western United States. AE Supply has also closed the sale of its interest in the Conemaugh Generating Station, as described below. AE Supply continues to consider the sale of additional assets, especially non-core assets.

Conemaugh Generating Station. On June 27, 2003, AE Supply completed the sale of its 83-MW share of the coal-fired Conemaugh Generating Station, located near Johnstown, Pennsylvania, to a subsidiary of UGI Corporation, (UGI), for approximately $46.25 million, which does not include a contingent amount of $5 million. This contingent amount could be received in full, in part, or not at all, depending upon AE Supply’ performance of certain post-closing obligations.

Restructuring and Cost-Reducing Initiatives: AE Supply has taken several actions to align its operations with its strategy and reduce its cost structure.

Restructuring of Operations. In July 2002, Allegheny announced a restructuring plan intended to strengthen its financial performance by, among other things, reducing its workforce. Allegheny has achieved workforce reductions of more that 10 percent through a voluntary Early Retirement Option (ERO) program and selected staff reductions. In 2002, approximately 600 eligible employees accepted the ERO program. AE Supply recorded a charge of $21.4 million, before income taxes for its allocable share of the effect of the ERO program. AE Supply has essentially completed these planned workforce reductions. AE Supply will continue to take actions intended to reduce costs and improve productivity in all of its operations.

Improving Internal Controls and Reporting: Comprehensive Financial Review. Commencing in the third quarter of 2002, Allegheny, including AE Supply, undertook a comprehensive and extended review of its financial information and internal controls and procedures. This review included continuous efforts by Allegheny’s top management and directors and extensive involvement of independent auditors and other outside service firms. Allegheny continues to address its controls environment and reporting procedures, as well as its SEC filing and other outstanding reporting obligations. See Item 14, “Controls and Procedures,” for a detailed discussion.

Associated Risks: There are many attendant risks, both with AE Supply’s current liquidity situation and the measures that have been undertaken to remedy the situation in the short-term. These risks can be viewed as liquidity risks associated with the Borrowing Facilities, asset sales risks, and risks associated with the restructuring.

Liquidity Risks Associated with the Borrowing Facilities: These risks would include increased interest rate risk and additional borrowing costs. Also, required prepayments under the Borrowing Facilities will absorb a large portion of future estimated cash flows and will limit AE Supply’s ability to raise capital for purposes other than debt repayment.

losing experienced personnel, diverting management resources away from continuing operations, and failing to realize anticipated cost reductions.

There is no guarantee that Allegheny will be able to complete its plan to strengthen liquidity in the short-term and move to its longer-term strategy of remaining an integrated energy company with a focus on its fundamental power generation and delivery businesses. Should the above actions not be accomplished, or should they prove inadequate, Allegheny will have to consider additional or other measures.

A portion of AE Supply’s energy trading activities involves long-term structured transactions. Since January 1, 2001, AE Supply has acquired or entered into certain long-term contracts as part of its energy trading activities. The following contracts that extend beyond five years were added to AE Supply’s energy trading portfolio during 2001 and 2002.

AE Supply records the contracts used in its wholesale marketing 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 operating 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. 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.

AE Supply has contracts that are unique due to their long-term nature and terms and are valued using proprietary pricing models. Inputs to the models include estimated forward natural gas and power prices, interest rates, estimates of market volatility for natural gas and power prices, and the correlation of natural gas and power 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 AE Supply’s financial position and results of operations if the judgments and assumptions underlying those models’ inputs prove to be wrong or inaccurate.

The fair value 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 FASB Interpretation No. 39. At December 31, 2002, the fair value of the energy trading commodity contract assets and liabilities was $1,211.9 million and $783.7 million, respectively. At December 31, 2001, the fair value of the energy trading commodity contract assets and liabilities was $1,529.3 million and $779.1 million, respectively.

Net unrealized losses of $349.7 million, before income tax, were recorded in operating revenues to reflect the change in fair value of the energy trading commodity contracts for 2002. During the third quarter of 2002, AE Supply announced a restructuring of its energy trading activities as a result of depressed market conditions and various other factors that have negatively affected the merchant energy business, including AE Supply’s energy trading activities. AE Supply is significantly reducing its reliance on the wholesale energy trading business primarily by restricting activities to an asset-backed trading strategy using its low-cost generating assets located in the Mid-Atlantic and Midwest. As a result, AE Supply’s trading activities will focus on lowering risk, optimizing the value of its generating assets, improving cash flows, and reducing the effect of mark-to-market earnings.

During the fourth quarter of 2002, the value of AE Supply’s portfolio of energy trading contracts was reduced by an additional $216.4 million, before income taxes. This reduction in value resulted from a decrease in the liquidity and volatility of the energy markets in the Western United States and a decrease in AE Supply’s liquidity, which restricted its ability to extract value from the portfolio in the short-term. This decrease in market

liquidity and volatility primarily affected the fair value of AE Supply’s contractual right to call up to 1,000 MW of generation in southern California and the agreement with LV Cogen for 222 MW of generating capacity.

Net unrealized gains of $598.1 million and $8.4 million, before income taxes, were recorded in operating revenues to reflect the change in fair value of the energy trading commodity contracts for 2001 and 2000, respectively.

As of December 31, 2002, the fair value of AE Supply’s commodity contracts with the CDWR of $1,037.5 million was approximately 18.8 percent of AE Supply’s total assets. As of December 31, 2001, the fair value of AE Supply’s commodity contracts with the CDWR of $1,320.9 million was approximately 22.6 percent of AE Supply’s total assets.

In June 2002, the EITF reached a consensus on Issue No. 02-3 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 was applicable to financial statements for periods ending after July 15, 2002. During 2002, AE Supply modified its reporting as a result of the EITF consensus to reflect the revenues from energy trading activities net of the cost of purchased energy and transmission related to contracts that require physical delivery. In addition, amounts for 2001 and 2000 were adjusted for comparability to reflect the adoption of the EITF consensus. As a result, AE Supply’s 2001 and 2000 operating revenues and cost of revenues are lower than previously reported, with no effect on consolidated net income.

The following table provides a reconciliation of the impact of previously reported amounts of operating revenues and cost of revenues as a result of the application of EITF Issue No. 02-3 (in millions):

The EITF also reached consensus on other related items, which will have the following effects on AE Supply:

The implementation of EITF Issue No. 02-3 will result in Allegheny recording a cumulative effect of an accounting change of approximately $11.9 million, net of income taxes ($19.7 million, before income taxes) in the first quarter of 2003. This charge will represent the fair value of those contracts previously accounted for under EITF Issue No. 98-10 that no longer qualify for mark-to-market accounting.

The identifiable assets acquired were recorded at estimated fair values at the date of acquisition. Consideration paid and assets acquired were as follows:

Effective January 1, 2002, AE Supply adopted SFAS No. 142 and, accordingly, ceased the amortization of goodwill and accounted for goodwill on an impairment-only approach. See Note 7 for additional information regarding AE Supply’s adoption of, and ongoing accounting related to, SFAS No. 142.

In the fourth quarter of 2002, circumstances surrounding the St. Joseph generating facility, a 630-MW merchant power plant under construction, indicated that the carrying amount of the facility would not be recoverable through operations. Allegheny, along with AE Supply, determined that the completion of the construction of the St. Joseph’s generating facility was not possible given its liquidity constraints and, therefore, could not proceed with the construction. AE Supply terminated construction of the St. Joseph’s generating facility and recorded an impairment charge, in accordance with SFAS No. 144, of $192.0 million, before income taxes ($118.4 million, net of income taxes). This impairment charge included amounts to record closure and cancellation costs associated with the facility.

On January 1, 2002, AE Supply adopted SFAS No. 141, “Business Combinations,” and SFAS No. 142. 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 AE Supply’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, AE Supply 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 AE Supply, SFAS No. 142 transitional provisions required AE Supply to test its goodwill for impairment as of January 1, 2002, and recognize any transitional goodwill impairment loss as the cumulative effect of a change in accounting principle. AE Supply completed its transitional goodwill impairment test, using a discounted cash flow methodology to determine the estimated fair value of its single reporting unit, which is the entity as a whole, and determined that there was no impairment of goodwill.

SFAS No. 142 transitional provisions also were completed with respect to AE Supply’s other intangible assets, resulting in no impairments or changes to amortizable lives.

Due to strategic changes announced by AE Supply and certain events affecting AE Supply in the third quarter of 2002, including the reduction of its wholesale energy trading activities, the cancellation of a number of generation projects, and the downgrade of AE Supply’s credit ratings by credit rating agencies, AE Supply initiated an impairment test of its goodwill. The impairment test used a discounted cash flow methodology to determine AE Supply’s fair value and indicated no impairment of goodwill. This test result reflects that AE Supply’s fleet of generating stations, comprised primarily of low-cost coal-fired steam generating stations, has a fair value in excess of the carrying value of those assets sufficient to cover the decline in value of its energy trading activities and the goodwill associated with the 2001 acquisition of the energy trading business.

AE Supply has other intangible assets consisting of amortized land easements, which are included in property, plant, and equipment on the consolidated balance sheet, with a gross carrying amount and accumulated amortization as follows: At December 31, 2002, $1.5 million and $.7 million, respectively, and at December 31, 2001, $1.5 million and $.6 million, respectively. Amortization expense for other intangible assets for 2002 and 2001 was $.1 million. Amortization expense is estimated to be $.1 million annually for 2003 through 2007.

If the provisions of SFAS No. 142 had been applied for 2001 and 2000, consolidated income before cumulative effect of accounting change and consolidated net income would have been as follows:

In July 2002, Allegheny Energy announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction and a reorganization of AE Supply’s trading division. For the year ended December 31, 2002, AE Supply recorded a charge for its allocable share of the workforce reduction expenses of $46.1 million, before income taxes ($28.2 million, net of income taxes). In addition, as a result of the restructuring, AE Supply recorded a charge of $7.9 million, before income taxes ($4.9 million, net of income tax) for impairment of leasehold improvements.

whose positions are being eliminated as part of the workforce reductions. The severance and other employee related costs are accounted for in accordance with 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).” For the year ended December 31, 2002, AE Supply recorded a charge of $24.7 million, before income taxes ($15.2 million, net of income taxes) for its allocable share of the effect of the SRSP related to approximately 80 of Allegheny’s employees whose positions have been or are being eliminated. Allegheny has essentially completed these planned workforce reductions. Workforce reduction costs are recorded in “Workforce reduction expense” on the consolidated statement of operations. The reorganization of AE Supply’s energy trading division included the relocation of the trading operations and resulted in a charge of approximately $20.2 million, before income taxes ($12.5 million, net of income taxes), related to costs associated with the relocation.

Effective January 1, 2001, AE Supply adopted SFAS No. 133, which established accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The standards require that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in earnings or other comprehensive income and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

On January 1, 2001, AE Supply recorded an asset of $1.5 million on its consolidated balance sheet based on the fair value of its two cash flow hedge contracts. An offsetting amount was recorded in other comprehensive income as a change in accounting principle as provided by SFAS No. 133. AE Supply’s risk management objectives regarding these cash flow hedge contracts were as follows: 1) to provide electricity in situations where the customers’ demand for electricity exceeded AE Supply’s electric generating capacity and 2) to protect AE Supply from price volatility for electricity.

The amounts accumulated in other comprehensive income related to these contracts were reclassified to earnings during July and August of 2001, when the hedged transactions were executed. As a result, a loss of $5.0 million, before income taxes ($3.1 million, net of income tax), was reclassified to purchased energy and transmission expense from other comprehensive income during the third quarter of 2001.

accumulated other comprehensive income for these treasury lock agreements over the life of the 10-year debt. For 2002, $.1 million, before income taxes ($.1 million, net of income taxes) was reclassified from accumulated other comprehensive income to earnings.

As of June 30, 2002, Allegheny recorded a liability in other current liabilities and an unrealized loss in operating revenues for derivative instruments of $5.2 million for seven wholesale electricity contracts. For the third quarter of 2002, AE Supply recorded an unrealized gain of $3.2 million for these contracts. In September 2002, AE Supply made operational changes regarding the delivery of electricity under these contracts. As a result, these contracts now qualify for the normal purchases and sales exception under SFAS No. 133.

The consolidated statement of comprehensive income provides the components of comprehensive (loss) income for the years ended December 31, 2002 and 2001. AE Supply had no elements of other comprehensive income for the year ended December 31, 2000.

For 2002, other comprehensive loss includes net unrealized losses of $1.7 million, before income taxes ($1.0 million, net of income taxes) and reclassifications to earnings of net realized losses of $.1 million, before income taxes ($.1 million, net of income taxes) for a total change in other comprehensive income of $1.6 million, before income taxes ($1.0 million, net of income taxes), for cash flow hedges. On January 1, 2001, AE Supply recorded an asset of $1.5 million on its consolidated balance sheet based on the fair value of its two cash flow hedge contracts and recorded an offsetting amount in other comprehensive income as a change in accounting principle in accordance with SFAS No. 133. The amounts accumulated in other comprehensive income related to these contracts were reclassified to earnings during July and August of 2001 when the hedged transactions were executed. As a result, a loss of $5.0 million, before income taxes ($3.1 million net of income taxes), was reclassified to purchased energy and transmission from other comprehensive income during the third quarter of 2001.

Members’ equity decreased by $476.4 million from January 1, 2002 to December 31, 2002 as a result of the following items: (1) a net loss during the year of ($583.8) million, (2) a dividend payment of approximately ($100) million, (3) unrealized loss on cash flow hedges of ($.9) million, (4) non-cash benefits associated with the supplemental employee retirement plan and other deferred compensation of approximately $13.4 million, and (5) a contribution of capital from AE of $194.9 million.

On March 16, 2001, AE Supply acquired Merrill Lynch’s energy trading business. AE Supply acquired this business for $489.2 million in cash plus the issuance of a 1.967 percent equity membership interest in AE Supply, effective June 29, 2001. As a result of an additional cash capital contribution from AE during the third quarter of 2002, Merrill Lynch’s equity membership decreased to 1.966 percent.

Members’ equity includes capital contributions related to West Penn, Potomac Edison, AYP Energy, and Monongahela generating asset transfers as described in Note 1 to the consolidated financial statements. Members’ equity also includes capital contributions from Allegheny of $2.0 million and $272.5 million in 2002 and 2001, respectively.

See Note 3, “Debt Financing and Liquidity Strategy,” for a description of the defaults under AE Supply’s current debt agreements. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was $1,747.8 million as of December 31, 2002.

Contractual maturities for debentures, notes and bonds in millions of dollars for the next five years, excluding unamortized debt discounts and premiums are: 2003, $114.3; 2004, $0; 2005, $0; 2006, $0; 2007, $507.3; and, thereafter, $1,341.4. Some properties of AE Supply are subject to a lien securing certain pollution control and solid waste disposal notes. See Note 24 for a discussion of the liens provided by AE Supply under the Borrowing Facilities that were entered into in February 2003.

AE Supply’s total long-term debt was $91.7 million as of December 31, 2002, and $1,349.1 million as of December 31, 2001.

During 2002, AE Supply redeemed $80.0 million of floating rate medium-term debt and $3.5 million of pollution control bonds per their original terms.

See Note 23, under “Leases,” for additional information regarding debt recorded on AE Supply’s consolidated balance sheet at December 31, 2002, from an operating lease transaction for a generating facility.

In June 2001, Monongahela and AE transferred generating assets to AE Supply totaling 523 MW. As part of this transfer, AE Supply’s members’ equity increased $173.8 million and long-term debt increased $15.9 million. In connection with the transfer of Monongahela’s Ohio and FERC jurisdictional generating assets, Monongahela continues to be co-obligor with respect to $15.9 million of pollution control debt.

On March 9, 2001, AE Supply issued $400.0 million of unsecured 7.80-percent notes due 2011 to pay for a portion of the cost of acquiring an energy trading business.

AE Supply may not directly or indirectly pay any dividend or make any distribution (by reduction of capital or otherwise), whether in cash, property, securities or a combination thereof, to any owner of a beneficial interest in AE Supply or otherwise with respect to any ownership or equity interest in, or, ownership security of AE Supply. AE Supply may not redeem, purchase, retire, or otherwise acquire for value any such ownership or equity interest or security and is also prohibited from setting aside or otherwise segregating any amounts for any such purpose.

The provision for income taxes for the cumulative effect of accounting change is different from the amount produced by applying the federal statutory income tax rate of 35 percent to the gross amount, as set forth below:

AE Supply recorded as deferred income tax assets the effect of net operating losses, which will be realized through future operations and through the reversal of existing temporary differences. These net operating loss carryforwards expire in varying amounts through 2022. In addition, AE Supply is a party to a consolidating tax sharing agreement and expects to realize benefits represented by deferred tax assets through its participation in the consolidated tax return in future years.

Total short-term income taxes receivable due from affiliates at December 31, 2002, was $66.9 million. Total short-term income taxes payable to affiliates at December 31, 2001, was $29.0 million. Total long-term income taxes payable to affiliates at December 31, 2002, was $18.2 million. There was no long-term income taxes receivable due from or payable to affiliates at December 31, 2001.

To provide interim financing, support for outstanding commercial paper, and the issuance of letters of credit to support general corporate purposes and energy trading activities, AE Supply had established lines of credit with several banks. These lines of credit had fee arrangements and no compensating balance requirements. At December 31, 2002, $894.9 million of the $965.0 million lines of credit with banks were drawn. Of the amount borrowed, $795.0 million and $99.9 million represented loans and letters of credit, respectively. All of the $70.1 million remaining lines of credit were unavailable to be drawn upon. At December 31, 2001, $61.6 million of the $705.0 million lines of credit with banks were drawn. Of the $643.4 million remaining lines of credit, $74.3 million was supporting commercial paper and $569.1 million was unused. These facilities, which were refinanced in February 2003, required the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio, as defined under the credit agreements. On October 8, 2002, Allegheny announced that AE, AE Supply, and AGC were in technical default under these facilities after AE Supply declined to post additional collateral in favor of several trading counterparties. As of December 31, 2002, AE Supply had obtained waivers and amendments for these facilities. See Note 24 for additional details regarding the Borrowing Facilities that were entered into in February 2003.

In addition to bank lines of credit, through August 2002 AE Supply, through its AGC subsidiary, participated in an Allegheny internal money pool, which accommodates intercompany short-term borrowing needs to the extent that certain of Allegheny’s subsidiaries have funds available. The money pool provides funds to approved Allegheny subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven-day commercial paper rate, as quoted by the same source, less four basis points. At December 31, 2001, AGC had borrowings outstanding from the money pool of $62.9 million. Excluding AGC, AE Supply has SEC authorization for total short-term borrowings in combination with AE, from all sources, of $4.0 billion. AGC has SEC authorization for total short-term borrowings, from all sources, of $100.0 million.

As described in Note 1, AE Supply is responsible for its proportionate share of the cost for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. AE Supply’s share of the (credits) costs, of which approximately 2 percent in 2002 was (credited) charged to plant construction, was as follows:

The carrying amounts and estimated fair value of financial instruments other than commodity contracts that were recorded at fair value in assets and liabilities at December 31, were as follows:

The carrying amount of temporary cash investments and short-term debt approximates the fair value because of the short maturities of those instruments. The fair value of debentures, notes and bonds was estimated based on actual market prices or market prices of similar issues.

AE Supply owns an interest in seven generating stations with Monongahela. Through June 2003, AE Supply also owned a 4.9 percent interest, approximately 83 MW, in coal-fired generating capacity of the Conemaugh

Generating Station near Johnstown, Pennsylvania. AE Supply records its proportionate share of operating costs, assets, and liabilities related to these generating facilities in the corresponding lines in the consolidated financial statements. As of December 31, 2002, AE Supply’s investment and accumulated depreciation in these generating stations were as follows:

Other income and expenses represent nonoperating revenues and expenses. The following table summarizes AE Supply’s other income and expense, net for 2002, 2001, and 2000:

In 2002, AE Supply recorded a gain of $1.2 million for the sale of approximately 150,000 Pennsylvania and Ohio retail customers to Dominion Retail, Inc., a subsidiary of Dominion Resources Inc.

AE Supply utilized the equity method of accounting for its investments in AGC through July 31, 2000. Effective August 1, 2000, AE Supply’s consolidated financial statements include the operations of AGC and the related minority interest because AE Supply’s ownership increased from 45% to 73%.

Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for AE Supply and its affiliates in accordance with PUHCA. Through AESC, AE Supply is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to AE Supply for 2002, 2001, and 2000 were $238.5 million, $121.7 million, and $95.3 million, respectively.

AE Supply supplies electricity to its regulated utility affiliates, West Penn, Potomac Edison, and Monongahela Power, in accordance with agreements approved by the FERC, to meet their retail load requirements as the default provider during the transition periods for deregulation plans approved in

Pennsylvania, Maryland, Virginia, West Virginia and Ohio. For 2002, 2001, and 2000, revenues from these sales were $1,159.6 million, $1,116.2 million, and $761.2 million, respectively. Prior to Allegheny joining PJM Interconnection, LLC (PJM) in April 2002, if AE Supply sold more electricity to its regulated affiliates, under PLR Agreements, than was needed to serve their customers, the excess electricity sold was purchased back by AE Supply and is reflected in “Purchased energy and transmission” on the consolidated statement of operations. Upon Allegheny joining PJM, operational changes were made so that AE Supply no longer has excess electricity to buy back from its regulated affiliates under these PLR Agreements. For 2002, 2001, and 2000, AE Supply purchased back excess electricity from its regulated affiliates of $15.9 million, $43.0 million, and $21.9 million, respectively.

In November 2001, AE Supply entered into an agreement with Potomac Edison to purchase 180 MW of unit contingent capacity, energy, and ancillary services from January 1, 2002, through December 31, 2004, related to the AES Warrior Run generation facility. The cost of purchasing power under this contract is reported net of associated energy trading revenues in “Total operating revenues” on the consolidated statement of operations in accordance with EITF Issue No. 02-3.

During 2001 and 2000, AE Supply recorded $9.4 million and $10.0 million, respectively, of competitive transition charge (CTC) revenue related to West Penn’s deregulation plan approved by the Pennsylvania PUC. The Pennsylvania PUC authorized West Penn to collect from its customers CTC revenue to recover transition costs, including certain costs of generating assets. Since West Penn’s generating assets were transferred to AE Supply in November 1999, the related CTC revenue was also transferred to AE Supply since November 1999.

In conjunction with the transfer of the generating assets of West Penn, Potomac Edison, and Monongahela Power to AE Supply, AE Supply assumed $350.9 million of pollution control debt. As of December 31, 2002, West Penn was a guarantor of $216.4 million, Potomac Edison was a guarantor of $101.0 million, and Monongahela Power is a co-obligor of $15.6 million of this pollution control debt.

The transfer of Potomac Edison’s generating assets to AE Supply, 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. The original lease term was for one year. AE Supply and Potomac Edison have mutually agreed to continue the lease beyond August 1, 2001. The Ohio and FERC jurisdictional generating assets transferred to AE Supply on June 1, 2001, have been leased back to Monongahela. The lease was effective on June 1, 2001, for a term of one year and renews automatically. Rental income from these leases was $149.6 million, $75.2 million, and $37.1 million in 2002, 2001, and 2000, respectively.

AE Supply and its affiliate, Monongahela Power, own certain generating assets jointly as tenants in common. The assets are operated by AE Supply, with each of the owners being entitled to the available energy output and capacity in proportion to its ownership in the assets. Monongahela Power does the billing for the jointly owned stations located in West Virginia, while AE Supply is responsible for billing Hatfield’s Ferry Power Station, a Pennsylvania station. See Note 17 for additional information regarding jointly owned electric utility plants.

At December 31, 2002 and 2001, AE Supply had net accounts payable to affiliates of $48.0 million and net accounts receivable from affiliates of $53.2 million, respectively.

See Note 13 for information regarding affiliated income taxes payable associated with AE Supply’s inclusion in Allegheny’s consolidated federal income tax return.

No generating assets were transferred to AE Supply by AE or an affiliate during 2002.

During 2001, the following transfers of generating assets to AE Supply occurred:

The quarterly amounts included in the table above reflect the adjustments identified in Allegheny’s comprehensive financial review, as discussed in Note 2. The following table summarizes the effect of the adjustments on amounts previously reported for AE Supply’s first and second quarter 2002 total operating revenues, net revenues, operating income, consolidated net (loss) income before cumulative effect of accounting change, and consolidated (loss) income before cumulative effect of accounting change, and consolidated net (loss) income. The amounts shown as previously reported for total operating revenues reflect certain reclassifications to comply with EITF Issue No. 02-3 as discussed in Note 4, and for net revenues and operating income, reflect reclassifications made in AE Supply’s presentation of its statement of operations after the Forms 10-Q for the first and second quarters of 2002 were filed. The reclassifications, were made to provide consistent presentations among Allegheny’s various SEC registrants. In aggregate, the reclassifications had no effect on previously reported consolidated (loss) income before cumulative effect of accounting change and consolidated net (loss) income.

The corrections of accounting errors related to the first and second quarters of 2002 were primarily as follows:

Had AE Supply adjusted 2001 for the correction of the accounting errors discussed in Note 2 that were recorded in the first quarter of 2002, the 2001 quarterly consolidated income before cumulative effect of accounting change and net income would have been as follows:

SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets, was adopted by AE Supply on January 1, 2003. SFAS No. 143 requires that the fair value of asset retirement costs for which AE Supply has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or records a gain or loss if settled at a different amount.

AE Supply has completed a detailed assessment of the specific applicability of SFAS No. 143 and recorded retirement obligations primarily related to ash landfills and underground and aboveground storage tanks. AE Supply also has identified a number of retirement obligations associated with certain other assets that have not been recorded, because the fair value of such obligations cannot be reasonably estimated, due primarily to the indeterminate lives of the assets.

The effect of adopting SFAS No. 143, effective January 1, 2003, on AE Supply’s consolidated statement of operations will be a cumulative effect adjustment to decrease net income by $7.3 million ($11.9 million, before income taxes). The effect of adopting SFAS No. 143 on AE Supply’s consolidated balance sheet will be a $.3 million increase in property, plant, and equipment, net and the recognition of a $12.2 million liability for asset retirement obligations.

See Note 4 for the effect of AE Supply’s adoption of EITF Issue No. 02-3. See Note 23, under “Guarantees” and “Variable Interest Entities,” for the effect of Allegheny’s adoption of FASB Interpretation Nos. (FIN) 45 and 46, respectively.

AE Supply has entered into commitments for its construction and capital programs for which expenditures are estimated to be $186.4 million (unaudited) for 2003 and $109.4 million (unaudited) for 2004. Construction expenditure levels in 2005 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 (CAAA) and the extent to which environmental initiatives currently being considered become mandated. AE Supply estimates that its management of emission allowances will allow it to comply with Phase II sulfur dioxide (SO₂) limits through 2005. Studies to evaluate cost-effective options to comply with Phase II SO₂ limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.

In 2002, AE Supply announced a series of initiatives to preserve cash and reduce expenses and respond to the challenges it faces in the current marketplace. These initiatives included the cancellation of several generation projects resulting in a write-off of $244.0 million, before income taxes. See Note 6 for additional information regarding asset impairments.

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

Supply is in the process of installing NO_x controls to meet the Pennsylvania, Maryland, and West Virginia SIP. AE also has the option to purchase, in some cases, alternate fuels, NO_x allowances, or power on the market, if needed, to supplement our compliance strategy. AE Supply expects to be in compliance with NO_x limits established by the SIP. AE Supply’s construction forecast includes the expenditure of $45.6 million (unaudited) of capital costs during the 2003 through 2004 period to comply with these regulations.

Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in most cases. AE believes that its subsidiaries’ generating facilities have been operated in accordance with the Clean Air Act and the rules implementing it. The experience of other energy companies, however, suggests that in recent years, the EPA has narrowed its view regarding the scope of the definition of “routine maintenance” under its rules, thereby broadening the range of actions subject to compliance with new source review standards. Under previous EPA interpretations these same actions did not trigger application of those standards. Section 114 information requests concerning facility modifications are often followed by enforcement actions. The EPA contacted AE and requested a meeting, which was held on July 16, 2003. Additional meetings will likely be scheduled in the next few months. At this time, AE is not able to determine what effect the EPA’s inquiry may have on its operations. If new source review standards are applied to AE generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. However, the recent preliminary judicial decision in the EPA vs. Duke energy case, as well as the final Routine Maintenance, Repair and Replacement Rule recently released by the EPA, are more consistent with the energy industry’s historical compliance approach. Therefore, at this time, AE and its subsidiaries are not able to determine the effect these actions may have on them with regard to compliance costs.

The Attorneys General of New York and Connecticut, in letters dated September 15, 1999, and November 3, 1999, respectively, notified AE of their intent to commence civil actions against AE and/or its subsidiaries alleging violations at the Fort Martin Power Station under the Clear Air Act, which requires power plants that make major modifications to comply with the same New Source Review emission standards appreciable to new power plants. Other governmental agencies may commence similar actions in the future. Fort Martin Power Station is located in West Virginia and is now jointly owned by AE Supply and Monongahela. Both Attorneys General stated their intent to seek injunctive relief and penalties. In addition, the Attorney General of the State of New York indicated that he may 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, AE and its subsidiaries are not able to determine what effect, if any, these actions may have on them.

NPC, and entered into under the Western Systems Power Pool Master Agreement. The transactions related to power sales during 2002. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with AE Supply under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers.

Sierra/Nevada: On April 2, 2003, NPC and Sierra Pacific Resources, Inc., (together Sierra/Nevada) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, Merrill). The complaint alleged that Allegheny and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (Nevada PUC) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180.0 million of NPC’s deferred energy expenses. Sierra/Nevada asserted three causes of action against Allegheny arising from the alleged fraudulent conduct. These include: (1) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages, (2) conspiracy, and (3) violations of the Nevada state RICO act. Sierra/Nevada filed an amended complaint on May 30, 2003 in which they assert a fourth cause of action against Allegheny for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys fees. Under the RICO count, Sierra/Nevada seeks in excess of $850 million.

