Back to GetFilings.com

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, 2003

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  x    No  ¨

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:

Documents Incorporated by Reference

Portions of the Allegheny Energy, Inc. definitive Proxy Statement for its 2004 Annual Meeting of Stockholders are incorporated by reference to Part III of this Annual Report on Form 10-K.

GLOSSARY

CONTENTS

CONTENTS (cont’d.)

ii

CONTENTS (cont’d.)

iii

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

ITEM 1.    BUSINESS

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

AE’s operations are aligned into two segments:

The Generation and Marketing Segment

The following are our principal companies and operations in this segment:

During 2003, the Generation and Marketing segment had operating revenues of $977.5 million, net of intersegment eliminations, and a net loss of $(465.7 million). At December 31, 2003, the Generation and Marketing segment held $5,266.7 of assets. See Note 11 to the Consolidated Financial Statements.

Delivery and Services Segment

Our principal companies in this segment are:

2

During 2003, the Delivery and Services segment had operating revenues of $1,494.9 million, net of intersegment eliminations, and net income of $110.7 million. At December 31, 2003, the Delivery and Services segment held $4,542.0 of assets. See Note 11 to the Consolidated Financial Statements.

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 AE Supply employees at 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. These companies reimburse AESC at cost for services provided by AESC’s employees. AESC had approximately 5,150 employees as of December 31, 2003.

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 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. 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 under the Securities Exchange Act of 1934 (Exchange Act) are made 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

Allegheny historically functioned as an integrated regulated utility within its service area. In 1999, Allegheny began to separate its energy supply business from its T&D business in order to develop its supply business into a national energy merchant in domestic retail and wholesale markets. As of December 31, 2000, AE Supply owned or contractually controlled 6,609 MW of generating capacity. In 2001, AE Supply expanded its owned and controlled generating capacity by nearly one-third, or more than 3,500 MW, in markets transitioning to competition throughout the United States. This included AE Supply’s $1.1 billion acquisition of three natural gas-fired generating facilities with a total capacity of 1,710 MW in Illinois, Indiana and Tennessee. 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.

3

In March 2001, AE Supply acquired the energy trading division of Merrill Lynch & Co., Inc. (Merrill Lynch). The acquisition 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.

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 common equity to total capitalization decreased from 33.1 percent at December 31, 2000 to 26.8 percent at December 31, 2002. Allegheny’s common equity to total capitalization was 20.7 percent at December 31, 2003. As described below, Allegheny’s financing and other authorizations under PUHCA are subject to AE and AE Supply’s meeting minimum equity to total capitalization ratio requirements.

Allegheny’s former business model faced several challenges, including (1) decisions by federal regulators and regulators in various states served by the Distribution Companies to slow or cease moves toward deregulation, (2) limited liquidity in the wholesale energy market beginning in 2002, and (3) the decisions by several states to suspend their retail competition programs, delay the implementation of such programs or announce 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 Part 1. “Regulatory Framework Affecting Allegheny—State Legislation and Regulatory Developments,” below.

Rapid deterioration of the energy trading markets in 2002 required Allegheny to write-down the value of many of its energy trading positions, including those relating to the Western United States energy markets. In October 2002, AE’s and its subsidiaries’ credit ratings were downgraded to below investment grade, which triggered collateral calls by Allegheny’s trading partners. 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 the restructuring of Allegheny’s debt in February 2003. In September 2003, Allegheny sold its contract with the California Department of Water Resources (CDWR) and hedges associated with the contract. See “Allegheny’s Response,” below.

The marketplace rules affecting Allegheny also changed markedly beginning in 2002. In January 2002, the Federal Energy Regulatory Commission (FERC) authorized the Distribution Companies and PJM to proceed with broadening the scope and regional configuration of PJM to include the Distribution Companies, via an arrangement known as PJM West. With the addition of Allegheny’s 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 service 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 PJM’s transmission pricing methods. Nevertheless, 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. For a further discussion of the effect that the FERC’s policy has on the Allegheny companies, see Part 1. “Regulatory Framework Affecting Allegheny—Federal Regulation,” below.

4

Continuing Challenges

Allegheny’s liquidity issues continued through 2003 and into 2004. Allegheny considers 2004 to be a transition year as it refocuses on its core businesses, as further discussed under “Allegheny’s Response,” below. Difficult market conditions and the effect of Allegheny’s weakened credit profile had a continuing substantial adverse effect on 2003 operations. 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 28 percent, which is the level required under its key SEC financing authorizations. As of December 31, 2003, AE’s common equity ratio was 20.7 percent, and the common equity ratio at AE Supply was 19.2 percent.

As a result, AE and AE Supply have had to, and will continue to be required to, obtain special authorizations from the SEC to engage in financings, asset sales, and other activities. Absent such authorizations, Allegheny will have very limited flexibility to meet expected liquidity requirements or to address contingencies. During 2003, the common equity ratio fell below its previously projected level due to several factors. First, AE Supply had to take substantial write-downs in connection with recognized reductions in various energy market 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 AE Supply’s power contracts and the cancellation of suspended generation projects. Finally, Allegheny’s financial performance and cash flows in 2003 were 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 increased collateral postings. In addition, the 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.

