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U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

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Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) have been subject to such filing requirements for the past 90 days.    Yes  ¨    No  x

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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

Securities registered pursuant to Section 12(b) of the Act:

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GLOSSARY

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CONTENTS

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CONTENTS (cont’d.)

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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.

PART I

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).

In 2002, AE aligned its businesses into two segments:

The Generation and Marketing Segment

Our principal companies and operations in this segment are:

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.

The Delivery and Services Segment

Our principal companies in this segment are:

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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.

Generation and Marketing Segment

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.

Delivery and Services Segment

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.

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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.

Intersegment Services

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.

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Where You Can Find More Information

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.

RECENT EVENTS

Previous Business Model

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

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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.

Challenges Arising in 2002

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.

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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

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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.

Continuing Challenges

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.

Allegheny’s Response

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

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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:

Substantial Senior Management Changes

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.

Completion of Key Financing Transactions

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

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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 11 ⁷/8% 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 11 ⁷/8% 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.

Exiting from Western 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 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.

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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.

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 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.)

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 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.

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Restructuring and Cost-Reducing Initiatives

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.

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 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.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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:

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RISK FACTORS

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.

RISKS RELATED TO TRADING MARKET EXPOSURES

Our cash position is highly vulnerable to market volatility.

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.

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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 trading portfolio exposes us to counterparty credit risks.

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.

RISKS ASSOCIATED WITH OUR CAPITAL STRUCTURE

AND CAPITAL REQUIREMENTS

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.

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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:

1.    Facilities at AE Supply:

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2.    Facilities at AE and its subsidiaries, other than AE Supply:

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 11 ⁷/8 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:

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AGC’s indenture also restricts additional secured borrowings.

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

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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 terms of the Borrowing Facilities expose us to interest rate risk.

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.

Our liquidity position adversely affects our operations.

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.

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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.

AE cannot pay dividends on its common stock for the foreseeable future.

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.

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

We have undertaken various restructuring and cost-cutting efforts, including:

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.

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RISKS RELATED TO OUR INTERNAL CONTROLS AND

PROCEDURES AND TO OUR BUSINESS MODEL TRANSITION

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.

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RISKS ASSOCIATED WITH COMPETITION

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.

OTHER RISKS ASSOCIATED WITH OUR BUSINESS

Seasonal fluctuations pressure our facilities and operating results.

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.

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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.

RISKS ASSOCIATED WITH REGULATION

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

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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.

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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.

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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.

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RISKS ASSOCIATED WITH THE CAPITAL-INTENSIVE

NATURE OF OUR BUSINESS

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.

RISKS RELATED TO LEGAL PROCEEDINGS

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.

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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.

Our Borrowing Facilities limit our ability to settle litigation.

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.

RISK RELATED TO OUR RELIANCE ON OTHER COMPANIES

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.

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RISKS ASSOCIATED WITH ENVIRONMENTAL REGULATION

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

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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.

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ALLEGHENY’S SALES AND REVENUES

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.

The Generation and Marketing Segment

Generation and Marketing 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.

The Delivery and Services Segment

Regulated Electric Sales and Revenues

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,

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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 all-time Peak Load was 2,080 MW on July 22, 2002.

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.

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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).

Regulated Natural Gas Sales and Revenues

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.

Unregulated Services Revenues

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.

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CONSTRUCTION AND OTHER CAPITAL EXPENDITURES

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.

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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.

Recently Completed 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.

Discontinued Projects

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.

The Delivery and Services Segment

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.

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ELECTRIC FACILITIES

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.

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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:

ALLEGHENY STATIONS

(as of December 31, 2002)

Maximum Generating Capacity (MW) (a)

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PURPA GENERATION (j)

Maximum Generating Capacity (MW)