Settlement of Litigation Related to Power Supply Contracts with the CDWR: In March and April 2001 AE Supply entered into two ten-year power sales agreements pursuant to a master power purchase and sale agreement (together the CDWR contract) with the CDWR, the electricity buyer for the state of California. The CDWR contract constituted one of Allegheny’s key assets. In February 2002, the California Public Utilities Commission (California PUC) and the California Electricity Oversight Board (CAEOB) filed complaints with the FERC seeking to abrogate the contracts. In January 2003, the CDWR filed a lawsuit in California Superior Court alleging that AE Supply breached the contracts, and seeking a judicial determination that the contracts were terminated along with monetary damages.

settlement terms also reduce the volume of power to be purchased from 1,000 MW from 2005-2011 to 750 MW in 2005 and 800 from 2006 through 2011. The renegotiated contract also states that the parties waive all rights to challenge the validity of the agreement or whether it is just and reasonable for its duration. These modifications significantly reduced the value of the CDWR contract, in the range of $160-$190 million. The terms of the settlement also provide that the California PUC and CAEOB agree to drop their complaints against AE Supply at FERC, and CDWR and the California Attorney General agree to drop their lawsuit filed in California Superior Court. The parties agreed that all litigation will be withdrawn with prejudice.

Nine related putative class action lawsuits against AE Supply, and more than two dozen other named defendant power suppliers were filed in various California superior courts during 2002. These class action suits were removed to federal court and transferred to the U.S. District Court for the Southern District of California. Eight of the suits were commenced by consumers of wholesale electricity in California. The ninth, Millar v. Allegheny Energy Supply Co., et al., was filed on behalf of California taxpayers. The complaints allege, among other things, that AE Supply and the other defendant power suppliers violated California’s antitrust statute and the California unfair business practices statute by allegedly manipulating the California electricity market over a period of years. The suits also challenge the validity of various long-term power contracts with the State of California, including the CDWR contract.

On August 25, 2003, AE Supply’s motion to dismiss seven of the eight consumer class actions with prejudice was granted by the U.S. District Court. AE Supply has not been served in the eighth consumer class action, Kurtz v. Duke Energy Trading and Marketing, LLC. This case is still pending in the U.S. District Court. The allegations in this complaint are substantively identical to those in the dismissed actions.

The Gleason Facility has demanded indemnification and a defense from Siemens Westinghouse, the manufacturer of the turbines used in the facility, pursuant to the terms of the equipment purchase agreement. On October 17, 2002, Siemens Westinghouse filed a request for a declaratory judgment in the Court of Common Pleas of Allegheny County, Pennsylvania seeking a declaration that the prior owner released Siemens Westinghouse from this liability through a release executed after Allegheny purchased the Gleason facility.

AE has also undertaken property purchases and other mitigation measures. AE cannot predict the outcome of this suit or whether it will be able to recover amounts from Siemens Westinghouse.

Litigation Against Merrill Lynch: AE and AE Supply entered into an asset purchase agreement with Merrill Lynch and affiliated parties in 2001 whereby AE and AE Supply purchased Merrill Lynch’s energy marketing and trading business for approximately $489 million and an equity interest in AE Supply of nearly two percent. The asset purchase agreement provides that Merrill Lynch would have the right to require AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest calculated from March 16, 2001, in the event that certain conditions were not met.

On October 23, 2002, AE filed a motion to stay Merrill Lynch’s federal court action in favor of AE and AE’s action in New York state court. On May 29, 2003, the United States District Court for the Southern District of New York denied AE’s motion to stay Merrill Lynch’s action and ordered that AE and AE Supply assert its claims against Merrill Lynch, which were initially brought in New York State Court as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply dismissed its New York State action and, on June 13, 2003, AE and AE Supply filed counterclaims against Merrill Lynch in the United States District Court for the Southern District of New York. Much like AE and AE Supply’s complaint in New York state court, the counterclaims allege that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims seek damages in excess of $605 million and rescission of the agreement, among other relief. Merrill Lynch has moved to dismiss Allegheny’s counterclaims. On August 29, 2003, AE and AE Supply filed amended counterclaims that, among other things, add a claim against Merrill Lynch for negligent misrepresentation, and have opposed the motion to dismiss. AE and AE Supply cannot predict the outcome of this suit.

EPMI Adversary Proceeding: On May 9, 2003, Enron Power Marketing, Inc. (EPMI), a Chapter 11 debtor, commenced an adversary proceeding against AE Supply in its bankruptcy case that is pending in the U.S. Bankruptcy Court for the Southern District of New York. The complaint alleges that AE Supply owes EPMI (1) $27,646,725 for accounts receivable due and owing for energy delivered prior to the commencement of EPMI’s bankruptcy case and (2) $8,250,000 in cash collateral previously posted by EPMI to AE Supply, less any amounts owed to AE Supply as a result of EPMI’s default under a master trading agreement entered into between the parties and certain transactions arising thereunder. By the complaint, EPMI also seeks certain declaratory

relief, including a declaration that the arbitration provision found in the master trading agreement is unenforceable. On August 1, 2003, AE Supply filed an answer asserting affirmative defenses. AE Supply is unable to predict the outcome of this matter.

In the normal course of business, AE Supply becomes involved in various other legal proceedings. AE Supply does not believe that the ultimate outcome of these proceedings will have a material effect on its consolidated financial position, results of operation and cash flows.

AE Supply has operating lease agreements with various terms and expiration dates, primarily for vehicles and electric generation facilities.

Total operating lease rent payments of $14.6 million in 2002, $14.5 million in 2001, and $6.5 million in 2000 were recorded as rent expense. Estimated minimum lease payments for operating leases with annual rent exceeding $100,000 and initial or remaining lease terms in excess of one year are $17.8 million in 2003, $28.4 million in 2004, $301.1 million in 2005, $4.5 million in 2006, $4.5 million in 2007, and $33.6 million thereafter.

In November 2001, AE Supply entered into an operating lease transaction to finance construction of a 630-MW generating facility in St. Joseph County, Indiana. As of December 31, 2002, AE Supply recorded the facility on its consolidated balance sheet as it was deemed the owner of the facility under EITF Issue No. 97-10, “The Effect of Lessee Involvement in Asset Construction,” as a result of lessor reimbursement for construction expenditures. As a result, AE Supply recorded approximately $415.5 million of debt related to this obligation, including costs associated with terminating the project, on its consolidated balance sheet at December 31, 2002. In February 2003, AE Supply purchased the project by assuming $380.0 million of the lessor’s long-term debt and paying an additional $35.5 million financed with debt. Following the purchase of the facility, Allegheny terminated the project resulting in a write-off of $192.0 million, before income taxes ($118.4 million, net of income taxes).

prior to January 31, 2003, AE Supply will be required to consolidate all variable interest entities in which it is the primary beneficiary, as of the third quarter of 2003. Other than the generating facility in Springdale, Pennsylvania, which was purchased in February 2003 and subsequently consolidated, AE Supply does not believe that FIN 46 will have a material effect on its consolidated results of operations and financial position.

AE Supply has entered into various long-term commitments for the procurement of fuel, primarily coal and lime, to supply its generating facilities. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. AE Supply’s fuel consumed for electric generation was $462.7 million, $424.6 million, and $305.7 million in 2002, 2001, and 2000, respectively. In 2002, AE Supply purchased approximately 59.2 percent of its fuel from one vendor. Total estimated long-term coal and lime obligations at December 31, 2002, were as follows:

Letters of credit are purchased guarantees that ensure AE Supply’s performance or payment to third parties, in accordance with certain terms and conditions, and amounted to $99.9 million as of December 31, 2002.

In November 2002, the FASB issued FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others,” which requires disclosures by a guarantor concerning its obligations under certain guarantees that it has issued. FIN 45 also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issued or modified after December 31, 2002. AE Supply does not anticipate FIN 45 will have a material effect on its consolidated results of operations and financial position.

At December 31, 2002, AE Supply and its subsidiaries provide guarantees, either directly or indirectly, of $35.0 million for their contractual obligations. Approximately $31.9 million relate to equipment purchase and sale agreements. An additional $3.1 million are for the purchase, sale, exchange, or transportation of wholesale natural gas, electric power, and related services. Under the terms of the guarantees, AE Supply would be required to perform should an affiliate be in default of its obligation, generally for an amount not to exceed the amount disclosed. Additionally, the term of these guarantees, in general, coincide with the term of the underlying agreement. There are no amounts being carried as liabilities for AE Supply’s obligations under these guarantees.

MW coal-fired generating facility and a 44 MW gas-fired combustion turbine. This amendment provides a put option that allows UGI to require AE Supply to purchase either or both the existing coal-fired facility and combustion turbine owned by Hunlock Creek for a specified purchase price. AE is currently a 50% owner in Hunlock Creek. The amendment provides a purchase price for the coal-fired facility equivalent to full value of $15 million, plus the value of all related inventory. The purchase price for the combustion turbine will be made at its book value at the time of exercise of the option. The option can be exercised for a period of 90 days commencing January 1, 2006.

In addition, $380.0 million of debt associated with the discontinued generating project in St. Joseph, Indiana, in the form of A-Notes, was restructured and assumed by AE Supply. Of this debt, $343.7 million is initially secured by substantially all the assets of AE Supply, except for its new generating facility in Springdale, Pennsylvania. The secured portion of this debt bears an interest rate of 10.25 percent and the unsecured portion bears interest at 13.0 percent. This debt matures in November 2007.

The $420.0 million committed and borrowed by AE Supply under the $470.0-million facility represents new liquidity, and the remaining facilities and restructured A-Notes represented refinanced indebtedness. The Borrowing Facilities at AE Supply also refinanced $1,637.8 million of existing debt and letters of credit, including $894.9 million outstanding under various credit agreements, and $270.1 million outstanding for AE Supply’s new generating facility in Springdale, Pennsylvania.

AE Supply borrowed $2,057.8 million under the Borrowing Facilities and the restructured A-notes. Until August 1, 2003, after certain conditions associated with securing the collateral under the Borrowing Facilities

were met on July 19, 2003, the LIBOR component charged AE Supply under the Borrowing Facilities with respect to secured borrowings had a two-percent floor. Also, since AE Supply was unable to secure all of the borrowing Facilities and the restructured A-Note debt before July 31, 2003, the interest rates charged on the amounts not so secured increased to a spread of 10.5 percent over the applicable LIBOR or the designated money center bank’s base rate for the Refinancing Credit Facility and the Springdale Credit Facility and 13.0 percent for the unsecured portion of the A-Note debt retroactively to February 25, 2003. The total amounts unsecured under the Refinancing Credit Facility, the Springdale Credit Facility and the A-Note debt are approximately $94.3 million, $175.8 million and $36.3 million respectively. A 30 percent limitation of available secured debt in AE Supply’s indenture will also make it difficult, if not impossible, for AE Supply to borrow additional funds until some of the secured debt under the Borrowing Facilities is repaid.

The interest rate margins payable by AE Supply under certain of the Borrowing Facilities are tied to AE Supply’s credit ratings. Should AE Supply’s credit ratings improve from its current ratings of B2 by Moody’s, B by Standard and Poor’s, and B+ by Fitch to certain specified higher ratings, the rate of interest AE Supply would be required to pay under the Refinancing Credit Facility and the Springdale Credit Facility could decrease by .5 percent to 1.0 percent for the secured portion of those credit facilities. AE Supply’s credit ratings would need to improve to BB/Ba2 to achieve a .5 percent decrease in the interest rates and BB+/Bal or higher to achieve a 1.0 percent decrease in the interest rates.

AE Supply is required to meet certain financial tests, as defined in the Borrowing Facilities agreements, including:

The Borrowing Facilities for AE Supply also have provisions requiring prepayments out of the proceeds of asset sales and debt and equity issuances, as follows:

The Borrowing Facilities also contain restrictive covenants that limit AE Supply’s ability to: borrow funds; incur liens; enter into a merger or other change of control transaction; make investments; prepay indebtedness; amend contracts; pay dividends and other distributions on AE Supply’s equity; and operate AE Supply’s business by requiring it to adhere to an agreed business plan.

The management of Allegheny Energy Supply Company, LLC (the Company), a wholly-owned subsidiary of Allegheny Energy, Inc. (Allegheny), is responsible for the information and representations in the Company’s financial statements. The Company prepares the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management’s best estimates and judgments of known conditions.

The Company is responsible for maintaining an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Company’s assets are protected. As discussed in Item 14 of Allegheny Annual Report on Form 10-K, Allegheny’s management has concluded that Allegheny’s internal controls are not adequate. Management and the Audit Committee of the Board of Directors of Allegheny committed to devoting the additional resources necessary to ensure that the Company’s reporting is accurate until internal controls are improved and are adequate.

Allegheny’s staff of internal auditors conducts periodic reviews designed to assist management in maintaining effective internal control procedures. PricewaterhouseCoopers LLP, an independent accounting firm, audits the financial statements and expresses its opinion on them. The independent auditors perform their audit in accordance with auditing standards generally accepted in the United States of America.

The Audit Committee of the Board of Directors of Allegheny, which consists of outside Directors, meets regularly with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff of Allegheny and PricewaterhouseCoopers LLP have free access to all of the Company’s records and to the Audit Committee.

In our opinion, the accompanying consolidated balance sheets, consolidated statements of capitalization and the related consolidated statements of operations, cash flows and comprehensive income, present fairly, in all material respects, the financial position of Allegheny Energy Supply Company, LLC and its subsidiaries (the Company) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the financial statements, the consolidated balance sheet as of December 31, 2001, has been restated.

As discussed in Note 7 to the financial statements, on January 1, 2002, the Company adopted Financial Accounting Standards Board Statement No. 142, “Goodwill and Other Intangible Assets.”

Monongahela Power Company (Monongahela) is a wholly-owned subsidiary of Allegheny Energy, Inc. (AE, and collectively with AE’s consolidated subsidiaries, Allegheny) and along with its wholly-owned subsidiary Mountaineer Gas Company (Mountaineer) and its regulated utility affiliates, The Potomac Edison Company (Potomac Edison) and West Penn Power Company (West Penn), collectively doing business as Allegheny Power, operate electric and natural gas transmission and distribution (T&D) systems. Monongahela’s business is the operation of electric T&D systems in Ohio and West Virginia, the operation of natural gas T&D systems in West Virginia, and the generation of electric energy for its West Virginia jurisdiction. In 2002, Monongahela aligned its businesses into two principal business segments. The Generation and Marketing segment is comprised of Monongahela’s electric generation. The Delivery and Services segment is comprised of Monongahela’s electric and natural gas T&D systems.

Monongahela is subject to regulation by the Securities and Exchange Commission (SEC), the Public Service Commission of West Virginia (West Virginia PSC), the Public Utilities Commission of Ohio (Ohio PUC), and the Federal Energy Regulatory Commission (FERC).

Certain amounts in the December 31, 2001, consolidated balance sheet and in the December 31, 2001, and 2000, consolidated statements of operations and consolidated statements of cash flows have been reclassified for comparative purposes. Significant accounting policies of Monongahela and its subsidiaries are summarized below.

The preparation of financial statements in conformity with generally accepted accounting principles of the United States of America (GAAP) requires Monongahela to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. On a continuous basis, Monongahela evaluates its estimates, including those related to the calculation of unbilled revenues, provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits, and contingencies related to environmental matters and litigation. Monongahela bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

The consolidated financial statements reflect investments in controlled subsidiaries on a consolidated basis. The consolidated financial statements include the accounts of Monongahela and all subsidiary companies after elimination of intercompany transactions and balances, and are prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of the FERC and applicable state regulatory commissions.

Revenues from the sale of electricity and natural gas to customers are recognized in the period that the electricity and natural gas are delivered and consumed by customers, including an estimate for unbilled revenues.

Natural gas production revenue is recognized as income when the natural gas is extracted, delivered and sold.

The difference between the costs of fuel, purchased energy, and certain other costs and revenues from electric utility purchases from or sales to other utilities and power marketers, including transmission services, and fuel related revenues billed to customers has historically been deferred until it is either recovered from or credited to customers under fuel and energy cost-recovery procedures in West Virginia and Ohio. Effective July 1, 2000, in West Virginia and January 1, 2001, in Ohio, fuel and purchased energy costs for Monongahela’s electric operations have been expensed as incurred as a result of the elimination of deferred energy cost mechanisms by Monongahela’s state regulatory bodies.

The difference between natural gas supply costs incurred, including the cost of natural gas transmission and transportation within the former West Virginia Power Company (WVP) territory, acquired in 1999, and natural gas cost revenues collected from customers are deferred until recovered from or credited to customers under a Purchased Gas Adjustment (PGA) clause in effect for this operation in West Virginia. Prior to November 1, 2001, the cost of natural gas for Mountaineer was expensed as incurred. Effective November 1, 2001, Mountaineer returned to the PGA mechanism.

Property, plant, and equipment are stated at original cost. Costs include direct labor and materials; allowance for funds used during construction (AFUDC) on the Delivery and Services segment’s regulated property for which construction work in progress is not included in rate base; and indirect costs such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes, and other benefits related to employees engaged in construction.

Upon retirement, the cost of depreciable regulated property, plus removal costs less salvage, are charged to accumulated depreciation in accordance with the provisions of Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”

As required by Emerging Issues Task Force (EITF) Issue No. 97-4, “Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statement Nos. 71 and 101,” Monongahela discontinued the application of SFAS No. 71 for its West Virginia jurisdiction’s electric generation operations in the first quarter of 2000 and for its Ohio jurisdiction’s electric generation operations in the fourth quarter of 2000. See “West Virginia Regulation” in Note 10 for additional information. Monongahela’s Ohio and FERC jurisdictional generating assets were transferred to Allegheny Energy Supply Company, LLC (AE Supply), Allegheny’s unregulated generation subsidiary, at book value on June 1, 2001.

Monongahela consolidates its proportionate interest in the electric generating stations it owns jointly with AE Supply.

Monongahela capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over the expected useful life of the software beginning upon a project’s completion.

Monongahela accounts for its natural gas exploration and production activities under the successful efforts method of accounting. The cost of Monongahela’s natural gas wells is being depleted utilizing the units of production method.

Monongahela adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. Long-lived assets owned by Monongahela are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, resulting in the asset being written down to its fair value. The fair value is determined by the use of quoted market prices, appraisals, or the use of other valuation techniques, such as expected discounted future cash flows.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized

AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is recognized as a cost of the Delivery and Services segment’s regulated property, plant, and equipment. Rates used for computing AFUDC in 2002, 2001, and 2000 averaged 8.97 percent, 8.42 percent, and 7.83 percent, respectively.

For the Generation and Marketing segment’s construction, starting on June 1, 2001, Monongahela has capitalized interest costs in accordance with SFAS No. 34, “Capitalization of Interest Costs.” The interest capitalization rates in 2002, 2001, and 2000 were 6.14 percent, 7.14 percent, and 7.07 percent, respectively. Monongahela capitalized $13.6 million of interest during 2002.

Depreciation expense is determined generally on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 3.1 percent of average depreciable property in 2002, 3.0 percent in 2001, and 3.3 percent in 2000. Estimated service lives for generation property range from four to 40 years, T&D property range from 15 to 58 years, and all other property range from 10 to 46 years. The Delivery and Services segment’s depreciation expense was $40.0 million, $39.2 million, and $32.6 million for 2002, 2001, and 2000, respectively. The Generation and Marketing segment’s depreciation expense was $32.0 million, $33.6 million, and $36.3 million for 2002, 2001, and 2000, respectively. Depreciation expense is provided for under currently enacted regulatory rates.

Maintenance expenses represent costs incurred to maintain the power stations, the electric and natural gas T&D systems, and general plant, and reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage to the T&D system. Maintenance costs are expensed in the year incurred.

Monongahela records the acquisition cost in excess of fair value of tangible and intangible assets acquired, less liabilities assumed, as goodwill. See Note 4 for additional information regarding Monongahela’s recent

acquisitions. Effective January 1, 2002, with the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets,” Monongahela recognized an impairment loss for all of its goodwill. SFAS No. 142 also requires that other intangible assets with indefinite lives not be amortized, but, rather, be tested for impairment at least annually. Other intangible assets with finite lives are to be amortized over their useful lives and tested for impairment when events or circumstances warrant. See Note 5 for additional information regarding Monongahela’s adoption of SFAS No. 142.

Equity investments are recorded using the equity method of accounting, if the investment gives Monongahela the ability to exercise significant influence, but not control, over the investee. The income or loss from unregulated investments is recorded in other income and expenses in the consolidated statement of operations.

For purposes of the consolidated statements of cash flows, temporary cash investments, with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, and repurchase agreements, are considered to be the equivalent of cash.

Monongahela has various operating transactions with affiliates. It is Monongahela’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented net on the consolidated balance sheet and the consolidated statement of cash flows. See Note 19 for additional information on related party transactions.

In accordance with SFAS No. 71, Monongahela’s consolidated financial statements include certain assets and liabilities resulting from cost-based ratemaking regulation.

Monongahela joins with Allegheny and its affiliates in filing a consolidated federal income tax return. The consolidated income 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 income tax liability.

Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the financial statement and tax basis of assets and liabilities computed using the most current tax rates. See Note 11 for additional information regarding income taxes.

Monongahela has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant, and equipment.

affiliates in accordance with PUHCA. Through AESC, Monongahela is responsible for its proportionate share of postretirement benefit costs.

AESC provides a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on each employee’s years of service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities, short-term investments, and insurance contracts.

AESC also provides partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993. The funding policy is to contribute the maximum amount that can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self-insured.

Effective August 18, 2000, the Mountaineer pension plan was merged with the AESC plan, and the pension plan assets were transferred to the AESC plan. The formula for pension benefits changed for nonunion employees but remained unchanged for union employees. For postretirement benefits other than pensions, Mountaineer nonunion employees became eligible for the benefits provided by AESC on January 1, 2001, and union employees continued their coverage under Mountaineer provisions. The employees remained employees of Mountaineer through December 31, 2000, at which time they were transferred to AESC.

Monongahela does not have any elements of other comprehensive income to report in accordance with SFAS No. 130, “Reporting Comprehensive Income.”

As a result of Allegheny’s comprehensive accounting review, Allegheny identified, prior to closing its books for 2002, various errors relating to the financial statements for 2001, 2000, and years prior to 2000. Allegheny’s management concluded that these errors for Monongahela were not material, either individually or in the aggregate, to the current year or any prior year’s financial statements. Accordingly, prior year financial statements have not been restated. These adjustments related to Monongahela, which increase the 2002 net loss, aggregate approximately $6.3 million, net of income taxes, and have been recorded in the first quarter of 2002. The nature and amounts of these adjustments are primarily as follows:

The years to which the (charges) to income, net of income taxes, relate are as follows:

While certain changes in policies and procedures have been instituted, additional changes are needed to improve the internal control structure of Allegheny.

Allegheny’s Management, Audit Committee, and Board of Directors are fully committed to the resolution of Allegheny’s internal control deficiencies. Ultimate resolution of the deficiencies will include changing the culture of the accounting function to focus on accountability and the strict, timely adherence to a set of sound internal control policies and procedures. Management has commenced or is undertaking the following corrective actions in order to achieve an immediate improvement in the controls environment:

Monongahela had several debt agreements that required it to file copies of its annual or quarterly reports as filed with the SEC pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) with the debt holders. Monongahela is also required to deliver to the trustees under its indentures a certificate indicating that Monongahela has complied with all conditions and covenants under the agreements. On April 30, 2003, Monongahela provided certificates to the trustee under its indentures indicating that it was not in compliance with the covenants for filing its annual and quarterly reports that are contained in its First Mortgage Bonds and Medium Term Notes. The covenant breaches with respect to the First Mortgage Bonds and Medium Term Notes are deemed defaults of the related debt agreements, as well as defaults under agreements governing certain other of Monongahela’s indebtedness, primarily its Pollution Control Bonds, that contain cross-acceleration provisions with the First Mortgage Bonds, for Monongahela’s financial reporting purposes in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived by the Creditor.”. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was approximately $600.1 million as of December 31, 2002. To date, the debtholders have not provided Monongahela with any notices of default under the agreements. Such notices, if received, would allow Monongahela 60 days to cure its noncompliance before the debtholders could accelerate the due dates of the debt obligations.

As of December 31, 2002, $90.0 million was outstanding under two Mountaineer Note Purchase Agreements. These Note Purchase Agreements contain covenants that required Mountaineer to deliver annual financial statements, an audited 2002 annual report, and certain certificates to the noteholders by March 31, 2003. Mountaineer did not deliver these items to the noteholders by March 31, 2003. Effective July 23, 2003, Mountaineer obtained waivers extending the covenant due dates until September 30, 2003, for the 2002 annual audited financial statements. Also, Mountaineer has obtained waivers until October 31, 2003, and December 1, 2003, for the delivery of its unaudited financial statements to the noteholders for the first and second quarters of 2003, respectively. These amounts have also been classified as a current liability on the consolidated balance sheet as of December 31, 2002.

Monongahela has prepared its financial statements assuming that it will continue as a going concern. However, noncompliance with its debt covenants and the classification of certain debt as current has caused its independent auditors, PricewaterhouseCoopers LLP to issue a modified opinion that indicates there is substantial doubt about Monongahela’s ability to continue as a going concern (a “Going Concern” opinion). The financial statements do not include any adjustments that might result from the resolution of this uncertainty. Management’s plan with respect to this matter is discussed below.

In 2003, Monongahela’s cash flows are expected to be adequate to meet all of its payment obligations under the First Mortgage Bonds and Pollution Control Bonds, and to fund other liquidity needs. Monongahela’s ability to meet its payment obligations under its First Mortgage Bonds, Medium Term Notes and Pollution Control Bonds and to fund capital expenditures will depend on its future performance. Monongahela’s future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control.

Management plans to file its Annual Report on Form 10-K for the period ended December 31, 2003 on a timely basis.

On August 18, 2000, Monongahela completed the purchase of Mountaineer, a natural gas sales and T&D company serving southern West Virginia and the northern and eastern panhandles of West Virginia, from Energy Corporation of America (ECA) for approximately $325.7 million, including the assumption of $100.1 million of existing long-term debt. The acquisition included the assets of Mountaineer Gas Services, Inc. (MGS), which operates natural gas-producing properties, natural gas-gathering facilities, and intrastate transmission pipelines. The acquisition increased Monongahela’s number of natural gas customers in West Virginia by about 200,000 in a region where Monongahela already provides energy services.

The acquisition has been recorded using the purchase method of accounting. The table below shows the allocation of the purchase price to assets and liabilities acquired:

Until December 31, 2001, Monongahela amortized the excess of cost over net assets acquired related to the Mountaineer acquisition on a straight-line basis over 40 years.

See Note 5 for additional information regarding Monongahela’s adoption of SFAS No. 142, including the impairment of the goodwill associated with the Mountaineer acquisition.

On January 1, 2002, Monongahela adopted SFAS No. 141, “Business Combinations,” and SFAS No. 142. 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 Monongahela’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. 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 Monongahela, SFAS No. 142 transitional provisions required Monongahela to test its goodwill for impairment as of January 1, 2002, and recognize any transitional goodwill impairment loss as the cumulative effect of a change in accounting principle. Monongahela completed its transitional goodwill impairment test, using a discounted cash flow methodology to determine the fair value of its reporting units, and recorded an impairment loss of $115.4 million, net of income taxes ($195.0 million, before income taxes). The impairment results from factors that are unique to this rate regulated entity and the ratemaking process, including the fact that none of the goodwill was being recovered in rates or included in rate base.

SFAS No. 142 transitional provisions also were completed with respect to Monongahela’s other intangible assets, resulting in no impairments or changes to amortizable lives.

Amortization expense for other intangible assets for 2002 and 2001 was $.3 million. Amortization expense is estimated to be $.3 million annually for 2003 through 2007.

If the provisions of SFAS No. 142 had been applied for 2001 and 2000, consolidated net income would have been as follows:

In July of 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities include a company-wide workforce reduction. For the year ended December 31, 2002, Monongahela recorded a charge for its allocable share of the workforce reduction expenses of $27.8 million, before income taxes ($16.5 million, net of income taxes).

Allegheny has achieved workforce reductions of approximately 10 percent primarily through a voluntary early retirement option (ERO) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits and required eligible employees to make an election. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” For the year ended December 31, 2002, approximately 600 of Allegheny’s eligible employees accepted the ERO program. Monongahela recorded a charge of $27.7 million, before income taxes ($16.4 million, net of income taxes). for its allocable share of the effect of the ERO program. Allegheny offered a Staffing Reduction Separation Program (SRSP) for employees whose positions are being eliminated as part of the workforce reductions. The severance and other employee-related costs are accounted for in accordance with 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).” For the year ended December 31, 2002, Monongahela recorded a charge of $.1 million, before income taxes ($.1 million, net of income taxes), for its allocable share of the effect of the SRSP, related to approximately 80 of Allegheny’s employees whose positions have been or are being eliminated. Allegheny has essentially completed these planned workforce reductions. Workforce reduction costs are recorded in “Workforce reduction expenses” on the consolidated statement of operations.

Monongahela manages and evaluates its operations in two business segments: 1) Delivery and Services and 2) Generation and Marketing. Prior to the second quarter of 2002, Monongahela’s reported segments were regulated utility operations and unregulated generation operations. Business segments have been changed to reflect current internal management reporting. Prior period segment information has been restated for comparability.

The Delivery and Services segment operates regulated electric and natural gas T&D systems.

The Generation and Marketing segment develops, owns, operates, and manages electric generating capacity. This segment includes intersegment sales to provide energy to Monongahela’s Delivery and Services segment. Prior to the second quarter of 2002, Monongahela’s unregulated generation operations segment consisted solely of the revenues and expenses between January 1, 2001, and May 31, 2001, associated with its deregulated Ohio jurisdictional generating assets. Prior to the second quarter of 2002, Monongahela’s West Virginia jurisdictional generating assets were included in the regulated utility operations segment.

Monongahela accounts for intersegment sales based on cost or regulatory commission approved tariffs or contracts.

Business segment information is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts.

As the result of a non-cash benefit associated with AE’s Supplemental Employee Retirement Plan, other paid-in capital increased during the period January 1, 2002 to December 31, 2002 by approximately $6.5 million.

Each share of Monongahela’s preferred stock is entitled, upon voluntary liquidation, to its then current call price and, on involuntary liquidation, to $100 a share.

See Note 3, “Debt Covenants,” for a description of the defaults under Monongahela’s current debt agreements. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was $690.1 million as of December 31, 2002.

Contractual maturities for debentures, notes, bonds and QUIDS in millions of dollars for the next five years, excluding unamortized debt discounts and premiums, are: 2003, $65.9; 2004, $3.3; 2005, $3.3; 2006, $303.3; 2007, $43.8; and thereafter, $367.1. At December 31, 2002, substantially all of the properties of Monongahela are held subject to the lien securing its first mortgage bonds. Some properties are also subject to a lien securing certain pollution control and solid waste disposal notes. Certain first mortgage bonds series are not redeemable until dates established in the respective supplemental indentures.

During 2002, Monongahela redeemed $1.8 million of 4.35 percent unsecured notes and $25.0 million of 7.375 percent first mortgage bonds, and Mountaineer made repayments of $3.3 million on 7.6 percent fixed-rate unsecured notes.

On September 21, 2001, Monongahela redeemed $40.0 million of eight percent QUIDS due June 25, 2025. On October 2, 2001, Monongahela issued debt of $300.0 million five percent first mortgage bonds due October 1, 2006. The net proceeds from the first mortgage bonds were used to replenish funds used to redeem the QUIDS, refinance $100.0 million senior secured credit facility that matured in October 2001, refinance $50.0 million first mortgage bonds that carried a higher interest rate, and provide additional funds for other corporate purposes.

Mountaineer is restricted in its ability to declare dividends. The restriction clause requires Mountaineer to maintain a minimum net worth of at least $53.0 million.

Monongahela follows EITF Issue No. 97-4, which provides that when a rate order is issued that contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated, the entity should cease to apply SFAS No. 71 to that separable portion of its business.

As required by EITF Issue No. 97-4, Monongahela discontinued the application of SFAS No. 71 for its West Virginia jurisdiction’s electric generation operations in the first quarter of 2000 and for its Ohio jurisdiction’s electric generation operations in the fourth quarter of 2000. Monongahela recorded an after-tax charge in 2000 of $63.1 million, to reflect the unrecoverable net regulatory assets that will not be collected from customers and to

record a rate stabilization obligation. This charge is classified as an extraordinary charge under the provisions of SFAS No. 101, “Accounting for the Discontinuation of Application of FASB Statement No. 71.”

As of December 31, 2002 and 2001, Monongahela had no generating assets subject to SFAS No. 71. The consolidated balance sheet includes the amounts listed below for generating assets not subject to SFAS No. 71.

In March 2003, the West Virginia Legislature passed House Bill (H.B.) 2870, which clarified the jurisdiction of the West Virginia PSC over electric generating facilities in West Virginia. Concurrent with the passage of H.B. 2870, Monongahela’s outside counsel advised that deregulation of generating assets in West Virginia was no longer probable and confirmed that the West Virginia PSC will have jurisdiction and rate authority over Monongahela’s generating assets in West Virginia. Monongahela therefore concluded that deregulation of its West Virginia generating assets is no longer probable and the generation operations in West Virginia meet the requirements of SFAS No. 71. Monongahela will reapply the provisions of SFAS No. 71 to its West Virginia jurisdictional generating assets in the first quarter of 2003. While its evaluation has not been fully completed, Monongahela currently estimates that it will recognize a gain as a result of the reapplication of SFAS No. 71 of approximately $50.0 million, net of income taxes, primarily as the result of the elimination of its transition obligation and the reestablishment of regulatory assets related to deferred income taxes.

The total provision for income tax expense is different from the amount produced by applying the federal statutory income tax rate of 35 percent to financial accounting income, as set forth below:

The provision for income taxes for the extraordinary charge and the cumulative effect of accounting change is different from the amount produced by applying the federal statutory income tax rate of 35 percent to the gross amount, as set forth below:

Federal income tax returns through 1997 have been examined and settled by the Internal Revenue Service. At December 31, the deferred tax assets and liabilities consisted of the following:

Monongahela recorded as deferred tax assets the effect of net operating losses, which will be realized through future operations and through the reversal of existing temporary differences. These net operating loss carryforwards expire in varying amounts through 2022. In addition, Monongahela is a party to a consolidating tax sharing agreement and expects to realize benefits represented by deferred tax assets through its participation in the consolidated tax return in future years.

Total short-term income taxes receivable due from affiliates at December 31, 2002 and 2001, was $33.0 million and $5.5 million, respectively. Total income taxes payable to affiliates at December 31, 2002 and 2001, was $177.1 million and $238.8 million, respectively.

To provide interim financing and support for outstanding commercial paper, Allegheny and its regulated subsidiaries, including Monongahela, had established lines of credit with several banks. These lines of credit had fee arrangements and no compensating balance requirements. At December 31, 2002, the entire $335.0 million lines of credit with banks were drawn by Allegheny, and no amounts were available for Monongahela. At December 31, 2001, $14.4 million of the $400.0 million lines of credit with banks were drawn by Mountaineer Gas. All of the $385.6 million remaining lines of credit were supporting commercial paper issued by Allegheny and an affiliate. These facilities, which were refinanced in February 2003, required the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio, as defined under the credit agreements. On October 8, 2002, Allegheny announced that it, AE Supply, and Allegheny Generating Company (AGC) were in default under these facilities after AE Supply declined to post additional collateral in favor of several trading counterparties. As of December 31, 2002, Allegheny had obtained waivers and amendments for these facilities. See Note 3 for additional details regarding the defaults as of December 31, 2002. See Note 24 for additional details regarding the Borrowing Facilities that were entered into in February 2003.

In addition to bank lines of credit, Monongahela participates in an Allegheny internal money pool which accommodates intercompany short-term borrowing needs, to the extent that certain of Allegheny’s subsidiaries

have funds available. The money pool provides funds to approved Allegheny subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven-day commercial paper rate, as quoted by the same source, less four basis points. At December 31, 2002 and 2001, Monongahela had no borrowings outstanding from the money pool. Monongahela has SEC authorization for total short-term borrowings, from all sources, of $106.0 million.

As described in Note 1, Monongahela is responsible for its proportionate share of the cost (income) for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. Monongahela’s share of the (credits) costs, of which approximately 16 percent in 2002 was (credited) charged to plant construction, was as follows:

Monongahela’s electric and natural gas T&D operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets, net of regulatory liabilities, reflected in the consolidated balance sheet at December 31 relate to:

SFAS No. 109, “Accounting for Income Taxes,” requires Monongahela to record a deferred income tax liability for tax benefits passed through to customers when temporary differences originate. These deferred income taxes relate to temporary differences involving regulated utility property, plant, and equipment and the related provision for depreciation. Monongahela records a regulatory asset for these income taxes since the amounts are recoverable from customers when the taxes are paid by Monongahela over the remaining depreciable lives of the property, plant, and equipment. Since the deferred income tax liability recorded under SFAS No. 109 is non-cash, no return is allowed on the income taxes regulatory asset.

See “West Virginia Regulation” in Note 10 for a discussion regarding Monongahela’s plans to reapply the provisions of SFAS No. 71 to its West Virginia jurisdictional generating assets in the first quarter of 2003.

The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:

The carrying amount of temporary cash investments, and short-term debt, approximates the fair value because of the short maturities of those instruments. The fair value of long-term debt was estimated based on actual market prices or market prices of similar issues. Monongahela had no financial instruments held or issued for trading purposes.

Monongahela owns an interest in seven generating stations with AE Supply. Monongahela records its proportionate share of operating costs, assets, and liabilities in the corresponding lines in the consolidated financial statements. As of December 31, 2002, Monongahela’s investment and accumulated depreciation in these generating stations were as follows:

Monongahela and its partially owned affiliate, AGC, own certain generating assets jointly as tenants in common. The assets are operated by Monongahela, with each of the owners being entitled to the available energy output and capacity in proportion to its ownership in the asset.

Other income and expenses, net represent nonoperating revenues and expenses before income taxes. The following table summarized Monongahela’s other income and expenses for 2002, 2001, and 2000:

Other income and expenses includes Monongahela’s portion of earnings in AGC. See Note 18 to the consolidated financial statements for further details regarding Monongahela’s investment in AGC.

Monongahela’s interest in the common stock of AGC decreased to 22.97 percent from 27.0 percent effective June 1, 2001. The decrease resulted from a transfer of Monongahela’s Ohio and FERC jurisdictional generating assets to AE Supply. AE Supply owns the remaining shares of AGC. Monongahela reports AGC in its consolidated financial statements using the equity method of accounting. AGC owns an undivided 40 percent interest, 960 megawatts (MW), in the 2,400-MW pumped-storage hydroelectric station in Bath County, Virginia, operated by the 60 percent owner, Virginia Electric and Power Company, a nonaffiliated utility.

AGC recovers from Monongahela and AE Supply all of its operation and maintenance expenses, depreciation, taxes, and a return on its investment under a wholesale rate schedule approved by the FERC. AGC’s rates are set by a formula filed with and previously accepted by the FERC. The only component that changes is the return on equity (ROE). Pursuant to a settlement agreement filed April 4, 1996, with the FERC, AGC’s ROE was set at 11.0 percent for 1996 and will continue until the time any affected party seeks renegotiation of the ROE.

Monongahela’s share of the equity in earnings was approximately $4.3 million, $5.0 million, and $5.9 million for 2002, 2001, and 2000, respectively, and is included in other income and expenses on Monongahela’s consolidated statement of operations.

Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for Monongahela and its affiliates in accordance with PUHCA. Through AESC, Monongahela is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to Monongahela for 2002, 2001, and 2000 were $203.7 million, $177.2 million, and $144.7 million, respectively.

Monongahela purchases nearly all of the power necessary to serve its Ohio customers who do not choose an alternate electricity generation provider from its unregulated generation company affiliate, AE Supply, in accordance with agreements approved by the FERC. The expense from these purchases is reflected in “Purchased energy and transmission” expense on the consolidated statement of operations. For 2002, 2001, and 2000, Monongahela purchased power from AE Supply of $49.2 million, $31.4 million, and $5.2 million, respectively. Prior to Monongahela joining PJM Interconnection, LLC (PJM) in April 2002, if Monongahela purchased more electricity than was needed to serve its customers, the excess electricity purchased was sold back to AE Supply and is reflected as operating revenues on the consolidated statement of operations. Upon Monongahela joining PJM, operational changes were made so that Monongahela no longer has excess electricity to sell back to AE Supply. For 2002, 2001, and 2000, Monongahela sold excess electricity back to AE Supply of $39.7 million, $74.9 million, and $56.8 million, respectively.

The Ohio and FERC jurisdictional generating assets transferred to AE Supply on June 1, 2001, have been leased back by Monongahela. The lease was effective on June 1, 2001 for a term of one year and renews automatically. Monongahela and AE Supply have mutually agreed to continue the lease. For 2002 and 2001, the rental expense from this arrangement totaled $37.1 million and $23.8 million, respectively, and is reported as “Purchased energy and transmission” expense on the consolidated statement of operations.

At December 31, 2002 and 2001, Monongahela had net accounts payable to affiliates of $21.5 million and $15.7 million, respectively.

See Note 11 for information regarding affiliated income taxes payable associated with Monongahela’s inclusion in Allegheny’s consolidated federal income tax return.

See Note 12 for information regarding Monongahela’s participation in an Allegheny internal money pool, a facility that accommodates short-term borrowing needs.

On June 1, 2001, Monongahela transferred, at book value, approximately 352 MW of Ohio and FERC jurisdictional generating assets to AE Supply. The Ohio PUC, as part of Ohio’s deregulation efforts, approved the transfer. The net effect of the assets transferred are shown below:

The pollution control notes related to the transfer of the Ohio jurisdictional generating assets are included as debt in Monongahela’s financial statements as Monongahela remains co-obligor for the debt. Even though AE Supply is responsible for the payment of the pollution control notes, Monongahela continues to accrue interest expense associated with the notes. As AE Supply remits payment, Monongahela reduces accrued interest and increases paid-in capital.

reported total operating revenues, consolidated (loss) income before cumulative effect of accounting change and consolidated net (loss) income.

The corrections of accounting errors related to the first and second quarters of 2002 were primarily as follows:

Had Monongahela adjusted 2001 for the correction of errors discussed in Note 2 that were recorded in the first quarter of 2002, the 2001 quarterly consolidated net income would have been as follows:

SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets, was adopted by Monongahela on January 1, 2003. SFAS No. 143 requires that the fair value of retirement costs for which Monongahela has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss if settled at a different amount.

Monongahela has completed a detailed assessment of the specific applicability of SFAS No. 143 and recorded retirement obligations primarily related to ash landfills, underground and aboveground storage tanks, and gas wells. Monongahela also has identified a number of retirement obligations associated with certain other assets that have not been recorded, because the fair value of such obligations cannot be reasonably estimated, due primarily to the indeterminate lives of the assets.

The effect of adopting SFAS No. 143 on Monongahela’s consolidated statement of operations will be a cumulative effect adjustment to decrease net income by $1.8 million ($3.1 million before income taxes). The effect of adopting SFAS No. 143 on Monongahela’s consolidated balance sheet will be a $3.0-million increase in property, plant, and equipment, net and the recognition of a $6.1-million liability for asset retirement obligations.

Monongahela has recorded in accumulated depreciation, removal costs collected from customers related to assets that do not have associated retirement obligations under SFAS No. 143. These estimated removal costs, totaling $218.5 million at December 31, 2002, represent a regulatory liability and remain in accumulated depreciation.

See Note 23: Commitments and Contingencies for the effect of Monongahela’s adoption of FASB Interpretation Nos. (FIN) 45 and 46, respectively.

Monongahela has entered into commitments for its construction and capital programs for which expenditures are estimated to be $68.0 million (unaudited) for 2003 and $71.6 million (unaudited) for 2004. Construction expenditure levels in 2005 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 (CAAA) and the

extent to which environmental initiatives currently being considered become mandated. Monongahela estimates that its management of emission allowances will allow it to comply with Phase II sulfur dioxide (SO₂) limits through 2005. Studies to evaluate cost-effective options to comply with Phase II SO₂ limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.

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

Clean Air Act and CAAA Matters: The EPA has issued a NO_x State Implementation Plan (SIP) call rule that requires the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Maryland, Pennsylvania, and West Virginia, beginning in May 2003. Monongahela’s compliance with such stringent regulations has required and will require the installation of expensive post-combustion control technologies on most of its power stations. During 2000, Pennsylvania and Maryland promulgated final rules to implement the EPA’s NO_x SIP call requirements, beginning in May 2003. During 2001, the West Virginia Department of Environmental Protection issued a final rule to implement the EPA’s NO_x SIP call requirements, beginning in May 2004. The EPA approved the West Virginia SIP in July of 2002. The EPA’s NO_x SIP call had been subject to litigation but, in 2000, the D.C. Circuit Court of Appeals issued a decision that upheld the regulation. The court issued a subsequent order that postponed the initial compliance date of the NO_x SIP call from May 2003 to May 2004. Maryland and Pennsylvania did not delay the May 2003 implementation dates of their respective SIP, nor are they legally required to do so. Monongahela is in the process of installing NO_x controls to meet the Pennsylvania, Maryland, and West Virginia SIP. Monongahela also has the option to purchase, in some cases, alternate fuels, NO_x allowances, or power on the market, if needed to supplement our compliance strategy. Monongahela expects to be in compliance with NO_x limits established by the SIP. Monongahela’s construction forecast includes the expenditure of $12.9 million (unaudited) of capital costs during the 2003 through 2004 period to comply with these regulations.

In August 2000, AE received a letter from the EPA requiring it to provide information and documentation relevant to the operation and maintenance of the following 10 electric generating stations, collectively including 22 generating units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island, AE Supply and Monongahela own these electric generating stations. The letter requested information under Section 114 of Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the new source review standards, which can require the installation of additional air pollution control equipment upon the major modification of an existing facility. Responsive submissions were made during 2000 and 2001. In July 2002, AE received a follow-up letter from the EPA requesting clarifying information. AE provided responsive information. The eventual outcome of the EPA investigation is unknown.

generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. However, the recent preliminary judicial decision in the EPA vs. Duke energy case, as well as the final Routine Maintenance, Repair and Replacement Rule recently released by the EPA, are more consistent with the energy industry’s historical compliance approach. Therefore, at this time, AE and its subsidiaries are not able to determine the effect these actions may have on them with regard to compliance costs.

The Attorneys General of New York and Connecticut, in letters dated September 15, 1999, and November 3, 1999, respectively, notified AE of their intent to commence civil actions against AE and/or its subsidiaries alleging violations at the Fort Martin Power Station under the federal Clean Air Act, which requires power plants that make major modifications to comply with the same New Source Review emission standards applicable to new power plants. Other governmental agencies may commence similar actions in the future. Fort Martin Power Station is located in West Virginia and is now jointly owned by AE Supply and Monongahela. Both Attorneys General stated their intent to seek injunctive relief and penalties. In addition, the Attorney General of the State of New York indicated that he may 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, AE and its subsidiaries, AE Supply and Monongahela, are not able to determine what effect, if any, these actions may have on them.

Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) Claim: On March 4, 1994, Monongahela, Potomac Edison, and West Penn (the Distribution Companies) received notice that the EPA had identified them as potentially responsible parties (PRPs) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site. Initially approximately 175 PRPs were involved, however, the current number of active PRPs is approximately 80. The costs of remediation will be shared by all responsible parties. In 1999, a PRP group that included the Distribution Companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30 million. However, Monongahela estimates that its share of the cleanup liability will not exceed $.3 million, which has been accrued as a liability at December 31, 2002.

Claims Related to Alleged Asbestos Exposure: Monongahela, Potomac Edison, and West Penn have also been named as defendants along with multiple other defendants in pending asbestos cases involving multiple plaintiffs. While Monongahela believes that all of the cases are without merit, Monongahela cannot predict the outcome of the litigation. Monongahela has accrued a reserve of $1.5 million as of December 31, 2002, related to the asbestos cases as the potential cost to settle the cases to avoid the anticipated cost of defense. During 2002, Monongahela received $1.1 million of insurance recoveries (net of $.2 million of legal fees) related to these asbestos cases. During 2001, Monongahela received $.2 million of insurance recoveries related to these asbestos cases.

In the normal course of business, Monongahela becomes involved in various other legal proceedings. Monongahela does not believe that the ultimate outcome of these proceedings will have a material effect on its consolidated financial position, results of operations and cash flows.

Monongahela has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles and computer equipment.

The carrying amount of assets recorded under capitalized lease agreements included in property, plant, and equipment at December 31 consist of the following:

At December 31, 2002 and 2001, obligations under capital leases were as follows:

Total capital and operating lease rent payments of $10.0 million in 2002, $13.3 million in 2001, and $13.4 million in 2000 were recorded as rent expense in accordance with SFAS No. 71. Monongahela’s estimated future minimum lease payments for operating leases with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are $2.4 million in 2003; $1.4 million in 2004; $.8 million in 2005; and $.4 million in 2006. Monongahela’s estimated future minimum lease payments for capital leases with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are $3.3 million in 2003; $4.4 million in 2004; $3.7 million in 2005; $3.1 million in 2006; $2.5 million in 2007; and $4.4 million thereafter. The present value of estimated future minimum lease payments for capital leases is $18.8 million, reflecting interest expense of $2.6 million.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities,” which addresses consolidation by business enterprises of variable interest entities, commonly referred to as “special purpose entities.” FIN 46 requires consolidation where there is a controlling financial interest in a variable interest entity or where the variable interest entity does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties. Monongahela will apply the provisions of FIN 46 prospectively for all variable interest entities created after January 31, 2003. Monongahela is not involved in any transactions with variable interest entities. Monongahela does not believe that FIN 46 will have a material affect on its statement of operations or financial position.

Under PURPA, electric utility companies, such as Monongahela, are required to interconnect with, provide back-up electric service to, and purchase electric capacity and energy from qualifying power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by the FERC. The appropriate state public service commission or legislature establishes the rates paid for electric energy purchased from such qualifying facilities.

Monongahela is committed to purchase the electrical output from 161 MW of qualifying PURPA capacity. Payments for PURPA capacity and energy in 2002 and 2001 totaled $58.6 million and $61.4 million, respectively. The average cost to Monongahela of these power purchases was approximately 5.4 cents/kilowatt-hour (kWh) and 5.2 cents/kWh for 2002 and 2001, respectively. Monongahela is currently authorized to recover these costs in its retail rates.

The table below reflects Monongahela’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2002. Actual values can vary substantially depending upon future conditions.

Monongahela has entered into various long-term commitments for the procurement of fuel, primarily coal and lime, to supply its generating facilities. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Monongahela’s fuel consumed for electric generation was $128.9 million, $131.8 million, and $145.7 million in 2002, 2001, and 2000, respectively. In 2002, Monongahela purchased approximately 57.2 percent of its fuel from one vendor. Total estimated long-term coal and lime obligations at December 31, 2002, were as follows:

In November 2002, the FASB issued FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others,” which requires disclosures by a guarantor concerning its obligations under certain guarantees that it has issued. FIN 45 also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issued or modified after December 31, 2002. Monongahela has no guarantees outstanding as of December 31, 2002. Monongahela does not anticipate FIN 45 will have a material impact on its consolidated results of operations and financial position.

In February and March 2003, AE, AE Supply, Monongahela and West Penn entered into agreements (the Borrowing Facilities), totaling $2,447.8 million, with various credit providers to refinance the bulk of AE and AE Supply’s short-term debt. Proceeds from the financing were used to refinance existing debt and for general corporate purposes.

Following is a summary of the term of the Borrowing Facilities at AE and its subsidiaries, other than AE Supply:

The terms of the Borrowing Facilities require that Allegheny, on a consolidated basis, and AE Supply meet certain financial tests, as defined in the Borrowing Facilities agreements. The Borrowing Facilities also have provisions requiring prepayments out of the proceeds of asset sales, debt and equity issuances, and excess cash flows, as defined in the agreements, by Allegheny, including Monongahela. Any prepayments under the provisions of the Borrowing Facilities reduce the amounts of scheduled principal payments in 2003 and 2004. Effective July 22, 2003 and August 22, 2003, Allegheny and AE Supply were granted waivers from compliance with all of the above financial tests for the first, second and third quarters of 2003.

The Borrowing Facilities also contain restrictive covenants that limit Monongahela’s ability to: borrow funds; incur liens; enter into a merger or other change of control transaction; make investments; prepay indebtedness; amend contracts; pay dividends and other distributions on Monongahela’s equity; and operate Monongahela’s business, by requiring it to adhere to an agreed business plan.

The management of Monongahela Power Company (the Company), a wholly-owned subsidiary of Allegheny Energy, Inc. (Allegheny), is responsible for the information and representations in the Company’s financial statements. The Company prepares the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management’s best estimates and judgments of known conditions.

The Company is responsible for maintaining an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Company’s assets are protected. As discussed in Item 14, of Allegheny’s Annual Report on Form 10-K, Allegheny’s management has concluded that the Allegheny internal controls and disclosure controls are not adequate, and need substantial work to restore them to adequacy. Management and the Audit Committee of the Board of Directors of Allegheny are committed to devoting the additional resources necessary to ensure that the Company’s reporting is accurate until internal controls and disclosure controls are improved and are adequate.

Allegheny’s staff of internal auditors conducts periodic reviews designed to assist management in maintaining effective internal control procedures. PricewaterhouseCoopers LLP, an independent accounting firm, audits the financial statements and expresses its opinion on them. The independent accountants perform their audit in accordance with auditing standards generally accepted in the United States of America.

The Audit Committee of the Board of Directors of Allegheny, which consists of outside Directors, meets regularly with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to all of the Company’s records and to the Audit Committee of Allegheny.

In our opinion, the accompanying consolidated balance sheets, consolidated statements of capitalization and the related consolidated statements of operations and cash flows, present fairly, in all material respects, the financial position of Monongahela Power Company and its subsidiaries (the Company) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 5 to the financial statements, on January 1, 2002, the Company adopted Financial Accounting Standards Board Statement No. 142, “Goodwill and Other Intangible Assets.”

In 2000, Potomac Edison transferred generating assets and the related pollution control obligations, with a principal balance of $104.2 million, to Allegheny Energy Supply Company, LLC.

The Potomac Edison Company (Potomac Edison) is a regulated wholly-owned subsidiary of Allegheny Energy, Inc. (AE, and collectively with AE’s consolidated subsidiaries, Allegheny) and along with its regulated utility affiliates, Monongahela Power Company (Monongahela) and West Penn Power Company (West Penn), collectively doing business as Allegheny Power, operate electric and natural gas transmission and distribution (T&D) systems. Potomac Edison’s business is the operation of an electric T&D system in Maryland, Virginia, and West Virginia. Potomac Edison currently operates under a single business segment, Delivery and Services. Prior to August 1, 2000, Potomac Edison operated an additional segment, Generation and Marketing.

Potomac Edison is subject to regulation by the Securities and Exchange Commission (SEC), the Maryland Public Service Commission (Maryland PSC), the Public Service Commission of West Virginia (West Virginia PSC), the Virginia State Corporation Commission (Virginia SCC), and the Federal Energy Regulatory Commission (FERC).

Certain amounts in the December 31, 2001 consolidated balance sheet and in the December 31, 2001, and 2000, consolidated statements of operations and consolidated statements of cash flows have been reclassified for comparative purposes. Significant accounting policies of Potomac Edison and its subsidiaries are summarized below.

The preparation of financial statements in conformity with generally accepted accounting principles of the United States of America (GAAP) requires Potomac Edison to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. On a continuous basis, Potomac Edison evaluates its estimates, including those related to the calculation of unbilled revenues, provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits, and contingencies related to environmental matters and litigation. Potomac Edison bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

The consolidated financial statements reflect investments in controlled subsidiaries on a consolidated basis. The consolidated financial statements include the accounts of Potomac Edison and all subsidiary companies after elimination of intercompany transactions and balances and are prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of the FERC and applicable state regulatory commissions.

Revenues from the sale of electricity to customers are recognized in the period that the electricity is delivered and consumed by customers, including an estimate for unbilled revenues. Revenues from one industrial customer were 8.9 percent, 8.7 percent and 7.6 percent of total operating revenues in 2002, 2001, and 2000, respectively.

The difference between the costs of fuel, purchased energy, and certain other costs and revenues from regulated electric utility purchases from or sales to other utilities and power marketers, including transmission services, and fuel related revenues billed to customers has historically been deferred until it is either recovered from or credited to customers under fuel and energy cost-recovery procedures in Maryland, Virginia, and West Virginia. Effective July 1, 2000, in Maryland and West Virginia, and August 7, 2000, in Virginia, fuel and purchased energy costs for Potomac Edison’s electric operations have been expensed as incurred as a result of the elimination of deferred energy cost mechanisms by Potomac Edison’s state regulatory bodies.

Under the provisions of the Public Utilities Regulatory Policies Act of 1978 (PURPA), Potomac Edison was required to enter into a long-term contract to purchase capacity and energy from the AES Warrior Run facility through the beginning of 2030. Effective July 1, 2000, Potomac Edison was authorized by the Maryland PSC to recover all contract costs from the AES Warrior Run facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market, through the life of the contract by means of a retail revenue surcharge. Any under or overrecovery of net costs is being deferred on Potomac Edison’s balance sheet, as deferred energy costs, pending subsequent recovery from or return to customers through adjustments to the retail revenue surcharge. See “PURPA” in Note 18 for additional information.

Property, plant, and equipment are stated at original cost. Costs include direct labor and materials; allowance for funds used during construction (AFUDC) on property for which construction work in progress is not included in rate base; and indirect costs such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes, and other benefits related to employees engaged in construction.

Upon retirement, the cost of depreciable property, plus removal costs less salvage, are charged to accumulated depreciation in accordance with the provisions of Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”

Potomac Edison capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over the expected useful life of the software beginning upon a project’s completion.

Potomac Edison adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets,” on January 1, 2002. Long-lived assets owned by Potomac Edison are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, resulting in the asset being written down to its fair value. The fair value is determined by the use of quoted market prices, appraisals, or the use of other valuation techniques, such as expected discounted future cash flows.

AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is recognized as a cost of property, plant, and equipment. Rates used for computing AFUDC in 2002, 2001, and 2000 averaged 2.76 percent, 4.31 percent, and 8.77 percent, respectively.

Depreciation expense is determined generally on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 2.8 percent of average depreciable property in 2002, 2.8 percent in 2001, and 3.5 percent in 2000. Estimated service lives for T&D property range from 14 to 55 years, and for all other property range from 5 to 42 years. Depreciation expense was $39.4 million, $38.5 million, and $62.1 million for 2002, 2001, and 2000, respectively. Depreciation expense for regulated property is provided for under currently enacted regulatory rates.

Maintenance expenses represent costs incurred to maintain the power stations (through July 31, 2000), the T&D system, and general plant, and reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage to the T&D system. Maintenance costs are expensed in the year incurred.

Potomac Edison adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” on January 1, 2002. SFAS No. 142 requires that intangible assets with indefinite lives not be amortized, but, rather, be tested for impairment at least annually. Intangible assets with finite lives are to be amortized over their useful lives and tested for impairment when events or circumstances warrant. Potomac Edison has intangible assets consisting of amortized land easements, which are included in property, plant, and equipment on the consolidated balance sheet, with a gross carrying amount and accumulated amortization as follows: at December 31, 2002, $54.8 million and $13.5 million, respectively, and at December 31, 2001, $54.0 million and $12.7 million, respectively. Amortization expense was $.7 million in 2002 and 2001. Amortization expense is estimated to be $.7 million annually for 2003 through 2007.

Potomac Edison has various operating transactions with affiliates. It is Potomac Edison’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented net on the consolidated balance sheet and the consolidated statement of cash flows. See Note 14 for additional information on related party transactions.

In accordance with SFAS No. 71, Potomac Edison’s consolidated financial statements include certain assets and liabilities resulting from cost-based ratemaking regulation.

Potomac Edison joins with Allegheny and its affiliates in filing a consolidated federal income tax return. The consolidated income 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 income tax liability.

Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the financial statement and tax basis of assets and liabilities computed using the most current tax rates. See Note 8 for additional information regarding income taxes.

Potomac Edison has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant, and equipment.

Substantially all of the employees of Allegheny are employed by Allegheny Energy Service Corporation (AESC), a wholly-owned subsidiary of Allegheny, which performs services at cost for Potomac Edison and its affiliates in accordance with PUHCA. Through AESC, Potomac Edison is responsible for its proportionate share of postretirement benefit costs.

AESC provides a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on each employee’s years of service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act of 1974 (ERISA) and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities, short-term investments, and insurance contracts.

Potomac Edison does not have any elements of other comprehensive income to report in accordance with SFAS No. 130, “Reporting Comprehensive Income.”

review of its financial processes, records, and internal controls to ensure that its current and prior financial statements are fairly presented in accordance with GAAP.

As a result of Allegheny’s comprehensive accounting review, Allegheny identified, prior to closing its books for 2002, various errors relating to the financial statements for 2001, 2000, and years prior to 2000. Except for certain restatement adjustments to the consolidated balance sheet as of December 31, 2001, Allegheny’s management concluded that these errors were not material, either individually or in the aggregate, to the current year or any prior year’s financial statements. These adjustments related to Potomac Edison, which increase net income, aggregate approximately $.7 million, net of income taxes, and have been recorded in the first quarter of 2002. The nature and amounts of these adjustments are primarily as follows:

The years to which the (charges) income, net of income taxes, relate are as follows:

Had the adjustments listed above been recorded in the appropriate years, the following table demonstrates the effect on both consolidated income before extraordinary charge and consolidated net income:

While certain changes in policies and procedures have been instituted, additional changes are needed to improve the internal control structure of Allegheny.

Allegheny’s management, Audit Committee, and Board of Directors are fully committed to the resolution of Allegheny’s internal control deficiencies. Ultimate resolution of the deficiencies will include changing the culture of the accounting function to focus on accountability and the strict, timely adherence to a set of sound internal control policies and procedures. Management has commenced or is under taking the following corrective actions in order to achieve an immediate improvement in the controls environment:

Potomac Edison had several debt agreements that required it to file copies of its annual or quarterly reports as filed with the SEC pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) with the debt holders. Potomac Edison is also required to deliver to the trustees under its indenture a certificate indicating that Potomac Edison has complied with all conditions and covenants under the agreements. On April 30, 2003, Potomac Edison provided certificates to the trustee under its indentures indicating that it was not in compliance with the covenants for filing its annual and quarterly reports that are contained in its First Mortgage Bonds and Medium Term Notes. The covenant breach of the First Mortgage Bonds and Medium Term Notes is deemed a default of the related debt agreements for Potomac Edison’s financial reporting purposes in accordance with EITF Issue No. 86-30, “classification of obligations when a violation is waived by the creditor.” The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was approximately $416.0 million as of December 31, 2002. To date, the debt holders have not provided Potomac Edison with any notices of default under the agreements. Such notices, if received, would allow Allegheny 60 days to cure its noncompliance before the debt holders could accelerate the due dates of the debt obligations.

Potomac Edison’s ability to meet its payment obligations under its First Mortgage Bonds and Medium Term Notes and to fund capital expenditures will depend on its future performance. Potomac Edison’s future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control. In 2003, Potomac Edison’s cash flows are expected to be adequate to meet all its payment obligations under the First Mortgage Bonds and Medium Term Notes and to fund other liquidity needs.

Management plans to file its Annual Report on Form 10-K for the period ended December 31, 2003 on a timely basis.

In July of 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction. For the year ended December 31, 2002, Potomac Edison recorded a charge for its allocable share of the workforce reduction expenses of $12.4 million, before income taxes ($7.5 million, net of income taxes).

Allegheny has achieved workforce reductions of approximately 10 percent primarily through a voluntary early retirement option (ERO) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits and required eligible employees to make an election. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” For the year ended December 31, 2002, approximately 600 of Allegheny’s eligible employees accepted the ERO program resulting in a charge of $12.4 million, before income taxes ($7.5 million, net of income taxes) for its allocable share. Allegheny offered a Staffing Reduction Separation Program (SRSP) for employees whose positions are being eliminated as part of the workforce reductions. The severance and other employee-related costs are accounted for in accordance with 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).” For the year ended December 31, 2002, Potomac Edison recorded a charge of $.04 million, before income taxes, for its allocable share of the effect of the SRSP, related to approximately 80 of Allegheny’s employees whose positions have been or are being eliminated. Allegheny has essentially completed these planned workforce reductions. Workforce reduction costs are recorded in “Workforce reduction expenses” on the consolidated statements of operations.

Potomac Edison currently operates under a single business segment, Delivery and Services, which operates Potomac Edison’s electric T&D system. Prior to Potomac Edison’s transfer of its generating assets to Allegheny Energy Supply Company, LLC (AE Supply), Potomac Edison’s unregulated generation affiliate, on August 1, 2000, Potomac Edison operated an additional segment, Generation and Marketing.

As a result of a non-cash charge associated with AE’s Supplemental Employee Retirement Plan, other paid-in capital decreased during the period January 1, 2002 to December 31, 2002 by approximately $1.5 million.

Contractual maturities for bonds, in millions of dollars, for the next five years are: 2003, $0; 2004, $0; 2005, $0; 2006, $100.0; 2007, $0; and thereafter, $320.0. Substantially all of the properties of Potomac Edison are held subject to the lien securing its first mortgage bonds. Certain first mortgage bond series are not redeemable until dates established in the respective supplemental indentures.

On November 6, 2001, Potomac Edison issued debt of $100.0 million five percent notes due on November 1, 2006. Potomac Edison used the net proceeds from these notes, together with other corporate funds, for the following purposes: to redeem $50 million principal amount of Potomac Edison’s first mortgage bonds, eight percent series due on June 1, 2006, at the optional redemption price of 100 percent of their principal amount plus accrued interest to the redemption date; to redeem $45.5 million principal amount of Potomac Edison’s 8 percent Quarterly Income Debt Securities (QUIDS) due September 30, 2025, at a redemption price of 100 percent of their principal amount plus accrued interest to the redemption date; and to add to Potomac Edison’s general funds.

See Note 3, “Debt Covenants,” for a description of the defaults under Allegheny’s current debt agreements. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was $416.0 million as of December 31, 2002.

Potomac Edison follows Emerging Issues Task Force (EITF) Issue No. 97-4, “Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statement Nos. 71 and 101,” which provides that when a rate order is issued that contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated, the entity should cease to apply SFAS No. 71 to that separable portion of its business.

As required by EITF Issue No. 97-4, Potomac Edison discontinued the application of SFAS No. 71 for its West Virginia jurisdiction’s electric generation operations in the first quarter of 2000 and for its Virginia jurisdiction’s electric generation operations in the fourth quarter of 2000. Potomac Edison had recorded an after-tax charge in 2000 of $13.9 million to reflect the unrecoverable net regulatory assets that will not be collected from customers and to record a rate stabilization obligation. This charge is classified as an extraordinary charge under the provisions of SFAS No. 101, “Accounting for the Discontinuation of Application of FASB Statement No. 71.” Potomac Edison also will reapply the provisions of SFAS No. 71 in the first quarter of 2003 and, while its evaluation has not been fully completed, currently estimates that it will recognize a gain of approximately $10.0 million, net of income taxes, as a result of the elimination of its transition obligation.

The total provision for income tax expense is different from the amount produced by applying the federal statutory income tax rate of 35 percent to financial accounting income, as set forth below:

The provision for income taxes for the extraordinary charge is different from the amount produced by applying the federal statutory income tax rate of 35 percent to the gross amount, as set forth below:

Federal income tax returns through 1997 have been examined by the Internal Revenue Service and settled. At December 31, the deferred tax assets and liabilities consisted of the following:

Potomac Edison recorded as deferred income tax assets the effect of net operating losses, which will be realized through future operations and through the reversal of existing temporary differences. These net operating loss carry forwards expire in varying amounts through 2022. Potomac Edison is a party to a consolidating tax sharing agreement and expects to realize benefits represented by deferred tax assets through its participation in the consolidated Allegheny tax return in future years.

Total short-term income taxes receivable due from affiliates at December 31, 2002, was $31.7 million. Total short-term income taxes payable to affiliates at December 31, 2001, was $1.2 million. Total long-term income taxes payable to affiliates at December 31, 2002, was $45.2 million. There was no long-term income taxes receivable due from or payable to affiliates at December 31, 2001.

To provide interim financing and support for outstanding commercial paper, Allegheny and its regulated subsidiaries, including Potomac Edison, had established lines of credit with several banks. The lines of credit had fee arrangements and no compensating balance requirements. At December 31, 2002, the entire $335.0 million lines of credit with banks were drawn by Allegheny, and no amounts were available for Potomac Edison. At December 31, 2001, $14.4 million of the $400.0 million lines of credit with banks were drawn by an affiliate. All of the $385.6 million remaining lines of credit were supporting commercial paper, $24.2 million of which was issued by Potomac Edison and $361.4 million of which was issued by Allegheny. These facilities, which were refinanced in February 2003, required the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio, as defined under the credit agreements. On October 8, 2002, Allegheny announced that AE, AE Supply, and Allegheny Generating Company (AGC) were in default under these facilities after AE Supply declined to post additional collateral in favor of several trading counterparties. As of December 31, 2002, Allegheny had obtained waivers and amendments for these facilities.

In addition to bank lines of credit, Potomac Edison participates in an Allegheny internal money pool which accommodates intercompany short-term borrowing needs, to the extent that certain of Allegheny’s subsidiaries have funds available. The money pool provides funds to approved Allegheny subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven-day commercial paper rate, as quoted by the same source, less four basis points. At December 31, 2002 and 2001, Potomac Edison had borrowings outstanding from the money pool of $8.5 million and $33.4 million, respectively. Potomac Edison has SEC authorization for total short-term borrowings, from all sources, of $130 million.

As described in Note 1, Potomac Edison is responsible for its proportionate share of the net periodic cost (income) for pension and postretirement benefits other than pensions (principally health care and life insurance)

for employees and covered dependents provided by AESC. Potomac Edison’s share of the (credits) costs, of which approximately 26.8 percent in 2002 was (credited) charged to plant construction, was as follows:

Potomac Edison’s operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets, net of regulatory liabilities, reflected in the consolidated balance sheet at December 31 relate to:

SFAS No. 109, “Accounting for Income Taxes,” requires Potomac Edison to record a deferred income tax liability for tax benefits passed through to customers when temporary differences originate. These deferred income taxes relate to temporary differences involving regulated utility property, plant, and equipment and the related provision for depreciation. Potomac Edison records a regulatory asset for these income taxes since the amounts are recoverable from customers when the taxes are paid by Potomac Edison over the remaining depreciable lives of the property, plant, and equipment. Since the deferred income tax liability recorded under SFAS No. 109 is non-cash, no return is allowed on the income taxes regulatory asset.

The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:

The carrying amount of temporary cash investments and short-term debt, approximates the fair value because of the short maturities of those instruments. The fair value of notes and bonds was estimated based on actual market prices or market prices of similar issues. Potomac Edison had no financial instruments held or issued for trading purposes.

Other income and expenses represent nonoperating revenues and expenses before income taxes. The following table summarizes Potomac Edison’s other income and expenses for 2002, 2001, and 2000:

Potomac Edison owned 28 percent of the common stock of AGC until July 31, 2000. AGC owns an undivided 40 percent interest, 960 megawatts (MW), in the 2,400-MW pumped-storage hydroelectric station in Bath County, Virginia, operated by the 60 percent owner, Virginia Electric and Power Company, a nonaffiliated utility. On August 1, 2000, Potomac Edison transferred its 28 percent ownership in AGC to AE Supply at book value as a result of deregulation restructuring plans in Maryland, Virginia, and West Virginia. Potomac Edison reported AGC in its financial statements using the equity method of accounting.

Potomac Edison’s share of the earnings of AGC was $3.5 million for 2000, and is included in “Other income and expenses” on Potomac Edison’s consolidated statement of operations.

Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for Potomac Edison and its affiliates in accordance with PUHCA. Through AESC, Potomac Edison is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to Potomac Edison for 2002, 2001, and 2000 were $103.1 million, $89.9 million, and $109.1 million, respectively.

Potomac Edison purchases nearly all of the power necessary to serve its customers who do not choose an alternate electricity generation provider from its unregulated generation company affiliate, AE Supply, in accordance with agreements approved by the FERC. The expense from these purchases is reflected in “Purchased energy and transmission cost” on the consolidated statement of operations. For 2002, 2001, and 2000, Potomac Edison purchased power from AE Supply of $607.5 million, $424.7 million, and $188.8 million, respectively. Prior to Potomac Edison joining PJM Interconnection, LLC (PJM) in April 2002, if Potomac Edison purchased more electricity than was needed to serve its customers, the excess electricity purchased was sold back to AE Supply and reflected as operating revenues on the consolidated statement of operations. Upon Potomac Edison joining PJM, operational changes were made so that Potomac Edison no longer has excess electricity to sell back to AE Supply. For 2002, 2001, and 2000, Potomac Edison sold excess electricity back to AE Supply of $5.0 million, $20.2 million, and $38.7 million, respectively.

At December 31, 2002 and 2001, Potomac Edison had net accounts payable to affiliates of $40.8 million and $38.6 million, respectively.

See Note 8 for information regarding affiliated income taxes payable associated with Potomac Edison’s inclusion in Allegheny’s consolidated federal income tax return.

See Note 9 for information regarding Potomac Edison’s participation in an Allegheny internal money pool, the facility that accommodates short-term borrowing needs.

*Includes $.7 million for the correction of accounting errors related to years prior to 2002 (Note 2) and $.9 million for the correction of accounting errors related to the first quarter of 2002.

The corrections of accounting errors related to the first and second quarters of 2002 were primarily as follows:

Had Potomac Edison adjusted 2001 for the correction of errors discussed in Note 2 that were recorded in the first quarter of 2002, the 2001 quarterly consolidated net income would have been as follows:

SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets, was adopted by Potomac Edison on January 1, 2003. SFAS No. 143 requires that the fair value of asset retirement costs for which Potomac Edison has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss if settled at a different amount.

Potomac Edison has completed a detailed assessment of the specific applicability of SFAS No. 143 and recorded retirement obligations related to underground and aboveground storage tanks. Potomac Edison also has identified a number of retirement obligations associated with certain other assets that have not been recorded, because the fair value of such obligations cannot be reasonably estimated, due primarily to the indeterminate lives of the assets.

The effect of adopting SFAS No. 143 effective January 1, 2003 on Potomac Edison’s consolidated statement of operations will be a cumulative effect adjustment to decrease net income by $.08 million ($.13 million before income taxes). The effect of adopting SFAS No. 143 on Potomac Edison’s consolidated balance sheet will be a $.03 million increase in property, plant, and equipment, net and the recognition of a $.16 million liability for asset retirement obligations.

Potomac Edison has recorded in accumulated depreciation, removal costs collected from customers related to assets that do not have associated retirement obligations under SFAS No. 143. These estimated removal costs, totaling $146.8 million at December 31, 2002, represent a regulatory liability and remain in accumulated depreciation.

See Note 18 under “Guarantees” and “Variable Interest Entities,” for the effect of Potomac Edison’s adoption of FASB Interpretation Nos. (FIN) 45 and 46, respectively.

Potomac Edison has entered into commitments for its construction and capital programs for which expenditures are estimated to be $59.1 million (unaudited) for 2003 and $59.8 million (unaudited) for 2004.

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

Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) Claim: On March 4, 1994, Monongahela, Potomac Edison, and West Penn (the Distribution Companies) received notice that the EPA had identified them as potentially responsible parties (PRPs) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site. Initially approximately 175 PRPs were involved, however, the current number of active PRPs is approximately 80. The costs of remediation will be shared by all responsible parties. In 1999, a PRP group that included the Distribution Companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30 million.

However, Potomac Edison estimates that its share of the cleanup liability will not exceed $.2 million, which has been accrued as a liability at December 31, 2002.

Claims Related to Alleged Asbestos Exposure: Monongahela, Potomac Edison, and West Penn have also been named as defendants along with multiple other defendants in pending asbestos cases involving multiple plaintiffs. While Potomac Edison believes that all of the cases are without merit, Potomac Edison cannot predict the outcome of the litigation. Potomac Edison has accrued a reserve of $1.2 million as of December 31, 2002, related to the asbestos cases as the potential cost to settle the cases to avoid the anticipated cost of defense. During 2002, Potomac Edison received $.7 million of insurance recoveries (net of $.1 million of legal fees) related to these asbestos cases. During 2001, Potomac Edison received $.2 million of insurance recoveries related to these asbestos cases.

In the normal course of business, Potomac Edison becomes involved in various other legal proceedings. Potomac Edison does not believe that the ultimate outcome of these proceedings will have a material effect on its consolidated financial position, results of operations and cash flows.

Potomac Edison has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles and computer equipment.

The carrying amount of equipment recorded under capitalized lease agreements included in property, plant, and equipment was $12.9 million and $12.4 million at December 31, 2002 and 2001, respectively.

At December 31, 2002 and 2001, obligations under capital leases were as follows:

Total capital and operating lease rent payments of $6.6 million in 2002, $12.1 million in 2001, and $12.4 million in 2000 were recorded as rent expense in accordance with SFAS No. 71. Potomac Edison’s estimated future minimum lease payments for operating leases with annual payments exceeding $100,000 and initial or

remaining lease terms in excess of one year are $1.3 million in 2003; $1.0 million in 2004; $.4 million in 2005; $.2 million in 2006; and $.04 million in 2007. Potomac Edison’s estimated future minimum lease payments for capital leases with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are $2.1 million in 2003; $3.0 million in 2004; $2.3 million in 2005; $1.9 million in 2006; $1.8 million in 2007; and $3.5 million thereafter. The present value of estimated future minimum lease payments for capital leases is $12.9 million, reflecting interest expense of $1.7 million.

In January 2003, the FASB issued FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities,” which addresses consolidation by business enterprises of variable interest entities, commonly referred to as “special purpose entities.” FIN 46 requires consolidation where there is a controlling financial interest in a variable interest entity or where the variable interest entity does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties. Potomac Edison will apply the provisions of FIN 46 prospectively for all variable interest entities created after January 31, 2003. Potomac Edison is not involved in any transactions with variable interest entities. Potomac Edison does not believe that FIN 46 will have a material impact on its consolidated results of operations and financial position.

Under PURPA, electric utility companies, such as Potomac Edison, are required to interconnect with, provide back-up electric service to, and purchase electric capacity and energy from qualifying power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by the FERC. The appropriate state public service commission or legislature establishes the rates paid for electric energy purchased from such qualifying facilities.

Potomac Edison is committed to purchase the electrical output from 180 MW of qualifying PURPA capacity from the AES Warrior Run facility. Payments for PURPA capacity and energy in 2002 and 2001 totaled $91.8 million and $88.9 million, respectively. The average cost to Potomac Edison of these power purchases was approximately 6.4 cents/kilowatt-hour (kWh) and 6.1 cents/kWh for 2002 and 2001, respectively. Potomac Edison is currently authorized to recover these costs in its retail rates as described below.

As a result of the 1999 Maryland restructuring settlement, AES Warrior Run capacity and energy must be offered into the wholesale market over the life of the Electric Energy Purchase Agreement (PURPA contract). In November 2001, the Maryland PSC approved a Power Sales Agreement (PSA) between Potomac Edison and AE Supply, the winning bidder, covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2002 through December 31, 2004. Additionally, on January 2, 2002, the FERC accepted the PSA for filing, a requirement due to the length of the contract. The cost of purchases from AES Warrior Run under the PURPA contract not recovered through the market sale of the output to AE Supply will be recovered, dollar-for-dollar, from Maryland customers through a retail revenue surcharge.

The table below reflects Potomac Edison’s estimated commitments for energy and capacity purchases under the PURPA contract as of December 31, 2002. Actual values can vary substantially depending upon future conditions. The table does not reflect the AES Warrior Run energy and capacity sold under the PSA.

Letters of credit are purchased guarantees that ensure Potomac Edison’s performance or payment to third parties, in accordance with certain terms and conditions and amounted to $10.6 million as of December 31, 2002.

In November 2002, the FASB issued FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others,” which requires disclosures by a guarantor concerning its obligations under certain guarantees that it has issued. FIN 45 also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issued or modified after December 31, 2002. Potomac Edison has no guarantees outstanding as of December 31, 2002. Potomac Edison does not anticipate FIN 45 will have a material impact on its consolidated results of operations and financial position.

The management of The Potomac Edison Company (the Company), a wholly-owned subsidiary of Allegheny Energy, Inc. (Allegheny), is responsible for the information and representations in the Company’s financial statements. The Company prepares the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management’s best estimates and judgments of known conditions.

The Company is responsible for maintaining an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Company’s assets are protected. As discussed in Item 14 of Allegheny’s Annual Report on Form 10-K, Allegheny’s management has concluded that Allegheny’s internal controls are not adequate. Management and the Audit Committee of the Board of Directors of Allegheny are committed to devoting the additional resources necessary to ensure that the Company’s reporting is accurate and complete until internal controls are improved and are adequate.

Allegheny’s staff of internal auditors conducts periodic reviews designed to assist management in maintaining the effectiveness of internal control procedures. PricewaterhouseCoopers LLP, an independent accounting firm, audits the financial statements and expresses its opinion on them. The independent auditors perform their audit in accordance with auditing standards generally accepted in the United States of America.

The Audit Committee of the Board of Directors of Allegheny, which consists of outside Directors, meets periodically with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to all of the Company’s records and to the Audit Committee of Allegheny.

In our opinion, the accompanying consolidated balance sheets, consolidated statements of capitalization and the related consolidated statements of operations and cash flows, present fairly, in all material respects, the financial position of The Potomac Edison Company and its subsidiaries (the Company) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

West Penn Power Company (West Penn) is a wholly-owned subsidiary of Allegheny Energy, Inc. (AE, and collectively with AE’s consolidated subsidiaries, Allegheny) and along with its regulated utility affiliates, Monongahela Power Company (Monongahela) and The Potomac Edison Company (Potomac Edison), collectively doing business as Allegheny Power, operate electric and natural gas transmission and distribution (T&D) systems. West Penn’s business is the operation of an electric T&D system in Pennsylvania. West Penn operates under a single business segment, Delivery and Services.

West Penn is subject to regulation by the Securities and Exchange Commission (SEC), the Pennsylvania Public Utility Commission (Pennsylvania PUC), and the Federal Energy Regulatory Commission (FERC).

Certain amounts in the December 31, 2001, consolidated balance sheet and in the December 31, 2001, and 2000, consolidated statements of operations and consolidated statements of cash flows have been reclassified for comparative purposes. Significant accounting policies of West Penn and its subsidiaries are summarized below.

The preparation of financial statements in conformity with generally accepted accounting principles of the United States of America (GAAP) requires West Penn to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. On a continuous basis, West Penn evaluates its estimates, including those related to the calculation of unbilled revenues, provisions for depreciation and amortization, adverse power purchase commitments, regulatory assets, income taxes, pensions and other postretirement benefits, and contingencies related to environmental matters and litigation. West Penn bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

The consolidated financial statements reflect investments in controlled subsidiaries on a consolidated basis. The consolidated financial statements include the accounts of West Penn and all subsidiary companies after elimination of intercompany transactions and balances and are prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of the FERC and applicable state regulatory commissions.

Revenues from the sale of electricity to customers are recognized in the period that the electricity is delivered and consumed by customers, including an estimate for unbilled revenues.

Upon retirement, the cost of depreciable property, plus removal costs less salvage, are charged to accumulated depreciation in accordance with the provisions of the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”

West Penn capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over the expected useful life of the software beginning upon a project’s completion.

West Penn adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. Long-lived assets owned by West Penn are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, resulting in the asset being written down to its fair value. The fair value is determined by the use of quoted market prices, appraisals, or the use of other valuation techniques, such as expected discounted future cash flows.

AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is recognized as a cost of property, plant, and equipment. Rates used for computing AFUDC in 2002, 2001, and 2000 averaged 7.07 percent, 7.46 percent, and 7.05 percent, respectively.

Depreciation expense is determined generally on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 2.8 percent of average depreciable property in 2002 and 2.9 percent in 2001 and 2000. Estimated service lives for T&D property range from 10 to 60 years and for all other property range from 5 to 60 years. Depreciation expense was $44.8 million, $46.2 million, and $45.2 million for 2002, 2001, and 2000, respectively. Depreciation expense is provided for under currently enacted regulatory rates.

Maintenance expenses represent costs incurred to maintain the T&D system and general plant, and reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from periodic storm damage to the T&D system. Maintenance costs are expensed in the year incurred.

West Penn adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” on January 1, 2002. SFAS No. 142 requires that intangible assets with indefinite lives not be amortized, but, rather, be tested for impairment at least annually. Intangible assets with finite lives are to be amortized over their useful lives and tested for impairment when events or circumstances warrant. West Penn has intangible assets consisting of amortized land easements, which are included in property, plant, and equipment on the consolidated balance sheet, with a gross carrying amount and accumulated amortization as follows: at December 31, 2002, $38.7 million and $9.2 million, respectively, and at December 31, 2001, $38.9 million and $8.7 million, respectively. Amortization expense was $.5 million in 2002 and 2001. Amortization expense is estimated to be $.5 million annually for 2003 through 2007.

West Penn has various operating transactions with its affiliates. It is West Penn’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented net on the consolidated balance sheet and the consolidated statement of cash flows. See Note 13 for additional information on related party transactions.

In accordance with SFAS No. 71, West Penn’s consolidated financial statements include certain assets and liabilities resulting from cost-based ratemaking regulation.

West Penn joins with Allegheny and its affiliates in filing a consolidated federal income tax return. The consolidated income 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 income tax liability.

Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred tax assets and liabilities represent the tax effect of certain income temporary differences between the financial statement and tax basis of assets and liabilities computed using the most current tax rates. See Note 7 for additional information regarding income taxes.

West Penn has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant, and equipment.

Substantially all of the employees of Allegheny are employed by Allegheny Energy Service Corporation (AESC), a wholly-owned subsidiary of Allegheny, which performs services at cost for West Penn and its affiliates in accordance with PUHCA. Through AESC, West Penn is responsible for its proportionate share of postretirement benefit costs.

AESC provides a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on each employee’s years of service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act of 1974 (ERISA) and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed income securities, short-term investments, and insurance contracts.

West Penn does not have any elements of other comprehensive income to report in accordance with SFAS No. 130, “Reporting Comprehensive Income.”

After Allegheny filed its quarterly report on Form 10-Q for the period ended June 30, 2002, Allegheny identified a miscalculation in its business segment information. Following the discovery of this miscalculation, and in light of Allegheny’s prior restatements of reports filed with the SEC, Allegheny initiated a comprehensive review of its financial processes, records, and internal controls to ensure that its current and prior financial statements are fairly presented in accordance with GAAP.

As a result of Allegheny’s comprehensive accounting review, Allegheny identified, prior to closing its books for 2002, various errors relating to the financial statements for 2001, 2000, and years prior to 2000. Allegheny’s management concluded that these errors for West Penn were not material, either individually or in the aggregate, to the current year or any prior year’s financial statements. Accordingly, prior year financial statements have not been restated. These adjustments related to West Penn, which decrease net income, aggregate approximately $2.3 million, net of income taxes, and have been recorded in the first quarter of 2002. The nature and amounts of these adjustments are primarily as follows:

In addition, Allegheny identified an adjustment for West Penn affecting only years prior to the year 2002 as follows:

The years to which the income (charges), net of income taxes, relate are as follows:

Had the adjustments listed above been recorded in the appropriate years, the following table demonstrates the effect on consolidated net income:

While certain changes in policies and procedures have been instituted, additional changes are needed to improve the internal control structure of Allegheny.

Allegheny’s management, Audit Committee, and Board of Directors are fully committed to the resolution of Allegheny’s internal control deficiencies, ultimate resolution of the deficiencies will include changing the culture of the accounting function to focus on accountability and the strict, timely adherence to a set of sound internal control policies and procedures. Management has commenced or is undertaking the following corrective actions in order to achieve an immediate improvement in the controls environment:

West Penn had several debt agreements that required it to file copies of its annual or quarterly reports as filed with the SEC pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) with the debt holders. West Penn is also required to deliver to the trustee under its indentures a certificate indicating that West Penn has complied with all conditions and covenants under the agreement. On April 30, 2003, Allegheny provided certificates to the trustee under its indentures indicating that it was not in compliance with the covenants for filing its annual and quarterly reports that are contained in its Transition Bonds and Medium Term Notes. The covenant breach of the Transition Bonds and Medium Term Notes is deemed a default under the related debt agreements for West Penn’s financial reporting purposes in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived by the Creditor”. The total debt classified as current in the accompanying consolidated balance sheet related to such default was approximately $510.2 million as of December 31, 2002. To date, the debt holders have not provided West Penn with any notices of default under the agreement. Such notices, if received, would allow West Penn either 30 or 60 days to cure its noncompliance before the debt holders could accelerate the due dates of the debt obligations.

West Penn has prepared its financial statements assuming that it will continue as a going concern. However, noncompliance with its debt covenants and the classification of certain debt as current has caused its independent auditors, PricewaterhouseCoopers LLP, to issue a modified opinion that indicates there is substantial doubt about West Penn’s ability to continue as a going concern (a “Going Concern” opinion). The financial statements do not include any adjustments that might result from the resolution of this uncertainty. Management’s plans with respect to this matter are discussed below.

Management plans to file its Annual Report on Form 10-K for the period ended December 31, 2003 on a timely basis.

In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities include a company-wide workforce reduction. For the year ended December 31, 2002, West Penn recorded a charge for its allocable share of the workforce reduction expenses of $19.4 million, before income taxes ($11.4 million, net of income taxes).

related costs are accounted for in accordance with 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).” For the year ended December 31, 2002, West Penn recorded a charge of $.1 million, before income taxes, for its allocable share of the effect of the SRSP, related to approximately 80 of Allegheny’s employees whose positions have been or are being eliminated. Allegheny has essentially completed these planned workforce reductions. Workforce reduction costs are recorded in “Workforce reduction expenses” on the consolidated statement of operations.

See Note 3, “Debt Covenants,” for a description of the defaults under West Penn’s current debt agreements. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was $510.2 million as of December 31, 2002.

Contractual maturities for notes and bonds, in millions of dollars, for the next five years, excluding unamortized debt discounts and premiums are: 2003, $76.0; 2004, $157.7; 2005, $73.0; 2006, $75.8; 2007, $79.9 and thereafter, $124.3.

During 2002, West Penn Funding, LLC (West Penn Funding) repaid $70.3 million of class A-2 6.63-percent transition bonds. During 2001, West Penn Funding repaid $27.2 million of class A-1 6.32-percent transition bonds and $33.0 million of class A-2 6.63-percent transition bonds.

In September 2002, West Penn repaid $32.1 million of 5.66-percent notes and $1.5 million of 5.56-percent notes.

In April 2002, West Penn issued $80.0 million of 6.625-percent notes due April 15, 2012. In May 2002, West Penn used the net proceeds from the notes to redeem $70.0 million principal amount of 8.0-percent Quarterly Income Debt Securities (QUIDS) due June 30, 2025, at a redemption price of 100-percent of their principal amount plus accrued interest to the redemption date, and for other corporate purposes.

West Penn follows EITF Issue No. 97-4, “Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statement Nos. 71 and 101,” which provides that, when a rate order is issued that contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated, the entity should cease to apply SFAS No. 71 to that separable portion of its business.

On May 29, 1998, the Pennsylvania PUC issued an order approving a transition plan for West Penn. This order was subsequently amended by a settlement agreement approved by the Pennsylvania PUC on November 19, 1998. West Penn recorded an extraordinary charge under the provisions of SFAS No. 101 “Accounting for the Discontinuation of Application of FASB Statement No. 71,” in 1998 to reflect the disallowances of certain costs in the Pennsylvania PUC’s May 29, 1998, order, as revised by the Pennsylvania PUC-approved November 19, 1998, settlement agreement. This charge included an estimated amount for an adverse power purchase commitment, which reflects a commitment to purchase power at above-market prices. As of December 31, 2002, West Penn’s reserve for adverse power purchase commitments was $255.2 million, based on West Penn’s forecast of future energy revenues and other factors.

Based on the forecast mentioned above, West Penn’s reserve for adverse power purchase commitments decreased as follows for 2002, 2001, and 2000:

The above decreases in the liability for adverse power purchase commitments are recorded as expense reductions in “Purchased energy and transmission” on the consolidated statement of operations. A change in the estimated energy revenues or other factors could have a material effect on the amount of the estimated liability for adverse power purchase commitments.

The total provision for income tax expense is different from the amount produced by applying the federal statutory income tax rate of 35 percent to financial accounting income, as set forth below:

West Penn recorded as deferred income tax assets the effect of net operating losses, which will be realized through future operations and through the reversal of existing temporary differences. These net operating loss carry forwards expire in varying amounts through 2022. In addition, West Penn is a party to a consolidating tax sharing agreement and expects to realize benefits represented by deferred tax assets through its participation in the Allegheny consolidated tax return in future years.

Total short-term income taxes receivable due from affiliates at December 31, 2002, was $1.0 million. Total short-term income taxes payable to affiliates at December 31, 2001, was $3.6 million. Total long-term income taxes payable to affiliates at December 31, 2002, was $24.0 million.

To provide interim financing and support for outstanding commercial paper, Allegheny and its regulated subsidiaries, including West Penn, had established lines of credit with several banks. These lines of credit had fee arrangements and no compensating balance requirements. At December 31, 2002, the entire $335.0 million lines of credit with banks were drawn by Allegheny, and no amounts were available for West Penn. At December 31, 2001, $14.4 million of the $400.0 million lines of credit with banks were drawn by an affiliate. All of the $385.6 million remaining lines of credit were supporting commercial paper issued by Allegheny and an affiliate, and no amounts were available to West Penn. These facilities, which were refinanced in February 2003, required the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio, as defined under the credit agreements. On October 8, 2002, Allegheny announced that AE, Allegheny Energy Supply Company, LLC (AE Supply), and Allegheny Generating Company (AGC) were in technical default under these facilities after AE Supply declined to post additional collateral in favor of several trading counterparties. As of December 31, 2002, Allegheny had obtained waivers and amendments for these facilities. See Note 17 for additional details regarding the Borrowing Facilities that were entered into in February 2003.

In addition to bank lines of credit, West Penn participates in an Allegheny internal money pool, which accommodates intercompany short-term borrowing needs, to the extent that certain of Allegheny’s subsidiaries

have funds available. The money pool provides funds to approved Allegheny subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven-day commercial paper rate, as quoted by the same source, less four basis points. At December 31, 2002 and 2001, West Penn had no borrowings outstanding from the money pool. West Penn has SEC authorization for total short-term borrowings, from all sources, of $500.0 million.

No short-term debt was outstanding as of December 31, 2002 and 2001. Average amounts for short-term debt outstanding during 2002 and 2001 consisted of:

As described in Note 1, West Penn is responsible for its proportionate share of the cost for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. West Penn’s share of the costs (Income), of which approximately 27 percent in 2002 was (credited) charged to plant construction, was as follows:

West Penn’s operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets, net of regulatory liabilities, reflected in the consolidated balance sheet at December 31 relate to:

SFAS No. 109, “Accounting for Income Taxes,” requires West Penn to record a deferred income tax liability for tax benefits passed through to customers when temporary differences originate. These deferred income taxes relate to temporary differences involving regulated utility property, plant, and equipment and the related provision for depreciation. West Penn records a regulatory asset for these income taxes, since the amounts are recoverable from customers when the taxes are paid by West Penn over the remaining depreciable lives of the property, plant, and equipment. Since the deferred income tax liability recorded under SFAS No. 109 represents a non-cash item, no return is allowed on the income taxes regulatory asset.

In 1998, West Penn recorded a regulatory asset for Pennsylvania stranded cost recovery, representing the portion of transition costs determined by the Pennsylvania PUC to be recoverable by West Penn under its deregulation plan. The CTC regulatory asset is being recovered over the transition period that will end in 2008. CTC rates include return on, as well as recovery of, transition costs.

The Pennsylvania PUC authorized West Penn to defer the difference between authorized and billed CTC revenues, with an 11-percent return on the deferred amounts, for future full and complete recovery. The amount of under-recovery of CTC during the transition period, if any, will be determined at the end of the transition period, which extends through 2008. On an annual basis, the Pennsylvania PUC has approved the amount of CTC true-up recorded as a regulatory asset by West Penn.

See Note 15 for a discussion of a regulatory liability identified in conjunction with the application of a new accounting pronouncement.

The carrying amounts and estimated fair values of financial instruments at December 31 were as follows:

The carrying amount of temporary cash investments approximates the fair value because of the short maturity of those instruments. The fair value of notes, bonds and QUIDS was estimated based on actual market prices or market prices of similar issues. West Penn had no financial instruments held or issued for trading purposes.

Other income and expenses represent nonoperating revenues and expenses before income taxes. The following table summarizes West Penn’s other income and expenses for 2002, 2001, and 2000:

Premium services, net represents revenues and related expenses associated with nonregulated products and services provided to customers.

Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for West Penn and its affiliates in accordance with PUHCA. Through AESC, West Penn is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to West Penn for 2002, 2001, and 2000 were $159.3 million, $145.2 million, and $148.9 million, respectively.

West Penn purchases nearly all of the power necessary to serve its customers who do not choose an alternate electricity generation provider from its unregulated generation company affiliate, AE Supply, in accordance with agreements approved by the FERC. The expense from these purchases is reflected in “Purchased energy and transmission” on the consolidated statement of operations. For 2002, 2001, and 2000, West Penn purchased power from AE Supply of $595.4 million, $565.5 million, and $522.8 million, respectively. Prior to West Penn joining PJM Interconnection, LLC (PJM) in April 2002, if West Penn purchased more electricity than was needed to serve its customers, the excess electricity purchased was sold back to AE Supply and is reflected as operating revenues on the consolidated statement of operations. Upon West Penn joining PJM, operational changes were made so that West Penn no longer has excess electricity to sell back to AE Supply. For 2002, 2001, and 2000, West Penn sold excess electricity back to AE Supply of $11.9 million, $34.1 million, and $28.1 million, respectively.

At December 31, 2002 and 2001, West Penn had net accounts payable to affiliates of $45.7 million and $36.3 million, respectively.

See Note 7 for information regarding affiliated income taxes payable associated with West Penn’s inclusion in Allegheny’s consolidated federal income tax return.

See Note 8 for information regarding West Penn’s participation in an Allegheny internal money pool, a facility that accommodates short-term borrowing needs.

The quarterly amounts included in the table above reflect the adjustments identified in Allegheny’s comprehensive financial review, as discussed in Note 2. The following table summarizes the effect of the adjustments on amounts previously reported for West Penn’s first and second quarter 2002 total operating revenues, net revenues, operating income, and consolidated net income. The amounts shown as previously reported for net revenues and total operating income reflect reclassifications in West Penn’s presentation of its Statement of Operations after the Forms 10-Q for the first and second quarters of 2002 were filed. The reclassifications were made to provide consistent presentation among Allegheny’s various SEC registrants. In aggregate, the reclassifications had no effect on previously reported total operating revenues and consolidated net income.

The corrections of accounting errors related to the first and second quarters of 2002 were primarily as follows:

Had West Penn adjusted 2001 for the correction of errors discussed in Note 2 that were recorded in the first quarter of 2002, the 2001 quarterly consolidated net income would have been as follows:

Asset Retirement Obligations SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets, was adopted by West Penn on January 1, 2003. SFAS No. 143 requires that the fair value of asset retirement costs for which West Penn has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or records a gain or loss if settled at a different amount.

West Penn has completed a detailed assessment of the specific applicability of SFAS No. 143 and will record retirement obligations primarily related to closed ash landfills and underground and aboveground storage tanks. West Penn also has identified a number of retirement obligations associated with certain other assets that have not been recorded, because the fair value of such obligations cannot be reasonably estimated, due primarily to the indeterminate lives of the assets.

The effect of adopting SFAS No. 143, effective January 1, 2003, on West Penn’s consolidated statement of operations will be a cumulative effect adjustment to decrease net income by $.7 million, net of income taxes ($1.2 million, before income taxes). The effect of adopting SFAS No. 143 on West Penn’s consolidated balance sheet will be the recognition of a $1.2 million liability for asset retirement obligations.

West Penn has recorded in accumulated depreciation, actual removal costs incurred less amounts collected from customers related to assets that do not have associated retirement obligations under SFAS No. 143. These estimated net removal costs, totaling $8.8 million at December 31, 2002, represent a regulatory asset and remain in accumulated depreciation.

See Note 16, under “Guarantees” and “Variable Interest Entities,” for the effect of West Penny’s adoption of FASB Interpretation Nos. (FIN) 45 and 46, respectively.

West Penn has entered into commitments for its construction and capital programs for which expenditures are estimated to be $45.4 million (unaudited) for 2003 and $58.9 million (unaudited) for 2004.

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

Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) Claim: On March 4, 1994, Monongahela, Potomac Edison, and West Penn (the Distribution Companies) received notice that the EPA had identified them as potential responsible parties (PRPs) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site. Initially approximately 175 PRPs were involved, however, the current number of active PRPs is approximately 80. The cost of remediation will be shared by all responsible parties. In 1999, a PRP group that included the Distribution Companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30 million. However, West Penn estimates that its share of the cleanup liability will not exceed $.5 million, which has been accrued as a liability at December 31, 2002.

Claims Related to Alleged Asbestos Exposure: Monongahela, Potomac Edison, and West Penn have also been named as defendants along with multiple other defendants in pending asbestos cases involving multiple plaintiffs. While West Penn believes that all of the cases are without merit, West Penn cannot predict the outcome of the litigation. West Penn has accrued a reserve of $1.2 million as of December 31, 2002, related to the asbestos cases as the potential cost to settle the cases to avoid the anticipated cost of defense. During 2002, West Penn received $.8 million of insurance recoveries (net of $.1 million of legal fees) related to these asbestos cases. During 2001, West Penn received $.2 million of insurance recoveries related to these asbestos cases.

Other: As part of the National Pollutant Discharge Elimination System (NPDES) permit review process at the Connellsville West Side facility, oil contamination has been noted at the facility. Steps have been taken to control the oil and monitoring is continuing at the site. The internal investigation into the source of the oil is ongoing in accordance with several Pennsylvania Department of Environmental Protection (PADEP) programs. West Penn accrued a liability of $.8 million in December 2001, as an estimate of the total remediation cost at the facility. At December 31, 2002, the accrued liability balance was $.04 million.

In the normal course of business, West Penn becomes involved in various other legal proceedings. West Penn does not believe that the ultimate outcome of these proceedings will have a material effect on its consolidated financial position, results of operations and cash flows.

West Penn has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles and computer equipment.

The carrying amount of equipment recorded under capitalized lease agreements included in property, plant, and equipment was $15.8 million and $16.9 million at December 31, 2002 and 2001, respectively.

At December 31, 2002 and 2001, obligations under capital leases were as follows:

Total capital and operating lease rent payments of $9.2 million in 2002, $16.7 million in 2001, and $16.8 million in 2000 were recorded as rent expense in accordance with SFAS No. 71. West Penn’s estimated future minimum lease payments for operating leases with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are $2.0 million in 2003; $1.2 million in 2004; $.7 million in 2005; $.3 million in 2006; and $.1 million in 2007. West Penn’s estimated future minimum lease payments for capital leases with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are $2.8 million in 2003; $3.7 million in 2004; $2.8 million in 2005; $2.4 million in 2006; $2.0 million in 2007; and $3.5 million thereafter. At December 31, 2002, the present value of estimated future minimum lease payments for capital leases included in consolidated balance sheet was $15.8 million, and reflected a difference of $1.4 million from the total annual payments disclosed above due to interest expense.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities,” which addresses consolidation by business enterprises of variable interest entities, commonly referred to as “special purpose entities.” FIN 46 requires consolidation where there is a controlling financial interest in a variable interest entity or where the variable interest entity does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties. West Penn will apply the provisions of FIN 46 prospectively for all variable interest entities created after January 31, 2003. West Penn is not involved in any transactions with variable interest entities. West Penn does not believe that FIN 46 will have a material impact on its consolidated statement of operations and financial position.

Under PURPA, electric utility companies, such as West Penn, are required to interconnect with, provide back-up electric service to, and purchase electric capacity and energy from qualifying small power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by the FERC. The appropriate state public service commission or legislature establishes the rates paid for electric energy purchased from such qualifying facilities.

West Penn is committed to purchasing the electrical output from 138 MW of qualifying PURPA capacity—125 MW through 2016 and an additional 13 MW through 2034. Payments for PURPA capacity and energy in 2002 and 2001 totaled $53.9 million and $53.2 million, respectively, before amortization of West Penn’s adverse power purchase commitment, according to these contracts. The average cost to West Penn of these power purchases was approximately 4.9 cents/kilowatt-hour (kWh) and 4.7 cents/kWh for 2002 and 2001, respectively. West Penn is currently authorized to recover these costs in its retail rates.

The table below reflects West Penn’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2002. Actual values can vary substantially depending upon future conditions.

Letters of credit are purchased guarantees that ensure West Penn’s performance or payment to third parties, in accordance with certain terms and conditions. As of December 31, 2002, West Penn had no outstanding letters of credit.

In November 2002, the FASB issued Fin 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others,” which requires disclosures by a guarantor concerning its obligations under certain guarantees that it has issued. FIN 45 also requires recognizing, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees issued or modified after December 31, 2002. West Penn has no guarantees outstanding as of December 31, 2002. West Penn does not anticipate FIN 45 will have a material effect on its statement of operations and financial position.

In February and March 2003, AE, AE Supply, Monongahela, and West Penn entered into agreements (Borrowing Facilities), totaling $2,447.8, with various credit providers and restructure the bulk of AE and AE Supply’s short-term debt.

The Borrowing Facilities at AE, Monongahela, and West Penn include a $305.0 million unsecured credit facility under which AE, Monongahela, and West Penn are the designated borrowers, and under which AE borrowed the full facility amount. This facility bears interest at a London Interbank Offering Rate (LIBOR)-based rate plus a margin of five percent or a designated money center bank’s base rate plus four percent.

The terms of the Borrowing Facilities require that Allegheny, on a consolidated basis, meet certain financial tests, as defined in the Borrowing Facilities agreements. The Borrowing Facilities also have provisions requiring prepayments out of the proceeds of asset sales, debt and equity issuances, and excess cash flows, as defined in the agreements, by Allegheny, including West Penn. Any prepayments under the provisions of the Borrowing Facilities reduce the amounts of scheduled principal payments in 2003 and 2004. Effective July 22, 2003 and August 22, 2003, Allegheny was granted waivers from compliance with all of the above financial tests for the first, second and third quarters of 2003.

The Borrowing Facilities also contain restrictive covenants that limit West Penn’s ability to: borrow funds; incur liens; enter into a merger or other change of control transaction; make investments; prepay indebtedness; amend contracts; pay dividends and other distributions on West Penn’s equity; and operate West Penn’s business, by requiring it to adhere to an agreed business plan.

The management of West Penn Power Company (the Company), a wholly-owned subsidiary of Allegheny Energy, Inc. (Allegheny), is responsible for the information and representations in the Company’s financial statements. The Company prepares the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management’s best estimates and judgments of known conditions.

The Company is responsible for maintaining an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Company’s assets are protected. As discussed in Item 14, of Allegheny’s Annual Report on Form 10-K, Allegheny’s management has concluded that Allegheny’s internal controls are not adequate. Management and the Audit Committee of the Board of Directors are committed to devoting the additional resources necessary to ensure that the Company’s reporting is accurate and complete until internal controls are improved and are adequate.

The Audit Committee of the Board of Directors of Allegheny, which consists of outside Directors, meets periodically with management, internal auditors and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to all of the Company’s records and to the Audit Committee of Allegheny.

In our opinion, the accompanying consolidated balance sheets, consolidated statements of capitalization and the related consolidated statements of operations and cash flows, present fairly, in all material respects, the financial position of West Penn Power Company and its subsidiaries (the Company) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Allegheny Generating Company (AGC) is owned 77.03 percent by Allegheny Energy Supply Company, LLC (AE Supply) and 22.97 percent by Monongahela Power Company (Monongahela) (collectively the Parents). The Parents are subsidiaries of Allegheny Energy, Inc. (AE, and collectively with AE’s consolidated subsidiaries, Allegheny), a diversified utility holding company whose principal business segments are the Generation and Marketing segment and the Delivery and Services segment. The Generation and Marketing segment includes AE Supply, AGC, and Monongahela’s generation for its West Virginia regulatory jurisdiction, which has not deregulated electric generation. AGC owns an undivided 40 percent interest, 960 megawatts (MW), in the 2,400-MW pumped-storage hydroelectric station in Bath County, Virginia, operated by the 60 percent owner, Virginia Electric and Power Company, a nonaffiliated utility. AGC sells its generating capacity to its Parents. AGC operates under a single business segment, Generation and Marketing.

AGC is subject to regulation by the Securities and Exchange Commission (SEC), the Virginia State Corporation Commission (Virginia SCC), and the Federal Energy Regulatory Commission (FERC).

Certain amounts in the December 31, 2001, balance sheet and in the December 31, 2001, and 2000, statements of operations and statements of cash flows have been reclassified for comparative purposes. Significant accounting policies of AGC are summarized below.

As part of Allegheny’s comprehensive accounting review, Allegheny identified, prior to closing its books for 2002, various adjustments relating to the financial statements for 2001, 2000, and prior to 2000. Such adjustments were identified for certain Allegheny subsidiaries; however, no such adjustments were identified for AGC. With respect to those Allegheny subsidiaries where adjustments were identified, Allegheny’s management concluded that those adjustments were not material, either individually or in the aggregate, to the current year or any prior year. Accordingly, prior year financial statements have not been restated, and those adjustments have been recorded as of January 1, 2002.

The preparation of financial statements in conformity with generally accepted accounting principles of the United States of America (GAAP) requires AGC to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. On a continuous basis, AGC evaluates its estimates, including those related to the calculation of the provision for depreciation, regulatory assets, income taxes, pensions and other postretirement benefits, and contingencies related to environmental matters and litigation. AGC bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Revenues are determined under a cost-of-service rate schedule approved by the FERC. Under this arrangement, AGC recovers in revenues all of its operation expense, depreciation, taxes, and a return on its investment. All sales are made to AGC’s Parents.

Costs incurred to issue are recorded as deferred charges on the balance sheet. These costs are amortized on a straight-line basis over the lives of the related debt securities, which does not differ materially from the effective interest method.

Property, plant, and equipment are stated at original cost, and consist of a 40 percent undivided interest in the Bath County pumped-storage hydroelectric station and its connecting transmission facilities. Upon retirement, the cost of depreciable property, plus removal costs less salvage, are charged to accumulated depreciation in accordance with the provisions of Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”

AGC adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. Long-lived assets owned by AGC are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, resulting in the asset being written down to its fair value. The fair value is determined by the use of quoted market prices, appraisals, or the use of other valuation techniques, such as expected discounted future cash flows.

Depreciation expense is determined on a straight-line method based on the estimated service lives of depreciable properties and amounted to approximately 2.1 percent of average depreciable property in 2002, 2001, and 2000. The estimated service life for generation property is 35 years, T&D property is 35 years, and all other property is 20 years. Depreciation expense is provided for under currently enacted regulatory rates.

Maintenance expenses represent costs incurred to maintain the power station and general plant and reflect routine maintenance of equipment, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power station. Maintenance costs are expensed in the year incurred. Power station maintenance costs are expensed within the year based on estimated annual costs and estimated generation. Power station maintenance accruals are not intended to accrue for future years’ costs.

AGC adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” on January 1, 2002. SFAS No. 142 requires that intangible assets with indefinite lives not be amortized, but, rather, be tested for impairment at least annually. AGC has intangible assets consisting of amortized land easements, which are included in property, plant, and equipment on the balance sheet, with a gross carrying amount and accumulated amortization as follows: At December 31, 2002, $1.4 million and $.7 million, respectively, and at December 31, 2001, $1.4 million and $.6 million, respectively. Amortization expense was less than $.1 million in 2002 and 2001. Amortization expense is estimated to be less than $.1 million annually for 2003 through 2007.

For purposes of the statement of cash flows and balance sheet, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, and repurchase agreements, are considered to be the equivalent of cash.

AGC has various operating transactions with its affiliates. It is AGC’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented net on the balance sheet and the statement of cash flows. See Note 10 for additional information on related party transactions.

In accordance with SFAS No. 71, AGC’s financial statements include certain assets and liabilities resulting from cost-based ratemaking regulation.

AGC joins with its Parents and affiliates in filing a consolidated federal income tax return. The consolidated income 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 income tax liability.

Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the financial statement and tax basis of assets and liabilities computed using the most current tax rates. See Note 5 for additional information regarding income taxes.

AGC has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant, and equipment.

Substantially all of the employees of Allegheny are employed by Allegheny Energy Service Corporation (AESC), a wholly-owned subsidiary of AE, which performs services at cost for AGC and its affiliates in accordance with the PUHCA. Through AESC, AGC is responsible for its proportionate share of postretirement benefit costs.

AGC does not have any elements of other comprehensive income to report in accordance with SFAS No. 130, “Reporting Comprehensive Income.”

On October 8, 2002, Allegheny announced that AE, AE Supply, and AGC were in default under their principal credit agreements after AE Supply declined to post additional collateral in favor of several trading counterparties. The collateral calls followed the downgrading of Allegheny’s credit rating below investment grade by Moody’s. AGC was a participant in these principal credit agreements through Allegheny. During the period November 2002 through February 2003, AE, AE Supply and AGC obtained waivers of, and amended, certain covenants to these principal credit agreements. The total debt classified as current, in accordance with EITF Issue No. 86-30, “Classification of Obligations When a Violation is Waived by the Creditor,” in the accompanying consolidated balance sheet related to such defaults was approximately $100.0 million as of December 31, 2002.

AGC has prepared its financial statements assuming that it will continue as a going concern. However, noncompliance with its debt covenants and the classification of certain debt as current has caused its independent auditors to issue a modified opinion that indicates there is substantial doubt about AGC’s ability to continue as a going concern (a “Going Concern” opinion). The financial statements do not include any adjustments that might result from the resolution of this uncertainty. Management’s plans with respect to this matter are discussed below.

On February 25, 2003, AE Supply provided AGC with a loan of $55.0 million in order for AGC to repay amounts outstanding under its principal credit agreements. On September 1, 2003, AGC received an equity contribution of $40.0 million from its parent companies based on their ownership percentages as described in Note 1, Summary of Significant Accounting Policies. Accordingly, AE Supply contributed $30.8 million and Monongahela contributed $9.2 million. The equity contributions were used to repay the $50.0 million, 5 5/8 percent debenture which matured on September 1, 2003. AE Supply and Monongahela will continue to provide assistance with AGC’s obligations as they come due.

In July of 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction. For the year ended December 31, 2002, AGC recorded a charge for its allocable share of the workforce reductions of $.02 million, before income taxes ($.01 million, net of income taxes).

AGC systematically reduces capitalization as its assets depreciate. In previous periods, this resulted in the payment of dividends in excess of current earnings. The SEC granted approval to AGC to allow it to pay common dividends out of capital. Common dividends were paid from retained earnings, reducing the account balance to zero, and from other paid-in-capital. In 2002, the level of dividends paid was reduced in order to meet

a capital structure objective to increase AGC’s equity percentage to approximately 40 percent. In 2002 dividends were paid entirely out of retained earnings. However, in prior years common dividends were paid from retained earnings and from other paid-in capital as follows:

See Note 2, “Debt Covenants,” for a description of the defaults under Allegheny’s current debt agreements. The total debt classified as current in the accompanying consolidated balance sheet related to such defaults was $100.0 million as of December 31, 2002.

On September 1, 2003 AGC received an equity contribution of $40.0 million from its Parent companies based on their ownership percentages as described in Management’s Discussion and Analysis of Financial Condition and Results of Operations, Overview. Accordingly, AE Supply contributed $30.8 million and Monongahela contributed $9.2 million. The equity contributions were used to repay the $50.0 million, 5 5/8 percent debenture which matured on September 1, 2003.

The total provision for income tax expense is different from the amount produced by applying the federal statutory income tax rate of 35 percent to financial accounting, as set forth below:

Federal income tax returns through 1997 have been examined by the Internal Revenue Service and settled. At December 31, the deferred income tax assets and liabilities consisted of the following:

To provide interim financing and support for outstanding commercial paper, Allegheny and its subsidiaries, including AGC, had established lines of credit with several banks. The lines of credit had fee arrangements and no compensating balance requirements. At December 31, 2002, AGC had $55.0 million drawn against lines of credit totaling $579.0 million in which AE Supply and AGC were participants. AGC had no amounts drawn against lines of credit totaling $150.0 million in which Allegheny and its regulated subsidiaries, including AGC, were participants. At December 31, 2001, AGC had no amounts drawn against lines of credit totaling $290.0 million in which Allegheny and its regulated subsidiaries, including AGC, were participants. These facilities, which were refinanced in February 2003, required the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio, as defined under the agreements. On October 8, 2002, Allegheny announced that AE, AE Supply, and AGC were in default under these facilities after AE Supply declined to post additional collateral in favor of several trading counterparties. As of December 31, 2002, Allegheny had obtained waivers and amendments for these facilities. See Note 14 for additional details regarding the Borrowing Facilities that were entered into in February 2003.

In addition to bank lines of credit, through August 2002 AGC participated in an Allegheny internal money pool, which accommodates intercompany short-term borrowing needs to the extent that certain of Allegheny’s

subsidiaries have funds available. The money pool provides funds to approved Allegheny subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven-day commercial paper rate, as quoted by the same source, less four basis points. Because AGC’s participation in the money pool ended in August 2002, AGC had no borrowings outstanding from the money pool at December 31, 2002. At December 31, 2001, AGC had borrowings outstanding from the money pool of $62.9 million. AGC has SEC authorization for total short-term borrowings, from all sources, of $100 million.

As described in Note 1, AGC is responsible for its proportionate share of the net periodic cost (income) for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. AGC’s share of the costs of these plans was as follows:

AGC’s operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory liabilities, net of regulatory assets, reflected in the balance sheet at December 31 relate to:

The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:

The carrying amounts of short-term debt approximates the fair value because of the short maturity of those instruments. The fair value of the debentures was estimated based on actual market prices or market prices of similar issues. AGC has no financial instruments held or issued for trading purposes.

Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for AGC and its affiliates in accordance with the PUHCA. Through AESC, AGC is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to AGC were $.2 million for 2002, and $.3 million for 2001, and 2000.

At December 31, 2002 and 2001, AGC had net accounts receivables due from affiliates of $11.8 million and $2.2 million, respectively.

See Note 6 for information regarding AGC’s participation through August 2002 in an Allegheny internal money pool, a facility that accommodates short-term borrowing needs.

While no adjustments relating to financial statements for periods prior to 2002 were identified for AGC during Allegheny’s comprehensive financial review, as discussed in Note 1, certain adjustments within 2002 were identified for AGC, and the quarterly amounts included in the table above reflect these adjustments. The following table summarizes the effect of the adjustments on amounts previously reported for AGC’s first and second quarter 2002 affiliated operating revenues, operating income, and net income:

SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets, was adopted by AGC on January 1, 2003. SFAS No. 143 requires that the fair value of retirement costs for which AGC has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss. AGC has completed a detailed assessment of the specific applicability of SFAS No. 143 and determined that the adoption of SFAS No. 143 will not have a material effect on AGC’s results of operations, cash flows, and financial position.

AGC has entered into commitments for its construction programs for which expenditures are estimated to be $9.7 million (unaudited) for 2003 and $6.1 million (unaudited) for 2004.

The management of Allegheny Generating Company (the Company), a wholly-owned subsidiary of Allegheny Energy, Inc. (Allegheny) is responsible for the information and representations in the Company’s financial statements. The Company prepares the financial statements in accordance with generally accepted accounting principles in the United States based upon available facts and circumstances and management’s best estimates and judgments of known conditions.

The Company is responsible for maintaining an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Company’s assets are protected. As discussed in Item 14, of Allegheny’s Annual Report on Form 10-K, Allegheny management has concluded that Allegheny’s internal controls and disclosure controls are not adequate, and need substantial work to restore them to adequacy. Management and the Audit Committee of the Board of Directors of Allegheny are committed to devoting the additional resources necessary to ensure that the Company’s reporting is accurate and complete until internal controls are improved and are adequate.

Allegheny’s staff of internal auditors conducts periodic reviews designed to assist management in maintaining the effectiveness of internal control procedures. PricewaterhouseCoopers LLP, an independent accounting firm, audits the financial statements and expresses its opinion on them. The independent accountants perform their audit in accordance with generally accepted auditing standards.

Management meets periodically with internal auditors and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff of Allegheny and PricewaterhouseCoopers LLP have free access to all of the Company’s records and to the Audit Committee of Allegheny.

In our opinion, the accompanying balance sheets and the related statements of operations and cash flows, present fairly, in all material respects, the financial position of Allegheny Generating Company (the Company) at December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company is not in compliance with reporting obligations contained in certain of its debt covenants and, as a result, certain debt has been classified as current which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Our audits of the consolidated financial statements of Allegheny Energy, Inc., referred to in our report dated September 23, 2003 (which report and consolidated financial statements are included in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 8 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

Our audits of the consolidated financial statements of Allegheny Energy Supply Company, LLC, referred to in our report dated September 23, 2003 (which report and consolidated financial statements are included in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 8 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

Our audits of the consolidated financial statements of Monongahela Power Company referred to in our report dated September 23, 2003 (which report and consolidated financial statements are included in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 8 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

Our audits of the consolidated financial statements of Potomac Edison Company referred to in our report dated September 23, 2003 (which report and consolidated financial statements are included in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 8 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

Our audits of the consolidated financial statements of West Penn Power Company referred to in our report dated September 23, 2003 (which report and consolidated financial statements are included in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 8 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Directors of the Registrants. As of September 15, 2003, the names, ages and business experience during the past five years of the directors of the Registrants (AE, Monongahela (MP), West Penn (WP), AGC and AE Supply), and terms of office are set forth below:

This note applies only to AE. All Directors of Monongahela, Potomac Edison, West Penn, AGC, and AE Supply stand for election annually for one-year terms.

As of September 15, 2003, the names of the executive officers of each Registrant, their ages, the positions they hold or held during 2002 and 2003, and their business experience during the past five years appears below:

Section 16(a) of the Securities Exchange Act of 1934 requires the executive officers and directors to file initial reports of ownership and reports of changes in ownership with the SEC and the New York Stock Exchange. All required reports were filed on a timely basis during 2002. Through September 30, 2003, all required reports were filed on a timely basis, other than a report on Form 4 by Bruce E. Walenczyk. Following his retirement, Mr. Walenczyk sold 1,400 shares of AE’s common stock on June 24, 2003 and 857.864 shares of AE’s common stock on July 18, 2003, which sales were reported on July 22, 2003.

We are required to report the compensation paid by Allegheny in 2002, 2001, and 2000 to the Chief Executive Officer and four other highest paid executive officers of Allegheny during such period. Allegheny instituted substantial changes to its senior management in 2003. As discussed in ITEM 1. BUSINESS—Recent Events—Allegheny’s Response, Messrs. Alan J. Noia, Michael P. Morrell, Bruce E. Walenczyk, and Richard J. Gagliardi, among other executive officers, retired from Allegheny during 2003. As of the date of this report, it is anticipated that the individuals for whom we will be required to report compensation paid in 2003 will include Alan J. Noia, Jay S. Pifer, Paul J. Evanson, Jeffrey D. Serkes, Joseph H. Richardson and David B. Hertzog. The compensation arrangements between Allegheny and Messrs. Evanson, Serkes, Richardson, and Hertzog are described below. During 2002, and for 2001 and 2000, the annual compensation paid by AE, Monongahela, Potomac Edison, West Penn, AE Supply, and AGC directly or indirectly to the Chief Executive Officer and each of the four highest paid executive officers of Allegheny whose cash compensation exceeded $100,000 for services in all capacities to Allegheny was as follows:

For 2002, the figures shown include amounts representing (1) the aggregate of life insurance premiums and dollar value of the benefit to the executive officer of the remainder of the premium paid on the Basic Group Life Insurance plan and the Executive Life Insurance Plan, and (2) ESOSP contributions, respectively, as follows: Mr. Noia, $4,440 and $4,742; Mr. Morrell, $3,392 and $5,100; Mr. Pifer, $3,250 and $5,100; Mr. Gagliardi, $2,628 and $4,648; and Mr. Walenczyk, $2,682 and $5,100.

Alan J. Noia, Jay S. Pifer, and Richard J. Gagliardi and other executive officers are covered under the Executive Life Insurance Plan (ELIP). In 1992, Allegheny purchased life insurance policies for participants to meet the obligations under the ELIP. The applicable premium for each covered participant is paid by Allegheny. The death benefit under the ELIP is equal to the insured’s base salary, excluding bonuses, while the participant is actively employed by Allegheny. Upon retirement, the death benefit increases to two times base salary for 12 months, then decreases 20 percent per year until the earlier of the fifth anniversary of retirement or the insured’s attainment of age 70, at which time the death benefit becomes equal to the insured’s final base salary at the time of retirement.

Allegheny provides life insurance to all employees, subject to meeting eligibility requirements, including the named executive officers under a basic group life insurance plan that pays a death benefit equal to the insured’s base salary, excluding bonuses, during employment and $25,000 during retirement.

The ESOSP was established as a non-contributory stock ownership plan for all eligible employees, effective January 1, 1976, and amended in 1984 to include a savings program. All of Allegheny’s employees, subject to meeting eligibility requirements, may elect to participate in the ESOSP. Under the ESOSP, each eligible employee can elect to have from two to twelve percent of his or her compensation contributed to the ESOSP on a pre-tax basis, and an additional one to six percent on a post-tax basis. Participants direct the investment of contributions to specified mutual funds. Fifty percent of pre-tax contributions, up to six percent of an employee’s compensation, is matched by Allegheny with common stock of AE. For 2002, the maximum amount of compensation to be factored into these calculations was $170,000. Pre-tax contributions may be withdrawn only if financial hardship requirements are met or employment is terminated. At present, employees may not purchase AE common stock under the ESOSP.

Allegheny maintains a retirement plan covering substantially all employees (Retirement Plan). The Retirement Plan is a noncontributory, trusteed pension plan designed to meet the requirements of Section 401(a) of the Internal Revenue Code of 1986, as amended (the Code). Each covered employee is eligible for retirement at normal retirement date (age 65), with early retirement permitted.

Allegheny also maintains a SERP for executive officers and other senior managers. All executive officers, except Messrs. Evanson, Serkes, Hertzog, and Richardson, are participants in the SERP. An officer will be eligible to receive benefits under the SERP only if he or she has been credited with at least 10 years of service with Allegheny and has reached his or her 55th birthday. Under the SERP, an eligible participant will receive a supplemental retirement benefit equal to his or her Average Compensation multiplied by the sum of: (1) two percent for each year of service up to 25; (2) one percent for each year of service from 25 to 30; and (3) one-half percent for each year of service from 30 to 40, less benefits paid under the Retirement Plan and less two percent for each year that a participant retires prior to his or her 60th birthday. The Plan also provides for use of Average Compensation in excess of the Code maximums.

A participant’s benefits are capped at 60 percent of Average Compensation (including for this purpose retirement benefits paid under the Retirement Plan and benefits payable from other employers), less two percent for each year the participant retires prior to reaching age 60.

The SERP defines Average Compensation as 12 times the average monthly earnings, including overtime and other salary payments actually earned, whether or not payment is deferred, for the 36 consecutive calendar months constituting the period of highest average monthly salary, together with 100 percent of the actual award paid under the Annual Incentive Plan.

A participant may elect to receive the plan benefit in such form as those available under the Retirement Plan.

To provide funds to pay these benefits, beginning January 1, 1993, Allegheny purchased insurance on the lives of some of the participants in the SERP, including Messrs. Noia, Morrell, Pifer, and Gagliardi. If the assumptions made as to mortality experience, policy dividends, and other factors are realized, Allegheny will recover all premium payments, plus a factor for the use of Allegheny’s money at the earlier of (1) the death of the insured, or (2) upon the later of ten years from the policy inception or the insured’s retirement. Upon maturity of the insurance contracts, the covered participants are given the choice of receiving (1) an annuity payment, or (2) the lump sum cash equivalent of the value of their monthly benefit payment under the SERP. The portion of the premiums required to be deemed compensation by the SEC for this insurance is included in the All Other Compensation column of the Executive Compensation chart.

The following table shows estimated maximum annual benefits payable to participants in the SERP following retirement (assuming payments on a normal life annuity basis and not including any survivor benefit) to an employee in specified remuneration and years of credited service classifications. These amounts are based on an estimated Average Compensation, retirement at age 65, and without consideration of any effect of various options which may be elected prior to retirement. The benefits under the SERP are not subject to any deduction for Social Security or any other offset amounts.

During August of 2002, and subsequently in March and April of 2003, AE offered a voluntary ERO to the named and other executive officers who are age 50 or older as of October 1, 2003. The ERO provides AE with the right to designate a retirement date for each electing employee. The retirement date may not be prior to June 1, 2003, or after January 1, 2005. Employees who have elected to participate in the ERO may rescind their elections at any time prior to the designated retirement effective date.

1. The 10-year service requirement to receive a benefit under the SERP has been waived.

2. Based on their age at retirement, officers receive from a minimum of three additional years of service up to a maximum of five additional years under the SERP.

As of the date of this report, the following executive officers have accepted the ERO and retired: Richard J. Gagliardi, Thomas K. Henderson, Michael P. Morrell, Karl Pfirrmann, and Bruce E. Walenczyk.

In addition, two other current executive officers elected the ERO: David C. Benson and Regis F. Binder. Dates have not been designated for their retirements. As part of the provisions of the ERO, although the Company is bound to allow an executive to retire pursuant to the ERO up until the date designated for his or her retirement, the executive may elect to not retire.

The Board of Directors and shareholders of AE approved the 1998 Long-Term Incentive Plan (LTIP) to assist Allegheny in attracting and retaining key employees and directors and motivating performance. The LTIP

is administered by the Management Compensation and Development Committee (the Committee), which may delegate to an executive officer the power to determine the employees (other than himself or herself) eligible to receive awards. The Committee may from time to time designate key employees and directors to participate in the LTIP for a particular year. The number of shares of AE common stock initially authorized for issuance under the LTIP is 10 million, subject to adjustments for recapitalizations or other changes to AE’s common shares. No participant in the LTIP may be granted more than 600,000 shares (or rights or options in respect of more than 600,000 shares) in any calendar year. For purposes of this limit, shares subject to an award that is to be earned over a period of more than one calendar year will be allocated to the first calendar year in which such shares may be earned.

The LTIP permits awards of options to purchase AE common stock on terms and conditions as determined by the Committee. Stock options are issued at strike prices equal to the fair market value (as defined in the LTIP) of AE common stock as of the date of the option grant. The terms of option awards are set forth in option award agreements. The Committee may award non-qualified stock options or incentive stock options (each as defined in the LTIP). No participant in the LTIP may receive incentive stock option awards under the LTIP or any other Allegheny compensation plan that would result in incentive stock options to purchase shares of AE common stock with an aggregate fair market value of more than $100,000 first becoming exercisable by such participant in any one calendar year.

Options awarded under the LTIP will terminate upon the first to occur of: (i) the option’s expiration under the terms of the related option award agreement; (ii) termination of the award following termination of the participant’s employment under the rules described in the next paragraph; and (iii) 10 years after the date of the option grant. The Committee may accelerate the exercise period of awarded options, and may extend the exercise period of options granted to employees who have been terminated.

In the event of the termination of employment of a participant in the LTIP, options not exercisable at the time of the termination will expire as of the date of the termination and exercisable options will expire 90 days from the date of termination. In the event of termination of a participant’s employment due to retirement or disability, options not exercisable will expire as of the date of termination and exercisable options will expire one year after the date of termination. In the event of the death of a participant in the LTIP, all options not exercisable at the time of death will expire, and exercisable options will remain exercisable by the participant’s beneficiary until the first to occur of one year from the time of death or, if applicable, one year from the date of the termination of such participant’s employment due to retirement or disability.

The Committee may establish dividend equivalent accounts with respect to awarded options. A participant’s dividend equivalent account will be credited with notional amounts equal to dividends that would be payable on the shares for which the participant’s options are exercisable, assuming that such shares were issued to the participant. The participant or other holder of the option will be entitled to receive cash from the dividend equivalent account at such time or times and subject to such terms and conditions as the Committee determines and provides in the applicable option award agreement. If an option terminates or expires prior to exercise, the dividend equivalent account related to the option will be concurrently eliminated and no payment in respect of the account will be made.

The Committee may permit the exercise of options or the payment of applicable withholding taxes through tender of previously acquired shares of AE common stock or through reduction in the number of shares issuable upon option exercise. The Committee may grant reload options to participants in the event that participants pay option exercise prices or withholding taxes by such methods.

In the event of a change of control of Allegheny (as defined in the LTIP), unless provided to the contrary in the applicable option award agreement, all options outstanding on the date of the change in control will become immediately and fully exercisable.

The Committee may grant shares of common stock on terms, conditions and restrictions as the Committee may determine. Restrictions, terms, and conditions may be based on performance standards, period of service, share ownership, or other criteria. Performance-based awards intended for federal income tax deductibility will be subject to performance targets with respect to operating income, return on investment, return on shareholders’ equity, stock price appreciation, earnings before interest, taxes and depreciation/amortization, earnings per share, and/or growth in earnings per share. The terms of restricted stock awards will be set forth in award agreements.

The participant will be an owner of restricted shares awarded to him or her under the LTIP. The shares may not be transferred, pledged, or assigned (other than by will or the laws of descent and distribution or to an inter vivos trust with respect to which the participant is treated as the owner under the internal revenue code) prior to the lapse of the applicable restrictions. A participant’s restricted shares will be forfeited to Allegheny in the event that the participant ceases to be employed by Allegheny prior to the expiration of the applicable forfeiture period. The Committee may waive an award’s forfeiture provisions under appropriate circumstances.

In the event of a change of control of Allegheny (as defined in the LTIP), unless provided to the contrary in the applicable restricted stock award agreement, the restrictions applicable to all restricted stock awards will terminate fully on the date of the change of control.

The Committee may grant performance awards, which will consist of a right to receive a payment that is either measured by the fair market value of a specified number of shares of AE common stock, increases in the fair market value of AE common stock during an award period and/or consists of a fixed cash amount. Performance awards may be made in conjunction with or in addition to restricted stock awards. Award periods will be two or more years or other annual periods as determined by the Committee. The Committee may permit newly eligible participants to receive performance awards after an award period has commenced.

The Committee establishes performance targets in connection with performance awards. In the case of awards intended to be deductible for federal income tax purposes, performance targets will relate to operating income, return on investment, return on shareholders’ equity, stock price appreciation, earnings before interest, taxes and depreciation/amortization, earnings per share, and/or growth in earnings per share. The Committee prescribes formulas to determine the percentage of the awards to be earned based on the degree of attainment of award targets. Allegheny may make payments in respect of performance awards in the form of cash or shares of AE common stock, or a combination of both.

In the event of a participant’s retirement during an award period, the participant will not receive a performance award unless otherwise determined by the Committee, in which case the participant will be entitled to a prorated portion of the award. In the event of the death or disability of a participant during an award period, the participant or his or her representative will be entitled to a prorated portion of the performance award. A participant will not be entitled to a performance awards if his or her employment terminates prior to the conclusion of an award period, provided that the Committee may determine in its discretion to pay performance awards, including full (i.e., non-prorated) awards, to any participant whose employment is terminated. In the event of a change of control of Allegheny, all performance awards for all award periods will immediately become payable to all participants and will be paid within 30 days after the change in control.

The Committee may, unless the relevant award agreement otherwise specifies, cancel, rescind, or suspend an award in the event that the LTIP participant engages in competitive activity, discloses confidential information, solicits employees, customers, partners or suppliers of Allegheny, or undertakes any other action determined by the Committee to be detrimental to Allegheny.

The LTIP contains provisions intended to ensure that certain restricted share awards and performance awards to “covered employees” under Section 162(m) of the Internal Revenue Code are exempt from the $1 million deduction limit contained in that Section of the Code. Those exemptive provisions, by their terms and under the applicable IRS regulations, expired as of May 14, 2003. Any pending, but unvested, awards issued under such provisions are unaffected by the provisions’ expiration, but any future restricted stock or performance awards to covered employees will not be eligible for the exemption from the Section 162(m) limit unless the provisions are reapproved by the shareholders. AE may seek stockholder reauthorization of the LTIP with respect to such provisions, but has no present intention to do so. Allegheny may choose alternative methods to compensate covered employees who would have received compensation under the terminated provisions of the LTIP had such provisions not terminated.

The named executives were awarded the above number of performance shares for Cycle IX under the LTIP. Such number of shares is only a target. Each executive’s 2002-2004 target long-term incentive opportunity was converted into performance shares equal to an equivalent number of shares of AE common stock, based on the price of such stock on December 31, 2001. The plan provides that at the end of this three-year performance period, the performance shares attributed to the calculated award will be valued based on the price of AE common stock on December 31, 2004, and will reflect dividends that would have been paid on such stock during the performance period as if they were reinvested on the date paid. If an executive retires, dies, or otherwise leaves the employment of Allegheny prior to the end of the three-year period, the executive may nevertheless receive an award based on the number of months worked during the period. The final value of an executive’s account, if any, will be paid to the executive in early 2005.

The actual payout of an executive’s award may range from zero to 200 percent of the target amount before dividend reinvestment. The payout is based upon stockholder performance versus the peer group. The

stockholder rating is then compared to a pre-established percentile-ranking chart to determine the payout percentage of target. A ranking below 30 percent results in a zero-percent payout. The minimum payout begins at the 30-percent ranking, which results in a payout of 60 percent of target, ranging up to a payout of 200 percent of target if there is a 90-percent or higher ranking.

Allegheny has established an Annual Incentive Plan (the Short-Term Incentive Plan) for the purpose of attracting and retaining quality managerial talent and to reward attainment of performance goals. Under the Short-Term Incentive Plan, the Management Compensation and Development Committee of AE’s Board of Directors determines award levels, subject to full Board approval, based upon the recommendation of the Chief Executive Officer. Awards may be granted to executives whose responsibilities can affect the performance of their business units and through unit performance, the performance of AE. The Board may not authorize awards if, in the Board’s opinion, AE’s performance is less than satisfactory from the perspective of the stockholders. Awards will be based on attainment of a variety of business unit and individual goals. The plan assigns numerical performance ratings with respect to the level of attainment of program goals. Award determinations will be based the extent to which performance falls short, meets, or exceeds plan targets. Awards will be payable in current cash, deferred cash or stock. AE has registered 1,000,000 shares of its common stock for distribution under the Short-Term Incentive Plan, and 982,197 of such shares remain available for issuance under the plan.

AE has entered into change in control contracts with the named executive officers as set forth in the Executive Compensation Table and with certain other Allegheny executive officers (Agreements). Each Agreement sets forth (1) the severance benefits that will be provided to the employee in the event the employee is terminated subsequent to a Change in Control of AE (as defined in the Agreements) and (2) the employee’s obligation to continue his or her employment after the occurrence of certain circumstances that could lead to a Change in Control. The Agreements provide generally that if there is a Change in Control, unless employment is terminated by AE for Cause, Disability, or Retirement or by the employee for other than Good Reason (each as defined in the Agreements), severance benefits payable to the employee will consist of a cash payment equal to 2.99 times the employee’s base annual salary and target short-term incentive together with AE maintaining existing benefits for the employee and the employee’s dependents for a period of three years. Each Agreement expires on December 31, 2001, but is automatically extended for one-year periods thereafter unless either AE or the employee gives notice otherwise. Notwithstanding the delivery of such notice, the Agreements will continue in effect for 36 months after a Change in Control.

AE and AESC entered into an employment agreement with Paul J. Evanson on June 9, 2003. Mr. Evanson will serve as Chairman of the Board of Directors of AE and President and Chief Executive Officer of AE for a

five-year term that began on June 16, 2003. Mr. Evanson’s annual base salary under the agreement will not be less than $900,000 for the term of the agreement and will be increased annually to reflect increases in the consumer price index. Mr. Evanson received an initial make-whole payment of $6,300,000 under the agreement to induce him to accept employment and compensate him for forfeitures of financial and other benefits from his former employer.

Mr. Evanson will be eligible to receive annual incentive compensation under the AE Annual Incentive Plan, with a target bonus opportunity of 100 percent of base salary and a maximum bonus opportunity of 200 percent of base salary. On January 2, 2004, Mr. Evanson will receive a grant of options to purchase 1,500,000 shares of AE common stock under the LTIP at a per-share exercise price equal to the closing price of AE common stock on the New York Stock Exchange on such date. One-fifth of the options will vest on June 9 of each of 2004 through 2008, provided that Mr. Evanson remains employed by AE on each applicable vesting date. Upon the occurrence of a change in control of AE (as defined in the employment agreement), all options will immediately vest.

On January 2, 2004, AE will grant to Mr. Evanson between 1,600,000 and 2,300,000 stock units. Additional stock units will be granted at such time if the closing price of AE common stock on January 2, 2004 (the 2004 Closing Price) exceeds the blended price by at least $0.50. The blended price is equal to the sum of (x) .25 multiplied by the closing price of AE common stock on June 9, 2003, and (y) .75 multiplied by the closing price of AE common stock on the fifth business day after the date on which AE publicly announces its 2002 financial results. If the 2004 Closing Price exceeds the blended price by at least $0.50, additional stock units will be granted equal to $1.5 million divided by the 2004 Closing Price and, in addition, the same number of additional stock units will be granted for each additional $1.00 by which the 2004 Closing Price exceeds the blended price. One-fifth of the units will vest on each June 9 from 2004 through 2008, provided Mr. Evanson remains employed by AE on each applicable vesting date. Additional stock units will be credited to Mr. Evanson to account for the value of cash dividends paid on AE common stock. AE will pay to Mr. Evanson the full value of each vested stock unit on each applicable vesting date, in cash or stock at AE’s option, subject to his election to defer the payments. All of the stock units will vest on a change in control of AE, or if one or more persons acquire collectively ownership of at least 10 percent of AE voting stock and the right to veto a corporate action and any such person exercises veto power over a corporate action which has been recommended by Mr. Evanson.

Mr. Evanson will also accrue a lump sum cash payment, in lieu of benefits under the SERP, at the rate of $66,667 for each month of employment. The payment will be made on termination of employment for any reason.

In the event of termination due to death or disability, all of Mr. Evanson’s stock options and stock units will vest, and all vested stock options will remain exercisable for three years (but in no event after their normal expiration date). Mr. Evanson will also receive a prorated target bonus for the year of termination.

If Mr. Evanson is terminated without cause (as defined in the employment agreement) or if Mr. Evanson resigns for good reason (as defined in the employment agreement) or for any reason in the 30-day period commencing six months following a change in control, AE will pay to Mr. Evanson a cash severance payment equal to three times the sum of his base salary and target bonus amount, as well as his target bonus prorated for the year in which his termination occurs. For three years from the date of termination, Mr. Evanson will be provided with life, health, and disability coverage, or a cash amount sufficient to procure such coverage. All of Mr. Evanson’s stock options and stock units will vest. Vested stock options will be immediately exercisable and will remain exercisable for five years from the termination date (but in no event after their normal expiration date). Mr. Evanson will also receive, in lieu of payments under the SERP, a cash payment in a lump sum equal to $4,000,000.

If, prior to January 2, 2004, Mr. Evanson’s employment is terminated by AESC without cause, due to death or disability, by Mr. Evanson for good reason, or a change in control occurs, Mr. Evanson (or his heirs in the case of a termination due to death) will receive, in addition to the amounts and benefits described above, a grant of vested and exercisable options under the LTIP to purchase 1,500,000 shares of AE common stock. Vested

options will remain exercisable for five years from the termination date (but in no event after their normal expiration date) at an exercise price equal to the closing price of AE common stock on the date of termination or change in control. Mr. Evanson will also receive either a number of registered shares of AE common stock equal to the sum of (x) 1,600,000 plus (y) the number of additional stock units that Mr. Evanson would have been granted on January 2, 2004, based on the closing price of AE common stock on the actual date of termination or change in control, or at the discretion of Allegheny, cash equal to the result of multiplying such number of shares by the closing price of AE stock on the date of termination or change in control, as applicable.

In the event of termination of Mr. Evanson’s employment at any time after June 9, 2008, AESC will pay him a prorated target bonus and all stock options and other equity awards granted to Mr. Evanson shall be fully vested. Mr. Evanson will also be entitled to a prompt lump sum cash payment equal to his accrued pension benefit.

The agreement provides that, in the event that compensation payable to Mr. Evanson under the agreement is subject to an excise tax under Section 4999 of the Internal Revenue Code, AE will make an additional payment to Mr. Evanson equal to the amount of such excise tax, as well as the income tax and excise tax applicable to such payment.

The agreement subjects Mr. Evanson to certain confidentiality, non-competition, and non-solicitation covenants, and indemnifies him against costs and liabilities arising from legal proceedings brought against him in relation to his employment.

AE and AESC entered into an employment agreement with Jeffrey D. Serkes on July 3, 2003. Mr. Serkes will serve as the Chief Financial Officer of AE for a three-year term which began on July 7, 2003. Mr. Serkes’s annual base salary under the agreement will not be less than $500,000 for the term of the agreement. Mr. Serkes received an initial make-whole payment of $250,000 under the agreement in respect of financial and other benefits forfeited as a result of his accepting employment with AE.

Mr. Serkes will be eligible to receive annual incentive compensation under the AE Annual Incentive Plan, with a target bonus opportunity of 100 percent of base salary and a maximum bonus opportunity of 200 percent of base salary. On January 2, 2004, Mr. Serkes will receive a grant of options to purchase 550,000 shares of AE common stock under the AE 1998 LTIP at a per-share exercise price equal to the closing price of AE common stock on the New York Stock Exchange on such date. One-third of the options will vest on July 3 of each of 2004 through 2006, provided that Mr. Serkes remains employed by AE on each applicable vesting date. Upon the occurrence of a change in control of AE (as defined in the employment agreement), all options will immediately vest.

On January 2, 2004, AE will grant to Mr. Serkes 550,000 stock units. Additional stock units will be granted at such time if the closing price of AE common stock on January 2, 2004 (the 2004 Closing Price) exceeds the blended price by at least $0.50. The blended price is equal to the sum of (x) .25 multiplied by the closing price of AE common stock on July 3, 2003 and (y) .75 multiplied by the closing price of AE common stock on the fifth business day after the date on which AE publicly announces its 2002 financial results. If the 2004 Closing Price exceeds the blended price by at least $0.50, additional stock units will be granted equal to $550,000 divided by the 2004 Closing Price and, in addition, the same number of additional stock units will be granted for each additional $1 by which the 2004 Closing Price exceeds the blended price. One-third of the units will vest on each July 3 of 2004 through 2006, provided Mr. Serkes remains employed by AE on each applicable vesting date. Additional stock units will be credited to Mr. Serkes to account for the value of cash dividends paid on AE common stock. AE will pay to Mr. Serkes the full value of each vested stock unit on each applicable vesting date, in cash or stock at AE’s option, subject to his election to defer the payments. All of the stock units will vest on a change in control of AE.

In the event of termination due to death or disability, all of Mr. Serkes’s stock options and stock units will vest, and all vested stock options will remain exercisable for two years (but in no event after their normal expiration date). Mr. Serkes will also receive a prorated target bonus for the year of termination and the lump sum cash amount described below will become immediately payable.

In lieu of benefits under the SERP, Mr. Serkes will accrue a lump sum cash amount of $41,667 for each month of employment at AE, which is payable at age 55. However, if at any time after Mr. Serkes’ employment with AE terminates, Moody’s reduces its rating of AE below Ba2 or Standard and Poor’s Rating Services reduces its rating of AE below BB, the lump sum cash amount shall become immediately payable at the request of Mr. Serkes. Mr. Serkes may elect, in lieu of a lump sum, to receive payment of such amount in any form provided for under the SERP. If Mr. Serkes is terminated by AESC without cause (as defined in the employment agreement), resigns with good reason (as defined in the employment agreement), or his employment terminates after the expiration of the term of the agreement, he will be fully vested in his accrued lump sum cash amount or, if greater, $1,500,000.

If Mr. Serkes is terminated by AE without cause, or if Mr. Serkes resigns with good reason, AE will pay to Mr. Serkes a cash severance payment equal to his annual base salary and target bonus multiplied by the greater of (x) two and (y) the fraction determined by dividing the number of months remaining in the term of employment by twelve. For two years from the date of termination (or, if longer, for the remainder of the term of employment), Mr. Serkes will be provided with life, health, and disability coverage, or a cash amount sufficient to procure such coverage. All of Mr. Serkes’ stock options and stock units will vest to the extent they would have vested had Mr. Serkes continued his employment with AE for two years or, if longer, through the remainder of the term of employment. Vested stock options will be immediately exercisable and will remain exercisable for three years from the termination date (but in no event after their normal expiration date). Mr. Serkes will also receive a prorated target bonus for the year of termination and the lump sum cash amount described above will become immediately payable.

If, prior to January 2, 2004, Mr. Serkes’ employment is terminated by AE without cause, due to death or disability, by Mr. Serkes for good reason, or a change in control occurs, Mr. Serkes (or his heirs in the case of a termination due to death) will receive, in addition to the amounts and benefits described above, a grant of vested and exercisable options under the LTIP to purchase 550,000 shares of AE common stock, exercisable for a period of three years, at an exercise price equal to the closing price of AE common stock on the date of termination or change in control, and either a number of registered shares of AE common stock equal to the sum of (x) 550,000 plus (y) the number of additional stock units that Mr. Serkes would have been granted on January 2, 2004, based on the closing price of AE common stock on the actual date of termination or change in control or, at the discretion of Allegheny, cash equal to the result of multiplying such number of shares by the closing price of AE stock on the date of termination or change in control, as applicable.

If Mr. Serkes is terminated by AE without cause or resigns with good reason following a change in control or in anticipation of a change in control, or if Mr. Serkes resigns for any reason during the 30-day period commencing six months following a change in control, AE will pay to Mr. Serkes a cash severance payment equal to three times his annual base salary and target bonus, as well as his target bonus prorated for the year in which his termination occurs. For three years from the date of termination, Mr. Serkes will be provided with life, health and disability coverage, or a cash amount sufficient to procure such coverage. All of Mr. Serkes’s stock options and stock units will vest. Vested stock options will be immediately exercisable and will remain exercisable for three years from the termination date (but in no event after their normal expiration date). In addition, Mr. Serkes will be entitled to a prompt lump sum cash payment equal to the greater of $1,500,000 and his accrued pension benefit, in lieu of payment of such amount at age 55.

In the event of termination of Mr. Serkes’s employment at any time after July 3, 2006, AESC will pay him a prorated target bonus.

The agreement provides that, in the event that compensation payable to Mr. Serkes under the agreement is subject to an excise tax under Section 4999 of the Internal Revenue Code, AE will make an additional payment to Mr. Serkes equal to the amount of such excise tax, as well as the income tax and excise tax applicable to such payment.

The agreement subjects Mr. Serkes to certain confidentiality, non-competition, and non-solicitation covenants, and indemnifies him against costs and liabilities arising from legal proceedings brought against him in relation to his employment.

AE and AESC entered into an employment agreement on July 18, 2003 with David B. Hertzog to serve as Vice President and General Counsel of AE and AESC. The term of the agreement commenced July 28, 2003 and will continue for five years unless earlier terminated in accordance with the terms of the agreement. Mr. Hertzog will receive an annual base salary of at least $450,000 for the term of the agreement. He will also be eligible to receive an annual incentive bonus with a target bonus opportunity of 77.78 percent of base salary and a maximum bonus opportunity of 155.56 percent of base salary. In order to make Mr. Hertzog whole for certain financial and other benefits foregone as a result of accepting employment with AE, AE paid to Mr. Hertzog a lump sum cash payment of $800,000 as of the commencement of the term of the agreement.

On January 2, 2004, AE will grant Mr. Hertzog under the LTIP options for the purchase of 300,000 shares of AE common stock. If AE cannot obtain authorization under PUHCA for the grant, AE will grant to Mr. Hertzog stock appreciation rights on 300,000 shares of AE common stock, payable in cash and on terms substantially economically equivalent to the stock options, in lieu of the options. The exercise price for the options will be the closing price of AE common stock on January 2, 2004. One fifth of the options will vest on July 18 of each of 2004 through 2008, provided that Mr. Hertzog continues to be employed by AE on each applicable vesting date. Upon the occurrence of a change in control (as defined in the employment agreement) of AE, all of the options will immediately vest.

On January 2, 2004, AE will grant 300,000 stock units to Mr. Hertzog. AE will also grant to Mr. Hertzog additional stock units at such time if the closing price of AE common stock on the New York Stock Exchange on January 2, 2004 (the 2004 Closing Price) exceeds the blended price by at least $0.50. The blended price is equal to the sum of (x) .25 multiplied by the closing price of AE common stock on July 18, 2003 and (y) .75 multiplied by the closing price of AE common stock on the fifth business day after the date on which AE publicly announces its 2002 financial results. If the 2004 Closing Price exceeds the blended price by at least $0.50, additional stock units will be granted equal to $300,000 divided by the 2004 Closing Price, and, in addition, the same number of additional stock units will be granted for each additional whole dollar by which the 2004 Closing Price exceeds the blended price. Additional units will also be credited in respect of any dividends paid on AE common stock. One fifth of the units will vest on July 18 of each of 2004 through 2008, provided that Mr. Hertzog continues to be employed by AE on each applicable vesting date. Upon the occurrence of a change in control of AE, all of the units will immediately vest. The value of a unit will be equal to the price of AE common stock on the date such unit vests. The units will be payable promptly upon vesting in cash or stock at the discretion of AE, subject to the election of Mr. Hertzog to defer the payments.

Mr. Hertzog will also accrue a lump sum cash payment, in lieu of benefits under the SERP, at the rate of $20,833.33 for each month of employment. The payment will be made on termination of employment for any reason. Mr. Hertzog may elect, in lieu of a lump sum, to receive payment of such amount in any form provided under the SERP.

In the event of termination due to death or disability, all of Mr. Hertzog’s stock options and stock units will vest, and all vested stock options will remain exercisable for two years (but in no event after their normal expiration dates). In addition, under such circumstances, Mr. Hertzog will be entitled to a prorated target bonus.

If Mr. Hertzog is terminated without cause, or Mr. Hertzog terminates his employment for good reason (as defined in the employment agreement), he will be entitled to receive a lump sum cash payment equal to the product of the severance factor multiplied by the sum of (x) the annual base salary for the year in which the termination occurs plus (y) the target bonus for such year. The severance factor will be equal to the greater of (x) two and (y) a fraction, the numerator of which is the number of whole and partial months remaining in the term of the agreement on the date of the termination and the denominator of which is twelve, provided that the severance factor will not exceed three. Mr. Hertzog will be provided with life, health and disability coverage, or a cash amount sufficient to procure such coverage, for a period equal to the greater of two years or the remainder of the term of employment, but in no event for longer than three years. Mr. Hertzog would also be entitled to receive a lump sum payment equal to the greater of (x) $1,250,000 and (y) his accrued lump sum cash payment. All stock options and stock units would vest to the extent that all such awards would vest had Mr. Hertzog continued his employment for two years from the date of termination (or, if longer, for the remainder of the term of employment), and all vested stock options would remain exercisable for three years from the date of termination (but in no event after their normal expiration date). Mr. Hertzog would also be entitled to a prorated payment in respect of the target bonus for the year of termination.

If, prior to January 2, 2004, Mr. Hertzog’s employment is terminated by AE without cause (as defined in the employment agreement), due to death or disability, by Mr. Hertzog with good reason, or a change in control occurs, Mr. Hertzog will receive, in addition to the amounts and benefits described above, (x) a grant of vested and exercisable stock options for the purchase of 300,000 AE common shares, exercisable for a period of three years, at a per share price equal to the closing price on the date of termination or change in control and (y) a number of registered shares of AE common stock (or the cash equivalent) equal to the sum of (i) 300,000 plus (ii) the number of additional units that would have been granted except that the date of termination or change in control will be substituted for January 2, 2004, for purposes of the additional units calculation.

If Mr. Hertzog’s employment is terminated by AE without cause or by Mr. Hertzog for good reason either following a change in control of AE, or in anticipation of a change in control, or if Mr. Hertzog resigns for any reason during the 30-day period commencing six months following a change in control, he will be entitled to receive a lump sum cash payment equal to three times the sum of (x) the base salary then in effect and (y) his target bonus for the year in which the termination occurs. For three years from the date of termination, Mr. Hertzog would be provided with life, health and disability coverage, or a cash amount sufficient to procure such coverage. Mr. Hertzog would also be entitled to a lump sum payment equal to the greater of (x) $1,250,000 and (y) the accrued lump sum cash payment. All stock options and stock units would vest, and all vested stock options would remain exercisable for three years from the date of termination (but in no event after their normal expiration dates). Mr. Hertzog would also be entitled to a prorated payment in respect of the target bonus for the year of termination.

In the event of a termination of Mr. Hertzog’s employment at any time after July 28, 2008, AESC will pay him a prorated target bonus, and a lump sum payment equal to the greater of (x) $1,250,000 and (y) his accrued pension benefit. In addition, each stock option and other equity or equity-related award will be vested to the extent of the greater of (x) a prorated portion of such award based upon the portion of the award vesting period during which Mr. Hertzog was employed by AESC or (y) the extent specified in the award, and all options shall continue to be exercisable for the period specified in the applicable option agreement or, if longer, for one year (but in no event after their normal expiration dates).

The employment agreement provides that in the event that compensation payable to Mr. Hertzog under the agreement is subject to an excise tax under Section 4999 of the Internal Revenue Code, AE will make an additional payment equal to the amount of the excise tax as well as the income tax and excise tax applicable to such payment.

The employment agreement subjects Mr. Hertzog to certain confidentiality, non-competition and non-solicitation covenants, and indemnifies him against costs and liabilities arising from legal proceedings brought against him in relation to his employment.

AE and AESC entered into an employment agreement on August 6, 2003 with Joseph H. Richardson to serve as President of Allegheny Power and President of each of Monongahela, Potomac Edison and West Penn. The term of the agreement commenced August 25, 2003 and will continue for three years and thereafter for successive one-year terms, unless terminated by a party at least 90 days prior to the end of the term. Mr. Richardson will receive an annual base salary of at least $400,000 for the term of the agreement. He will also be eligible to receive an annual incentive bonus with a target bonus opportunity of 50 percent of base salary and a maximum bonus opportunity of 100 percent of base salary. For 2003 the target and maximum bonus amounts will be $83,833 and $166,666, respectively.

On January 2, 2004, AE will grant Mr. Richardson under the LTIP options for the purchase of 200,000 shares of AE common stock. If AE cannot obtain authorization under PUHCA for the grant, AE will grant to Mr. Richardson stock appreciation rights on 200,000 shares of AE common stock, payable in cash and on terms substantially economically equivalent to the stock options, in lieu of the options. The exercise price for the options will be the closing price of AE common stock on January 2, 2004. One fifth of the options will vest on August 25 of each of 2004 through 2008, provided that Mr. Richardson continues to be employed by AE on each applicable vesting date. Upon the occurrence of a change in control (as defined in the employment agreement) of AE, all of the options will immediately vest.

On January 2, 2004, AE will grant 50,000 stock units to Mr. Richardson. AE will also grant to Mr. Richardson additional stock units at such time if the closing price of AE common stock on the New York Stock Exchange on January 2, 2004 (the 2004 Closing Price) exceeds the blended price by at least $0.50. The blended price is equal to the sum of (x) .25 multiplied by the closing price of AE common stock on August 25, 2003, and (y) .75 multiplied by the closing price of AE common stock on the fifth business day after the date on which AE publicly announces its 2002 financial results. If the 2004 Closing Price exceeds the blended price by at least $0.50, additional stock units will be granted equal to $50,000 divided by the 2004 Closing Price and, in addition, the same number of additional stock units will be granted for each additional whole dollar by which the 2004 Closing Price exceeds the blended price. Additional units will also be credited in respect of any dividends paid on AE common stock. One fifth of the units will vest on August 25 of each of 2004 through 2008, provided that Mr. Richardson continues to be employed by AE on each applicable vesting date. Upon the occurrence of a change in control of AE, all of the units will immediately vest. The value of a unit will be equal to the price of AE common stock on the date such units vests. The units will be payable promptly upon vesting in cash or stock at the discretion of AE, subject to the election of Mr. Richardson to defer the payments.

Mr. Richardson will be eligible to participate in the LTIP and Allegheny’s other employee benefit plans, other than the SERP. Upon Mr. Richardson’s attainment of age 65, he shall be entitled to a lump sum cash payment equal to $5,000 for each month of employment with Allegheny (the “pension benefit”). Mr. Richardson may choose to receive the pension benefit in any form provided for under the SERP in lieu of a lump sum. In the event of a termination of employment for cause or a termination by Mr. Richardson, he will receive the pension benefit accrued up to the date of termination.

In the event of termination due to death or disability, all of Mr. Richardson’s stock options and stock units will vest, and all vested stock options will remain exercisable for two years (but in no event after their normal expiration date). In addition, under such circumstances, Mr. Richardson or his beneficiaries will be entitled to a pro-rated target bonus. Mr. Richardson would also be entitled to a lump sum payment equal to his pension benefit accrued to the date of termination.

If Mr. Richardson is terminated without cause, he will be entitled to receive, in addition to all accrued compensation and benefits, a lump sum cash payment equal to two times the sum of (x) the base salary then in effect and (y) his target bonus for the year in which the termination occurs. Mr. Richardson would also be entitled to a lump sum payment equal to the greater of (x) $300,000 and (y) the accrued pension benefit. All

stock options and stock units would vest to the extent that all such awards would vest had Mr. Richardson continued his employment for two years from the date of termination, and all vested stock options would remain exercisable for three years from the date of termination (but in no event after their normal expiration dates). Mr. Richardson would also be entitled to a prorated payment in respect of the target bonus for the year of termination.

If, prior to January 2, 2004, Mr. Richardson’s employment is terminated by AE without cause or, due to death or disability or a change in control occurs, Mr. Richardson will receive, in addition to the amounts, and benefits described above, (x) a grant of stock options for the purchase of 200,000 AE common shares, exercisable for a period of three years, at a per share price equal to the closing price on the date of termination or change in control and (y) a number of registered shares of AE common stock (or the cash equivalent) equal to the sum of (i) 50,000 plus (ii) the number of additional units that would have been granted except that the date of termination or change in control will be substituted for January 2, 2004 for purposes of the additional units calculation.

If Mr. Richardson’s employment is terminated by AE without cause or by Mr. Richardson for good reason (as defined in the employment agreement) either following a change in control of AE, or in anticipation of a change in control, he will be entitled to receive a lump sum cash payment equal to three times the sum of (x) the base salary then in effect and (y) the target bonus for the year in which the termination occurs. For three years from the date of termination, Mr. Richardson would be provided with life, health and disability coverage, or a cash amount sufficient to procure such coverage. Mr. Richardson would also be entitled to a lump sum payment equal to the greater of (x) $300,000 and (y) his accrued pension benefit. All stock options and stock units would vest, and all vested stock options would remain exercisable for three years from the date of termination (but in no event after their normal expiration dates). Mr. Richardson would also be entitled to a prorated payment in respect of the target bonus for the year of termination.

In the event of termination of Mr. Richardson’s employment at any time after August 25, 2006, AESC will pay him a prorated target bonus.

The employment agreement provides that in the event that compensation payable to Mr. Richardson under the agreement is subject to an excise tax under Section 4999 of the Internal Revenue Code, AE will make an additional payment equal to the amount of the excise tax, as well as the income tax and excise tax applicable to such payment.

The employment agreement subjects Mr. Richardson to certain confidentiality, non-competition, and non-solicitation covenants, and indemnifies him against costs and liabilities arising from legal proceedings brought against him in relation to his employment.

AE has entered into Employment Contracts with the named executive officers as set forth in the Executive Compensation Table and certain other executive officers. Each Contract provides for a two-year initial term and has a one-year renewal provision. The Contracts provide for specified levels of severance protection based on the reason for termination. The Contracts provide that base salary will not be reduced and the officers will remain eligible for participation in Allegheny’s executive compensation and benefit plans during the duration of the Contract. The Contracts provide that in the event that the employee’s employment is terminated without Cause (as defined under the contracts) or that the employee terminates employment with Good Reason (as defined under the contracts), the employee will be eligible during a specified number of months (Continuation Period) for (1) severance pay equal to the sum of the employee’s monthly base salary at the time of termination plus one-twelfth of the employee’s target annual bonus and (2) continuation of employee benefit plan and executive compensation plan eligibility. Under such circumstances, if the employee had completed 15 years of service with Allegheny prior to the date of termination, the employee would be entitled to receive benefits under the SERP as

if the employee had attained age 55 or older, adding the Continuation Period to the employee’s age for this purpose. The Continuation Period varies among the named executive officers from 18 to 30 months. The monthly severance pay and continuation period for Mr. Pifer is $66,250 and 18 months.

Alan J. Noia. In connection with the retirement of Mr. Noia on May 1, 2003, Mr. Noia entered into an agreement with AE and AESC. Under the agreement, Mr. Noia will receive monthly severance payments in accordance with terms of his existing employment contract for 30 months of approximately $133,333. Mr. Noia is a participant in SERP, and is eligible to receive SERP payments. The agreement required AE to purchase insurance or annuity policies as necessary to fully insure or annuitize the SERP benefits in accordance with past practice relating to SERP benefits. The agreement required AE to pay to Mr. Noia obligations accrued to him under existing arrangements prior to retirement as of his retirement date and, accordingly, $72,422 was paid to him in May 2003, with respect to his accrued benefit under the 1993 deferred compensation plan. The agreement provides that Mr. Noia’s deferred stock awards under the LTIP are payable in the form of AE common stock in January 2004. The agreement provides that Mr. Noia’s vested stock options will continue to remain exercisable until May 2006. The agreement permits Mr. Noia to request a release from certain non-competition covenants, provided that such a release will result in the loss of any vested but unexercised options outstanding at the time of the release. In recognition of ongoing matters in which Allegheny may require communication and cooperation with Mr. Noia, the agreement also provides that for three years Mr. Noia will be provided or reimbursed the cost of office space and support at AE, and certain maintenance and connection for his home security monitoring system previously installed by AE for a three-year period. Mr. Noia has agreed to cooperate with Allegheny with respect to ongoing or future litigation and proceedings.

Michael P. Morrell. Mr. Morrell elected to retire under the ERO effective September 1, 2003. Under the terms of the ERO, Mr. Morrell was credited with three additional years of service under the SERP. Mr. Morrell also entered into an agreement with AESC under which AESC agreed to waive the requirement that Mr. Morrell serve ten years with Allegheny in order to be credited with eight additional years of service for purposes of the SERP. Mr. Morrell’s retirement under the agreement will effect the termination of his Employment Agreement and Change in Control Contract with AE. The agreement also subjects Mr. Morrell to certain, confidentiality, non-competition and non-solicitation covenants.

Bruce E. Walenczyk. On June 1, 2003, Mr. Walenczyk elected to retire under the ERO. Mr. Walenczyk and AESC are parties to an agreement in connection with Mr. Walenczyk’s retirement under which: (1) Mr. Walenczyk is entitled to the benefits provided for in the ERO; and (2) Mr. Walenczyk received a payment of $150,000 on June 13, 2003 and will receive a payment of $150,000 on January 9, 2004. Mr. Walenczyk’s retirement under the agreement effected the termination of his Employment Agreement and Change in Control Agreement. The agreement also subjects Mr. Walenczyk to certain confidentiality, non-competition and non-solicitation covenants. Mr. Walenczyk has agreed to cooperate with Allegheny with respect to ongoing or future litigation and proceedings.

Richard J. Gagliardi. On August 1, 2003, Mr. Gagliardi elected to retire under the ERO. Mr. Gagliardi and AESC are parties to an agreement in connection with Mr. Gagliardi’s retirement under which: (1) Mr. Gagliardi is entitled to the benefits provided for in the ERO; and (2) Mr. Gagliardi will receive payments totaling $24,585 for consulting services, payable in five installments beginning on August 8, 2003. Mr. Gagliardi’s retirement under the agreement effected the termination of his Employment Agreement and Change in Control Agreement. The agreement also subjects Mr. Gagliardi to certain confidentiality, non-competition and non-solicitation covenants, and requires Mr. Gagliardi to cooperate with Allegheny in connection with ongoing or future litigation and proceedings.

Jay S. Pifer. Mr. Pifer was also provided with an enhanced benefit under the SERP. His SERP benefit will be based on highest one-year earnings.

The members of AE’s Management Compensation and Development Committee for the fiscal year ended December 31, 2002 were: Frank A. Metz, Jr. (chairman); Eleanor Baum; Lewis B. Campbell and Gunnar E. Sarsten. There were no interlocking directorships, and there was no insider participation on this committee during the fiscal year ended December 31, 2002.

In 2002, directors who were not officers or employees (outside directors) received for all services to the registrants $22,000 in retainer fees, $1,000 for each Board meeting attended and $1,000 for each Committee meeting attended. Beginning in November 2002, the members of the Audit Committee received $1,200 for each meeting of the Audit Committee attended. The Chairperson of each committee, other than the Executive Committee, receives an additional fee of $4,000 per year. The Chairman of the Audit Committee receives $8,000 per year.

Under an unfunded deferred compensation plan, an outside director may elect to defer receipt of all or part of his or her director’s fees for succeeding calendar years to be payable with accumulated interest when the director ceases to be such, in equal annual installments, or, upon authorization by the Board of Directors, in a lump sum.

In addition to the foregoing compensation, the outside directors of AE receive an annual retainer of $12,000 in shares of common stock. Further, a Deferred Stock Unit Plan for Outside Directors (Plan) provides for a lump sum payment (payable at the director’s election in one or more installments, including interest thereon equivalent to the dividend yield) to directors calculated by reference to the price of AE’s common stock. Outside directors who serve at least five years on the Board and leave at or after age 65, or upon death or disability, or as otherwise directed by the Board, will receive payments under the Plan. In 2002, AE credited each outside director’s account with 375 deferred stock units.

The table below shows the number of shares of AE common stock that are beneficially owned, directly or indirectly, by each director and named executive officer of AE, Monongahela, Potomac Edison, West Penn, AGC, and AE Supply and by all directors and executive officers of each such company as a group as of September 15, 2003. To the best of AE’s knowledge, there is no person who is a beneficial owner of more than five percent of the voting securities of AE.

As of September 15, 2003, all of the shares of common stock of Monongahela (5,891,000), Potomac Edison (22,385,000), and West Penn (24,361,586) are owned by AE. All of the common stock of AGC is owned by AE Supply (77.03 percent) and Monongahela (22.97 percent). As of June 30, 2003, ML IBK Positions, Inc. owned 1.974 percent of the ownership interests in AE Supply, and AE held the remainder. See ITEM 3. LITIGATION.

The table below shows information as of September 15, 2003 related to the number of shares of AE common stock to be issued upon exercise of outstanding options and the number of securities remaining available for future issuance under equity compensation plans.

In 2002 and 2003, the law firm Swidler Berlin Shereff Friedman, LLP performed legal services for AE and its subsidiaries. Mr. Hoecker, a Director of AE, is a partner at Swidler Berlin Shereff Friedman, LLP.

After Allegheny filed its quarterly reports on Form 10-Q for the period ended June 30, 2002, Allegheny identified a miscalculation in its business segment information. Following the discovery of this miscalculation and in light of Allegheny’s prior restatements of reports filed with the SEC, Allegheny initiated a comprehensive review of its financial processes, records, and internal controls to ensure that its current and prior financial statements are fairly presented in accordance with generally accepted accounting principles. As a result, Allegheny identified numerous accounting errors, the most significant of which relate to:

In addition, Allegheny identified certain adjustments affecting only years prior to 2002 primarily as follows:

See Note 2 of the consolidated financial statements of AE Supply, Monongahela, Potomac Edison, and West Penn for additional information regarding the effect of the above accounting errors on each of these registrants.

These accounting errors resulted principally from internal control deficiencies, which were identified by Allegheny during the performance of the comprehensive financial review, and related primarily to the following:

Many of these deficiencies were aggravated by difficulties in integrating the energy trading business that Allegheny acquired in March 2001. Among other issues, the acquisition did not include middle-and back-office infrastructure and systems. Allegheny is currently engaged in litigation in which it is pursuing claims relating to this acquisition, as described under ITEM 3. LITIGATION.

In connection with their review of the Allegheny’s financial statements for the quarter ended June 30, 2002, PricewaterhouseCoopers LLP (PwC), by letter dated August 26, 2002, advised Allegheny’s Audit Committee of the Board of Directors that it noted certain deficiencies involving the internal controls related to Allegheny’s energy trading operations and the failure of identified controls to prevent and/or detect misstatements of accounting information that PwC considered to be material weaknesses under standards established by the American Institute of Certified Public Accountants. The Board of Directors, through the Audit Committee, directed that management undertake a comprehensive program to address and resolve all of these concerns.

Due to the ongoing comprehensive financial review and accounting errors identified by Allegheny, Allegheny and its subsidiaries delayed the filing of this report, and have not filed their quarterly reports on Form 10-Q for the periods ended September 30, 2002, March 31, 2003, and June 30, 2003.

Based on the results of its comprehensive financial review, Allegheny was able to determine that its financial statements for periods prior to 2002 do not require restatement as discussed in Note 2 to the consolidated financial statements.

Allegheny has implemented corrective actions to mitigate the risk that its internal control deficiencies could lead to material misstatements in the financial statements filed as part of this Form 10-K. Allegheny developed and implemented a plan to perform significant additional procedures designed to mitigate the effects of the deficiencies in internal controls and hired outside professional services firms to assist in the performance of the additional procedures. Allegheny’s additional procedures included the reconciliation and analysis of balance sheet accounts, analysis of various transactions for proper classification and cut-off, and the analysis of various accounting processes to determine additional actions necessary to ensure the accuracy of Allegheny’s financial records and identify corrective actions needed to improve internal controls. These outside professional service firms are continuing to assist Allegheny with the performance of its additional procedures to ensure the ongoing accuracy of Allegheny’s financial statements and improve Allegheny’s internal controls. These additional procedures were designed to enable the completion of the audit of Allegheny’s financial statements for 2002, which PwC completed on September 23, 2003. However, PwC, in its report dated September 12, 2003, has advised the Audit Committee of continuing material weaknesses noted during the 2002 audit. The Audit Committee discussed PwC’s findings with management, and directed management to continue its efforts to address, and expeditiously resolve, such material weaknesses. Management informed the Audit Committee that it will continue to address and correct such material weaknesses.

Regarding its internal controls for energy trading operations, Allegheny has revised its corporate energy risk policy to incorporate the best practices as defined by the Committee of Chief Risk Officers (CCRO) in its governance white paper issued in November 2002, which is included as Exhibit No. 99.1 to this report. As a result, the role and responsibilities of Allegheny’s corporate risk management function, which is independent from its energy trading operations, have been significantly expanded, to include the responsibility for determining the fair value of energy trading positions. Allegheny has established clear separation of duties for front-, middle-, and back-office activities. Allegheny also reduced transaction and exposure limits for its energy trading operations. Allegheny has undertaken an initiative to select from an outside provider and implement a new transaction processing system for front-, middle-, and back-office areas. It is expected that the core functions of this system will be in operation by mid- 2004.

Allegheny’s management, Audit Committee, and Board of Directors are fully committed to resolving Allegheny’s internal control deficiencies. Ultimate resolution of the deficiencies will include changing the culture of the accounting function to focus on accountability and strict, timely adherence to a set of sound internal control policies and procedures. As discussed in ITEM 1. BUSINESS—Recent Events—Senior Management Changes, Allegheny has recently made substantial changes in its senior management. Management has commenced or is undertaking the following corrective actions in order to achieve an immediate improvement in the controls environment:

Allegheny expects to implement all of these corrective actions during the remainder of 2003 and 2004. Before December 31, 2004, Allegheny expects that it will have restored the effectiveness of its internal controls and will no longer need to rely on the performance of additional procedures to ensure the accuracy and completeness of its financial statements.

To address the weaknesses identified in Allegheny’s internal controls and disclosure practices, Allegheny substantially augmented and revised its procedures in connection with the preparation of this report. These augmented procedures involved the creation of a formal drafting group to comprehensively review, revise and update disclosure over an extensive iterative process. This exercise also involved a heightened degree of direct involvement by senior officers, including the Chief Executive Officer and the Chief Financial Officer. The principal elements of these augmented procedures have formed the basis for Allegheny’s written disclosure controls and procedures applicable to future periodic reports and certain public communications.

Allegheny has created a Disclosure Committee, which is chaired by Allegheny’s General Counsel and currently comprised of executives, including Allegheny’s Chief Risk Officer, Vice President and Controller, Director of Audit Services and Vice President, Corporate Communications, as well as the senior officers responsible for Allegheny’s segments. The Disclosure Committee’s principal functions are to establish, maintain, monitor and evaluate Allegheny’s written disclosure controls and procedures, and to supervise and coordinate the preparation of Allegheny’s periodic reports and certain other public communications.

Following its formation, the Disclosure Committee adopted formal written disclosure controls and procedures. These newly-adopted disclosure controls and procedures will be applicable to Allegheny’s future periodic reports and certain public communications.

The Disclosure Committee, with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, reviewed the augmented procedures implemented by Allegheny in connection with the preparation of this report and found them to be satisfactory. However, until Allegheny completes the actions described above to achieve improvements in its internal controls, Allegheny intends to devote additional resources to ensure that its public disclosures are accurate.

The above matters have been undertaken by Allegheny at the direction and with the oversight of the Audit Committee of the Board of Directors and with extensive involvement of PwC and other outside professional services firms.

(i) AE, Inc. on December 19, 2002, Items 7 and 9, attaching Unaudited Consolidated Financial Data for Nine Months Ended September 30, 2002; and

(ii) AE Supply on December 19, 2002, Items 7 and 9, attaching Unaudited Consolidated Financial Data for Nine Months Ended September 30, 2002.

(i) AE Inc., on July 8, 2002, Items 7 and 9, attaching Press Release regarding Allegheny Energy Revised 2002 Earnings Guidelines;

(ii) AE, Inc., on July 31, 2002, Items 7 and 9, attaching Second Quarter Earnings Release; and

(iii) AE, Inc., on August 14, 2002, Items 7 and 9, attaching Statements under oath of Principal Executive Officer and Principal Financial Officer regarding facts and circumstances relating to Exchange Act filings.

(i) AE, Inc. on March 7, 2003, Items 7 and 9, attaching Press Release regarding announcement of decision of CEO to retire;

(ii) AE, Inc. on March 7, 2003, Items 7 and 9, attaching Press Release regarding Adjournment of Special Meeting of Stockholders;

(iii) AE, Inc. on March 10, 2003, Items 7 and 9, attaching Press Release regarding Postponement of 2003 Annual Meeting of Stockholders;

(iv) AE, Inc. on March 17, 2003, Items 7 and 9, attaching Press Release regarding Stockholder Approval of Charter Amendment;

(v) AE, Inc. on April 16, 2003, Items 7 and 9, attaching Press Release regarding Appointment by the Board of Directors of Interim President and CEO and Lead Director;

(vi) AE, Inc. on May 15, 2003, Items 7 and 9, attaching Press Release regarding announcement of executive leadership change;

(vii) AE, Inc. on May 23, 2003, Items 7 and 9, attaching Press Release regarding announcement of executive leadership change;

(viii) AE, Inc. on June 11, 2003, Items 7 and 9, attaching Press Release regarding announcement of election by the Board of Directors of Chairman, President, and CEO;

(ix) AE, Inc. on June 11, 2003, Items 7 and 9, attaching Press Release announcing renegotiation of terms and conditions of its energy supply contract with CDWR;

(x) AE, Inc. on June 24, 3003, Items 7 and 9, attaching Press Release announcing that its common equity ratio has fallen below the level required under certain key SEC authorizations;

(xi) AE, Inc. on July 7, 2003, Items 7 and 9, attaching Press Release regarding announcement of appointment of Senior Vice President and Chief Financial Officer;

(xii) AE, Inc. on July 17, 2003, Items 5 and 7, issued notice announcing its intention to issue and sell, through Allegheny Capital Trust I, a special purpose finance subsidiary of AYE, Mandatorily Convertible Trust Preferred Securities;

(xiii) AE, Inc. on July 23, 2003, Items 7 and 9, attaching Press Release regarding announcement of appointment of Vice President and General Counsel;

(xiv) AE, Inc. on July 25, 2003, Items 7 and 9, announcing that it has completed a private placement of $300 million of convertible trust preferred securities;

(xv) AE, Inc. on July 30, 2003, Items 7 and 9, announcing that its ATFC has signed a definitive agreement to sell its energy supply contract with the CDWR;

(xvii) AE Supply on August 1, 2003, Items 5 and 7, attaching financing documents;

(xviii) Monongahela on August 1, 2003, Items 5 and 7, attaching financing documents;

(xix) West Penn on August 1, 2003, Items 5 and 7, attaching financing documents; and

(xx) AE, Inc. on August 19, 2003, Items & and 9, attaching Press Release regarding announcement of appointment of President of Allegheny Power.

ALLEGHENY ENERGY, INC.

By:		/s/ PAUL J. EVANSON
		(Paul J. Evanson, Chairman, President, and Chief Executive Officer)

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

MONONGAHELA POWER COMPANY

By:		/s/ JOSEPH H. RICHARDSON
		(Joseph H. Richardson, President)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant, in the capacities and on the date indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

THE POTOMAC EDISON COMPANY

By:		/s/ JOSEPH H. RICHARDSON
		(Joseph H. Richardson, President)

WEST PENN POWER COMPANY

By:		/s/ JOSEPH H. RICHARDSON
		(Joseph H. Richardson, President)

ALLEGHENY GENERATING COMPANY

By:		/s/ JAY S. PIFER
		(Jay S. Pifer, President)

ALLEGHENY ENERGY SUPPLY COMPANY, LLC

By:		/s/ JAY S. PIFER
		(Jay S. Pifer, President)

We hereby consent to the incorporation by reference in Allegheny Energy, Inc.’s Registration Statements on Form S-3 (Nos. 33-36716, 33-57027, 33-49791, 333-41638, 333-49086, 333-56786; and 333-82176); Allegheny Energy, Inc.’s Registration Statements on Form S-8 (No. 333-65657 and No. 333-40432); Monongahela Power Company’s Registration Statements on Form S-3 (Nos. 333-31493, 33-51301, 33-56262, 33-59131 and 333-38484); The Potomac Edison Company’s Registration Statements on Form S-3 (Nos. 333-33413, 33-51305 and 33-59493); West Penn Power Company’s Registration Statements on Form S-3 (Nos. 333-34511, 33-51303, 33-56997, 33-52862, 33-56260 and 33-59133); and Allegheny Energy Supply Company, LLC’s Registration Statement on Form S-4/A (No. 333-72498); of our reports dated September 23, 2003, relating to the financial statements and financial statement schedules, which appear in this Form 10-K.

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Energy, Inc., a Maryland corporation, do hereby constitute and appoint DAVID B. HERTZOG and ROBERT T. VOGLER, and each of them, a true and lawful attorney in his or her name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2002, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratifies and confirms all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Monongahela Power Company, an Ohio corporation, The Potomac Edison Company, a Maryland and Virginia corporation, and West Penn Power Company, a Pennsylvania corporation, do hereby constitute and appoint DAVID B. HERTZOG and ROBERT T. VOGLER, and each of them, a true and lawful attorney in his name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2002, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

/s/ PAUL J. EVANSON

(Paul J. Evanson)

/s/ JOSEPH H. RICHARDSON

(Joseph H. Richardson)

/s/ JAY S. PIFER

(Jay S. Pifer)

/s/ JEFFREY D. SERKES

(Jeffrey D. Serkes)

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Generating Company, a Virginia corporation, do hereby constitute and appoint DAVID B. HERTZOG and ROBERT T. VOGLER, and each of them, a true and lawful attorney in his name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2002, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

/s/ PAUL J. EVANSON

(Paul J. Evanson)

/s/ JAY S. PIFER

(Jay S. Pifer)

/s/ JEFFREY D. SERKES

(Jeffrey D. Serkes)

/s/ DAVID C. BENSON

(David C. Benson)

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Energy Supply Company, LLC, a Delaware limited liability company, do hereby constitute and appoint DAVID B. HERTZOG and ROBERT T. VOGLER, and each of them, a true and lawful attorney in his or her name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2002, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratifies and confirms all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

/s/ PAUL J. EVANSON

(Paul J. Evanson)

/s/ JAY S. PIFER

(Jay S. Pifer)

/s/ JEFFREY D. SERKES

(Jeffrey D. Serkes)

/s/ DAVID C. BENSON

(David C. Benson)

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification Number
1-267	ALLEGHENY ENERGY, INC.	13-5531602
	(A Maryland Corporation)
	10435 Downsville Pike
	Hagerstown, Maryland 21740-1766
	Telephone (301) 790-3400

333-72498	ALLEGHENY ENERGY SUPPLY	23-3020481
	COMPANY, LLC
	(A Delaware Limited Liability Company)
	4350 Northern Pike
	Monroeville, Pennsylvania 15146-2841
	Telephone (412) 858-1600

1-5164	MONONGAHELA POWER COMPANY	13-5229392
	(An Ohio Corporation)
	1310 Fairmont Avenue
	Fairmont, West Virginia 26554
	Telephone (304) 366-3000

1-3376-2	THE POTOMAC EDISON COMPANY	13-5323955
	(A Maryland and Virginia Corporation)
	10435 Downsville Pike
	Hagerstown, Maryland 21740-1766
	Telephone (301) 790-3400

1-255-2	WEST PENN POWER COMPANY	13-5480882
	(A Pennsylvania Corporation)
	800 Cabin Hill Drive
	Greensburg, Pennsylvania 15601
	Telephone (724) 837-3000

0-14688	ALLEGHENY GENERATING COMPANY	13-3079675
	(A Virginia Corporation)
	10435 Downsville Pike
	Hagerstown, Maryland 21740-1766
	Telephone (301) 790-3400

Registrant	Title of each class	Name of exchange on which registered
Allegheny Energy, Inc.	Common Stock, $1.25 par value	New York Stock Exchange Chicago Stock Exchange Pacific Stock Exchange

Monongahela Power Company	Cumulative Preferred Stock, $100 par value: 4.40 percent 4.50 percent, Series C	American Stock Exchange American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Allegheny Generating Company	Common Stock, $1.00 par value	None


	Aggregate market value of voting and non-voting common equity held by nonaffiliates of the registrants at June 30, 2003	Number of shares of common stock of the registrants outstanding at June 30, 2003

Allegheny Energy, Inc.	$1,072,943,406	126,975,551 ($1.25 par value)

Monongahela Power Company	None. (a)	5,891,000 ($50 par value)

The Potomac Edison Company	None. (a)	22,385,000 ($.01 par value)

West Penn Power Company	None. (a)	24,361,586 (no par value)

Allegheny Generating Company	None. (b)	1,000 ($1.00 par value)

Allegheny Energy Supply Company, LLC	None. (c)	(d)

(In Millions)		2002			2001			Percent Change
Generation & Marketing Revenues		$	945.3		$	1,928.1		(51.0	)%

	2002		2001		Percent Change
Regulated Kilowatt-hour Sales:
Residential		15,152		14,454	4.8	%
Commercial		10,059		9,616	4.6	%
Industrial		20,131		19,884	1.2	%
Wholesale and Other		1,443		1,502	(3.9	)%
Total Regulated Kilowatt-hour Sales:		46,785		45,456	2.9	%

Regulated Electric Revenues (In Millions):
Residential	$	1,052.4	$	1,002.1	5.0	%
Commercial		594.3		554.0	7.3	%
Industrial		803.8		772.3	4.1	%
Wholesale and Other		39.7		66.6	(40.4	)%
Total Regulated Electric Revenues:	$	2,490.2	$	2,395.0	4.0	%

Allegheny Energy, Inc.	Yes x	No ¨
Allegheny Energy Supply Company, LLC	Yes ¨	No x
Monongahela Power Company	Yes ¨	No x
The Potomac Edison Company	Yes ¨	No x
West Penn Power Company	Yes ¨	No x
Allegheny Generating Company	Yes ¨	No x

ACC		Allegheny Communications Connect, Inc., a subsidiary of Allegheny Ventures.

AE		Allegheny Energy, Inc., a diversified utility holding company.

AE Supply		Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of Allegheny Energy, Inc., also a holding company.

AESC		Allegheny Energy Service Corporation, a wholly owned subsidiary of Allegheny Energy, Inc.

AGC		Allegheny Generating Company, an unregulated generation unit of Allegheny Energy Supply Company, LLC.

Allegheny		Allegheny Energy, Inc. together with its consolidated subsidiaries.

Allegheny Ventures		Allegheny Ventures, Inc., a nonutility, unregulated subsidiary of Allegheny Energy, Inc.

Distribution Companies		Collectively, Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company. The Distribution Companies do business as Allegheny Power.

Green Valley Hydro		Green Valley Hydro, LLC, a subsidiary of Allegheny Energy, Inc.

MGS		Mountaineer Gas Services, Inc., a subsidiary of Mountaineer Gas Company.

Monongahela		Monongahela Power Company, a regulated subsidiary of Allegheny Energy, Inc.

Mountaineer		Mountaineer Gas Company, a subsidiary of Monongahela Power Company.

Potomac Edison		The Potomac Edison Company, a regulated subsidiary of Allegheny Energy, Inc.

West Penn		West Penn Power Company, a regulated subsidiary of Allegheny Energy, Inc.

WVP		West Virginia Power, a division of Monongahela Power Company.

CAAA		Clean Air Act Amendments of 1990

CDWR		California Department of Water Resources

Clean Air Act		Clean Air Act of 1970

CWA		Clean Water Act

EPA		United States Environmental Protection Agency

EPACT		National Energy Policy Act of 1992

FERC		Federal Energy Regulatory Commission (an independent commission within the Department of Energy)

EWG		Exempt wholesale generator

KWh		Kilowatt-hour

MW		Megawatt

MWh		Megawatt-hour

NSR		The New Source Performance Review Standards, or “New Source Review” applicable to facilities deemed “new” sources of emissions

OVEC		Ohio Valley Electric Corporation

PJM		PJM Interconnection, L.L.C., a regional transmission organization

PJM West		The commonly used name of the western extension of PJM Interconnection, L.L.C.

PLR		Provider-of-last-resort

PUHCA		Public Utility Holding Company Act of 1935, as amended

PURPA		Public Utility Regulatory Policies Act of 1978

RTO		Regional Transmission Organization

SEC		U.S. Securities and Exchange Commission

T&D		Transmission and Distribution

		Page
PART I:

ITEM 1.	Business	1
	Where You Can Find More Information	4
	Recent Events	4
	Previous Business Model	4
	Challenges Arising in 2002	5
	Continuing Challenges	7
	Allegheny’s Response	7
	Special Note Regarding Forward-Looking Statements	12
	Risk Factors	13
	Allegheny’s Sales and Revenues	31
	Generation and Marketing Revenues	31
	Regulated Electric Sales and Revenues	31
	Regulated Natural Gas Sales and Revenues	33
	Unregulated Services Revenues	33
	Construction and Other Capital Expenditures	34
	Electric Facilities	36
	Allegheny Map	39
	Fuel, Power, and Resource Supply	40
	Rate Matters	44
	Regulatory Framework Affecting Allegheny	46
	Federal Regulation	46
	State Legislation and Regulatory Developments	49
	Allegheny’s Competitive Actions	53
	Employees	58
	Environmental Matters	58
	Air Standards	58
	Water Standards	60
	Hazardous and Solid Wastes	63
	Penalties and Noncompliance	63
	Research and Development	63

ITEM 2.	Properties	64

ITEM 3.	Legal Proceedings	65

ITEM 4.	Submission of Matters to a Vote of Security Holders	71

PART II:

ITEM 5.	Market for the Registrants’ Common Equity and Related Stockholder Matters	73

ITEM 6.	Selected Financial Data	75
	Allegheny Energy, Inc.	76
	Allegheny Energy Supply Company, LLC	77
	Monongahela Power Company	78
	The Potomac Edison Company	79
	West Penn Power Company	80
	Allegheny Generating Company	81

		Page

ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	82
	Allegheny Energy, Inc.	83
	Allegheny Energy Supply Company, LLC	114
	Monongahela Power Company	136
	The Potomac Edison Company	147
	West Penn Power Company	156
	Allegheny Generating Company	165

ITEM 7A.	Quantitative and Qualitative Disclosure About Market Risk	170
	Allegheny Energy, Inc.	170
	Allegheny Energy Supply Company, LLC	174
	Monongahela Power Company	178
	The Potomac Edison Company	179
	West Penn Power Company	180
	Allegheny Generating Company	181

ITEM 8.	Financial Statements and Supplementary Data	182
	Allegheny Energy, Inc.	183
	Allegheny Energy Supply Company, LLC	248
	Monongahela Power Company	293
	The Potomac Edison Company	327
	West Penn Power Company	352
	Allegheny Generating Company	376

ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	400

PART III:

ITEM 10.	Directors and Executive Officers of the Registrants	400

ITEM 11.	Executive Compensation	407

ITEM 12.	Security Ownership of Certain Beneficial Owners and Management	424

ITEM 13.	Certain Relationships and Related Transactions	425

ITEM 14.	Controls and Procedures	425

PART IV:

ITEM 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	429

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.		430

SIGNATURES		431

	2002		2003		2004
(In Millions)	(Actual)		(Estimated)
AE Supply
Total Generation	$	205.2	$	176.7	$	103.4
Environmental Portion		157.0		51.2		71.1

Monongahela
Total Generation		42.9		18.4		27.2
Environmental Portion		39.1		12.5		19.8

AGC
Total Generation		1.4		9.7		6.0
Environmental Portion		—		—		—

Total Generation and Marketing Construction Expenditures	$	249.5	$	204.8	$	136.6

Potomac Edison*
T&D		45.7		59.1		59.8
Environmental		—		—		—

West Penn*
T&D		57.9		45.4		58.9
Environmental		—		—		—

Monongahela*
T&D		49.8		50.6		45.2
Environmental		—		—		—

Allegheny Ventures		0.4		—		—

AESC		0.4		2.1		3.8

Total Delivery and Services Construction Expenditures	$	154.2	$	157.2	$	167.7

Total Construction Expenditures	$	403.7	$	362.0	$	304.3

			Regulated		Unregulated
Allegheny Station			Monongahela		AE Supply and Other		Service Commencement Dates (b)
	Units	Total
Coal-Fired (Steam):
Albright (Albright, WV)	3	292	184		108		1952-4
Armstrong (Adrian, PA)	2	356			356		1958-9
Conemaugh (c) (New Florence, PA)	2	83			83	(c)	2001
Fort Martin (Maidsville, WV)	2	1,107	212		895		1967-8
Harrison (Haywood, WV)	3	1,961	417		1,544		1972-4
Hatfield’s Ferry (Masontown, PA)	3	1,710	400		1,310		1969-71
Hunlock (d) (Hunlock Creek, PA)	1	24			24	(d)	2000(d)
Mitchell (Courtney, PA)	1	288			288		1963
Ohio Valley Electric Corp. (e) (Chelsea, OH) (Madison, IN)	11	280	78	(e)	202	(e)
Pleasants (Willow Island, WV)	2	1,300	277		1,023		1979-80
Rivesville (Rivesville, WV)	2	142	121		21		1943-51
R. Paul Smith (Williamsport, MD)	2	116			116		1947-58
Willow Island (Willow Island, WV)	2	243	207		36		1949-60

Gas-Fired:
AE Nos. 1 & 2 (Springdale, PA)	2	88			88		1999
AE Nos. 8 & 9 (Gans, PA)	2	88			88		2000
AE Nos. 12 & 13 (Chambersburg, PA)	2	88			88		2001
Buchanan (f) (Oakwood, VA)	2	43			43		2002
Gleason (Gleason, TN)	3	526			526		2001
Hunlock CT (d) (Hunlock Creek, PA)	1	22			22	(d)	2000
Lincoln (Manhattan, IL)	8	672			672		2001
Wheatland (Wheatland, IN)	4	512			512		2001

Oil-Fired Steam:
Mitchell (g) (Courtney, PA)	1	82			82		1948-49

Pumped-Storage and Hydro:
Bath County (h) (Warm Springs, VA)	6	960	221	(h)	739	(h)	1985; 2001
Lake Lynn (i) (Lake Lynn, PA)	4	52			52		1926
Potomac Edison Hydroelectric (i)	21	6			6		Various

Total Allegheny-Owned Capacity	92	11,041	2,117		8,924

		Allegheny Company Purchaser
PURPA Generation Project	Project Total	Monongahela	Potomac Edison		West Penn	AE Supply And Other	PURPA Contract Termination Date

Coal-Fired: Steam
AES Beaver Valley (Monaca, PA)	125				125		12/13/2016
Grant Town (Grant Town, WV)	80	80					05/28/2028
West Virginia University (Morgantown, WV)	50	50					04/17/2027
AES Warrior Run (k) (Cumberland, MD)	180		180	(k)			02/10/2030

Hydro:
Allegheny Lock and Dam 5 (Freeport, PA)	6				6		09/30/2034
Allegheny Lock and Dam 6 (Freeport, PA)	7				7		06/30/2034
Hannibal Lock and Dam (New Martinsville, WV)	31	31					06/01/2034

Total Other Capacity	479	161	180		138

Total Allegheny-Owned and PURPA Committed Generating Capacity (a)	11,520	2,278	180		138	8,924

	Underground	Above- Ground	Total Miles	Total Miles Consisting of 500-Kilovolt (kV) Lines	Number of Transmission and Distribution Substations
Monongahela	538	22,715	23,253	235	340
Potomac Edison	3,959	17,868	21,827	174	277
West Penn	2,265	23,987	26,252	276	679
AGC (a)	0	87	87	87	1
Total	6,762	64,657	71,419	772	1,297

Distribution Company	State	Percentage of Total 2002 Power Purchases for PLR Obligations from AE Supply by Jurisdiction (a)	Percentage of Total 2002 Power Purchases for PLR Obligations from AE Supply in Aggregate (b)	Termination Date of Power Sale Agreement with AE Supply
Monongahela	Ohio	100 percent	4 percent	December 31, 2005
Potomac Edison	Maryland	100 percent	26 percent	December 31, 2008
Potomac Edison	West Virginia	100 percent	8 percent	December 31, 2017*
Potomac Edison	Virginia	99 percent	8 percent	July 1, 2007
West Penn	Pennsylvania	94 percent	54 percent	December 31, 2008

	Twelve Months Ended December 31, 2002
	Volume (Mmcf)	Percent of Total
MGS-Owned/Controlled Production	1,444	5.3
Consumers Gas Utility Company	3	—
Hope Gas, Inc.	59	—
Cabot Oil & Gas Marketing Corporation	791	3
Energy Corporation of America	2,694	10
Other Appalachian Basin Producers/Suppliers	1,712	6.3
AEP Energy Services	500	1.8
Amerada Hess Corporation	610	2.2
Anadarko Energy Services	1,507	5.5
BP/Amoco	3,444	12.7
Cinergy Marketing & Trading, L.P.	1,141	4.2
Conoco, Inc.	1,785	6.6
Coral Energy, L.P.	969	3.6
EnergyUSA-TPC	1,161	4.3
Idacorp Energy, L.P.	1,662	6.1
Marathon Oil Company	200	1
Mirant Americas Energy Marketing, L.P.	1,374	5.1
Noble Gas Marketing, Inc.	2,879	10.6
Occidental Energy Marketing, Inc.	29	—
PG&E Energy Trading-Gas Corporation	672	2.5
Virginia Power Energy Marketing, Inc.	2,486	9.2

Totals	27,122	100

Nominees for Director	Votes For	Votes Withheld
Frank A. Metz, Jr.	104,904,846	3,683,708
Alan J. Noia	104,920,548	3,668,006
Steven H. Rice	105,007,960	3,580,594

Shareholder Action Items Referenced Above	Votes For	Votes Against	Abstentions	Total
(2)	102,047,599	5,712,526	817,819	108,577,944
(3)	46,991,073	39,321,399	2,515,302	88,827,774
(4)	7,057,999	77,659,490	4,115,697	88,833,186
(5)	34,899,562	51,684,756	2,239,310	88,823,628
(6)	29,051,930	57,517,191	2,257,807	88,826,928
(7)	11,231,186	74,114,914	3,491,091	88,837,191
(8)	24,523,230	61,428,886	2,884,372	88,836,488
(9)	48,143,789	38,588,132	2,094,949	88,826,870

	2002							2001
	Dividend	High		Low		Close		Dividend	High		Low		Close
1^st Quarter	43 cents	$	41.35	$	32.26	$	41.35	43 cents	$	48.22	$	41.06	$	46.26
2^nd Quarter	43 cents	$	43.53	$	25.75	$	25.75	43 cents	$	54.79	$	45.74	$	48.25
3^rd Quarter	43 cents	$	26.95	$	11.73	$	13.10	43 cents	$	48.82	$	35.84	$	36.70
4^th Quarter	None	$	12.00	$	3.80	$	7.56	43 cents	$	39.90	$	33.25	$	36.22

	2003
	Dividend	High		Low		Close
1^st Quarter	None	$	10.30	$	4.82	$	6.21
2^nd Quarter	None	$	9.69	$	6.26	$	8.45

		Page No.
Allegheny		76

AE Supply		77

Monongahela		78

Potomac Edison		79

West Penn		80

AGC		81

Year ended December 31 (a)	2002			2001		2000		1999		1998
(In millions, except per share data)
Total operating revenues (b)	$	2,988.5		$	3,425.1	$	2,653.1	$	2,808.4	$	2,576.4
Cost of revenues		1,701.2			1,116.8		832.7		1,096.0		933.4
Other operating expenses		1,786.4			1,348.3		1,099.3		1,073.4		1,035.1
Consolidated income (loss) before extraordinary charge and cumulative effect of accounting change (c) (d)	$	(502.2	)	$	448.9	$	313.7	$	285.4	$	263.0
Earnings per share
Consolidated income (loss) before extraordinary charge and cumulative effect of accounting change—basic	$	(4.00	)	$	3.74	$	2.84	$	2.45	$	2.15
—diluted	$	(4.00	)	$	3.73	$	2.84	$	2.45	$	2.15
Dividends declared per share	$	1.29		$	1.72	$	1.72	$	1.72	$	1.72

Short-term debt	$	1,132.0		$	1,238.7	$	722.2	$	641.1	$	258.8
Long-term debt due within one year		257.2			353.1		160.2		189.7		—
Debentures, notes and bonds (e)		3,662.2			—		—		—		—

Total short-term obligations	$	5,051.4		$	1,591.8	$	882.4	$	830.8	$	258.8

Long-term debt and QUIDS (e)	$	115.9		$	3,200.4	$	2,559.5	$	2,254.5	$	2,179.3
Capital leases		39.1			35.3		34.4		.9		1.1

Total long-term obligations	$	155.0		$	3,235.7	$	2,593.9	$	2,255.4	$	2,180.4

Total assets	$	10,600.3		$	11,032.5	$	7,697.0	$	6,852.4	$	6,535.2

Year ended December 31	2002		2001		2000		1999		1998
(In millions)
Affiliated operating revenues	$	64.1	$	68.5	$	70.0	$	70.6	$	73.8
Net income	$	18.6	$	20.3	$	21.9	$	21.2	$	22.8
Other operating expenses	$	25.8	$	25.5	$	27.6	$	26.5	$	26.2

Short-term debt	$	55.0	$	—	$	—	$	—	$	—
Long-term debt due within one year		50.0		—		—		—		—
Debentures (a)		99.3		—		—		—		—

Total short-term obligations	$	204.3	$	—	$	—	$	—	$	—

Long-term debt (a)	$	—	$	149.2	$	149.0	$	148.9	$	148.8
Capital leases		—		—		—		—		—

Total long-term obligations	$	—	$	149.2	$	149.0	$	148.9	$	148.8

Total assets	$	597.6	$	591.6	$	602.0	$	620.9	$	639.5

Year	Price Per megawatt-hour (MWh) Peak/Off-Peak		Volume Megawatt (MW)
2003	$	61 / $61	250
2004	$	61 / $60	500
2005	$	61 / $59	750
2006 - 2011	$	61 / $58	800

(In millions)	1-Percentage-Point Increase			1-Percentage-Point Decrease
Change in the discount rate:
Pension and OPEB benefit obligation	$	(134.8	)	$	151.0
Net periodic cost-pension and OPEB		(2.2	)		7.0
Change in expected return on plan assets:
Net periodic cost-pension and OPEB		(9.0	)		9.0

	Consolidated Net (Loss) Income
(In millions, except per share data)
	2002			2001			2000
Delivery and Services	$	84.1		$	187.5		$	162.3
Generation and Marketing		(586.3	)		261.4			151.3

Consolidated (loss) income before extraordinary charge and cumulative effect of accounting change		(502.2	)		448.9			313.6
Extraordinary charge, net (see Note 14 to consolidated financial statements)		—			—			(77.0	)
Cumulative effect of accounting change, net (see Notes 7 and 9 to consolidated financial statements)		(130.5	)		(31.1	)		—

Consolidated net (loss) income	$	(632.7	)	$	417.8		$	236.6


	Basic Earnings (Loss) Per Share
	2002			2001			2000
Delivery and Services	$	.67		$	1.56		$	1.47
Generation and Marketing		(4.67	)		2.18			1.37

Consolidated (loss) income before extraordinary charge and cumulative effect of accounting change		(4.00	)		3.74			2.84
Extraordinary charge, net (see Note 14 to consolidated financial statements)		—			—			(.70	)
Cumulative effect of accounting change, net (see Notes 7 and 9 to consolidated financial statements)		(1.04	)		(.26	)		—

Consolidated net (loss) income	$	(5.04	)	$	3.48		$	2.14

	Fair value of contracts at December 31, 2002
Classifications of contracts by source of fair value (In millions)	Delivery by December 31, 2003			Delivery from January 1, 2004, to December 31, 2005			Delivery from January 1, 2006, to December 31, 2007			Delivery from January 1, 2008, and beyond			Total fair value
Prices actively quoted	$	(39.5	)	$	(38.6	)	$	(9.5	)	$	(4.9	)	$	(92.5	)
Prices provided by other external sources		—			(1.6	)		(2.1	)		(2.1	)		(5.8	)
Prices based on models		4.6			146.7			233.3			143.4			528.0

Total	$	(34.9	)	$	106.5		$	221.7		$	136.4		$	429.7

(In millions)	2002
Net fair value of commodity contract assets and (liabilities) at January 1,	$	760.4
Unrealized losses on commodity contracts, net during 2002:
Fair value of structured transactions when entered into during 2002		12.2
Changes in fair value attributable to changes in valuation techniques and assumptions as a result of significant market changes during 2002		(608.1	)
Other unrealized gains on commodity contracts, net		237.6

Total unrealized losses on commodity contracts, net during 2002		(358.3	)
Net options paid or received*		27.6

Net fair value of commodity contract assets and liabilities at December 31,	$	429.7

	PLR				Excess Generation And Trading						Total Generation And Marketing
(In millions)	2002		2001		2002			2001			2002			2001
Operating revenues:
Physical	$	1,472.3	$	1.395.9	$	(178.6	)	$	5.0		$	1,293.7		$	1,400.9
Financial		—		—		(348.4	)		527.2			(348.4	)		527.2

Total operating revenues		1,472.3	$	1,395.9		(527.0	)		532.2			945.3			1,928.1

Cost of revenues:
Fuel for electric generation		564.4		519.4		27.1			41.0			591.5			560.4
Purchased energy and transmission:
Physical		39.7		59.7		82.9			103.0			122.6			162.7
Financial		—		—		10.2			(2.4	)		10.2			(2.4	)
Natural gas purchases
Financial		—		—		—			8.0			—			8.0

Total cost of revenues		604.1		579.1		120.2			149.6			724.3			728.7

Net revenues	$	868.2	$	816.8	$	(647.2	)	$	382.6		$	221.0		$	1,199.4

	Payments Due by Period
Contractual Cash Obligations and Commitments (In millions)	Payments by December 31, 2003		Payments from January 1, 2004, to December 31, 2005		Payments from January 1, 2006, to December 31, 2007		Payments from January 1, 2008, and beyond		Total
Short-term debt	$	1,132.0	$	—	$	—	$	—	$	1,132.0
Long-term debt due within one year*		253.4		—		—		—		253.4
Debentures, notes and bonds classified as current*		—		537.4		1,092.4		2,041.0		3,670.8
Long-term debt*		—		—		15.4		101.1		116.5
Capital lease obligations		9.3		20.1		13.7		11.3		54.4
Operating lease obligations		23.1		335.0		10.0		33.6		401.7
PURPA purchased power		213.8		406.0		418.4		4,393.7		5,431.9
Fuel purchase commitments		406.1		627.1		129.5		—		1,162.7

Total	$	2,037.7	$	1,925.6	$	1,679.4	$	6,580.7	$	12,223.4

Year	Price Per Megawatt-hour (MWh) Peak/Off-Peak		Volume in Megawatts (MW)
2003	$	61 / $61	250
2004	$	61 / $60	500
2005	$	61 / $59	750
2006 - 2011	$	61 / $58	800

	Fair value of contracts at December 31, 2002
Classifications of contracts by source of fair value (In millions)	Delivery by December 31, 2003			Delivery from January 1, 2004, to December 31, 2005			Delivery from January 1, 2006, to December 31, 2007			Delivery from January 1, 2008, and beyond			Total fair value
Prices actively quoted	$	(39.5	)	$	(38.6	)	$	(9.5	)	$	(4.9	)	$	(92.5	)
Prices provided by other external sources		—			(1.6	)		(2.1	)		(2.1	)		(5.8	)
Prices based on models		5.0			144.8			233.3			143.4			526.5

Total	$	(34.5	)	$	104.6		$	221.7		$	136.4		$	428.2

	PLR				Excess Generation and Trading					Total Generation and Marketing
(In millions)	2002		2001		2002			2001		2002			2001
Operating revenues:
Physical	$	1,181.1	$	1,107.5	$	(136.3	)	$	23.0	$	1,044.8		$	1,130.5
Financial		—		—		(361.8	)		527.2		(361.8	)		527.2

Total operating revenues		1,181.1	$	1,107.5		(498.1	)		550.2		683.0			1,657.7

Cost of revenues:
Fuel consumed for electric generation		443.7		400.1		19.0			24.6		462.7			424.7
Purchased energy and transmission:
Physical		50.4		77.3		95.7			153.4		146.1			230.7
Financial		—		—		7.1			5.5		7.1			5.5

Total cost of revenues		494.1		477.4		121.8			183.5		615.9			660.9

Net revenues	$	687.0	$	630.1	$	(619.9	)	$	366.7	$	67.1		$	996.8

	Payments Due by Period
Contractual Cash Obligations and Commitments (In millions)	Payments by December 31, 2003		Payments from January 1, 2004, to December 31, 2005		Payments from January 1, 2006, to December 31, 2007		Payments from January 1, 2008, and beyond		Total
Short-term debt	$	797.0	$	—	$	—	$	—	$	797.0
Long-term debt due within one year*		114.4		—		—		—		114.4
Debentures, notes and bonds classified as current*		—		—		492.7		1,263.7		1,756.4
Long-term debt*		—		—		14.6		77.6		92.2
Capital lease obligations		1.0		.3		—		—		1.3
Operating lease obligations		16.8		329.2		9.0		33.6		388.6
Fuel purchase commitments		308.4		480.2		99.6		—		888.2

Total	$	1,237.6	$	809.7	$	615.9	$	1,374.9	$	4,038.1

	Payments Due by Period
Contractual Cash Obligations and Commitments (In millions)	Payments by December 31, 2003		Payments from January 1, 2004, to December 31, 2005		Payments from January 1, 2006, to December 31, 2007		Payments from January 1, 2008, and Beyond		Total
Notes and bonds classified as current*	$	—	$	—	$	100.0	$	320.0	$	420.0
Capital lease obligations		2.1		5.3		3.7		3.5		14.6
Operating lease obligations		1.3		1.4		.2		—		2.9
PURPA purchased power		91.8		187.7		192.6		2,425.8		2,897.9

Total	$	95.2	$	194.4	$	296.5	$	2,749.3	$	3,335.4

Credit Quality*	Amount
(In millions)
Investment grade	$	1,207.8
Non-investment grade		38.0
No external ratings:
Government agencies		16.4
Other		—

Total	$	1,262.2