In August 2002, Allegheny’s independent auditor, PricewaterhouseCoopers LLP (PwC), advised Allegheny that it considered Allegheny’s internal controls to have material weaknesses, principally relating to 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 timely its periodic reports on Form 10-K for 2002 and on Forms 10-Q for the third quarter of 2002 and the first three quarters of 2003. As of the date of this report, Allegheny has filed all of these reports with the SEC. In March 2004, PwC advised Allegheny that although management has made significant progress in addressing the specific control weaknesses previously identified, not all of these deficiencies have been remedied and certain internal control material weaknesses remain. Allegheny continues to address its internal control issues and expects to resolve these issues by the end of 2004. See Item 9A. “Controls and Procedures” and Note 2 to AE’s Consolidated Financial Statements, for further information.

Allegheny’s Response

Upon re-examining its business model and structure, Allegheny adopted a long-term strategy of focusing on the core generation and T&D businesses in which it has been historically engaged. Allegheny will seek, consistent with regulatory constraints, to manage its business lines as an integrated whole. Implementing this strategy has been 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:

5

Substantial Senior Management Changes

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

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.

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.

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.

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 October 13, 2003, Thomas R. Gardner was named Vice President, Controller, and Chief Accounting Officer. Prior to his appointment, Mr. Gardner was a partner with the audit and consulting firm of Deloitte & Touche LLP.

On October 13, 2003, David C. Benson was named President of AE Supply. Mr. Benson previously served as Executive Vice President of AE Supply and, prior to that, as Vice President, Production for AE Supply.

On October 13, 2003, Philip L. Goulding was named Vice President, Strategic Planning & Chief Commercial Officer. Prior to his appointment as Vice President, Mr. Goulding led the North American energy practice of L.E.K. Consulting.

Completion of Key Financing Transactions

Allegheny has completed several key financing transactions to improve its liquidity position.

2003 Short-Term Debt Refinancing of 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

6

$420 million of immediate liquidity. The Borrowing Facilities also extended short-term debt maturities. The terms of the Borrowing Facilities required AE and AE Supply to make substantial amortization payments in the fourth quarter of 2003, and required significant amortizations in 2004 and 2005. The Borrowing Facilities were refinanced in the 2004 Refinancing described below.

Private Placement. On July 24, 2003, Allegheny raised $291 million ($275 million after deducting various fees and placement agents’ commissions) from the issuance to Allegheny Capital Trust I (Capital Trust), 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. Capital Trust 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 Capital Trust’s payment obligations on the preferred securities. In accordance with generally accepted accounting principles, Allegheny’s consolidated balance sheet 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 New Loan Facilities described below.

2004 Refinancing. On March 8, 2004, AE and AE Supply entered into agreements (New Loan Facilities) with various credit providers to refinance and restructure the bulk of their bank debt. The New Loan Facilities provide AE Supply with a $750 million secured Term Loan B and a $500 million secured Term Loan C. The New Loan Facilities provide AE with a $200 million unsecured revolving credit facility and a $100 million unsecured term loan facility. The proceeds of the New Loan Facilities, together with cash held by AE and AE Supply, were used to refinance existing debt, including debt outstanding under the Borrowing Facilities and under outstanding letters of credit. The New Loan Facilities extended the maturities of, and lowered the interest rates on, AE and AE Supply’s outstanding bank debt and contain less stringent financial and other covenants than those contained in the Borrowing Facilities. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Executive Summary—First Quarter 2004 Liquidity Event,” below for additional information about the New Loan Facilities.

Exiting from Western Energy Markets

Allegheny worked through 2003 to accomplish AE Supply’s 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 the 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, AE Supply and its subsidiary, Allegheny Trading Finance Company, LLC (ATF) sold the CDWR contract and associated hedge transactions, to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc., for $354 million. Allegheny applied $214 million of the sale proceeds to required payments under agreements entered into to terminate tolling agreements with Williams Energy Marketing & Trading Company (Williams) and Las Vegas Cogeneration II, LLC (LV Cogen), a unit of Black Hills Corporation, as described below. The tolling agreements involving gas-fired generation controlled by Williams and LV Cogen were originally intended to hedge the CDWR contract and other power supply obligations then existing in Allegheny’s book of Western transactions. Allegheny will apply an additional $28 million of the proceeds to make required payments in March and September of 2004 under the agreement with

7

Williams. Approximately $26 million is being held in a pledged account for the benefit of AE Supply’s creditors. This arrangement was intended to enhance AE Supply’s ability to refinance the Borrowing Facilities. Approximately $71 million of the sale proceeds were placed in escrow for the benefit of J. Aron & Company, pending Allegheny’s fulfillment of certain post-closing requirements, primarily AE Supply providing a performance guarantee for ATF. On March 3, 2004, AE Supply issued this guarantee and the funds were released from escrow. Approximately $15 million of sale proceeds was used to partially offset certain of the hedges related to the CDWR contract and to pay fees and expenses associated with the transaction.

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

Allegheny’s remaining trading exposures in the Western power market were eliminated by the end of 2003.

Refocusing Trading Activities

Adoption of Asset-Based Trading Strategy. AE Supply has reoriented its trading operations from high-volume financial trading in national markets to asset optimization and hedging within markets near its generating facilities. Exiting the Western power markets, together with terminating or selling speculative trading positions in other energy markets, has enabled AE Supply to reduce the volatility associated with long-term trading-related cash outflows and collateral obligations. Since then, AE Supply has focused its efforts in PJM, the Midwest, and Mid-Atlantic markets with the primary objective of locking in cash flows associated with AE Supply’s portfolio of core physical generating assets and load obligations.

Relocation of Trading Operations. AE Supply moved its energy marketing operations from New York to Monroeville, Pennsylvania, on May 5, 2003 and reduced its staff in these operations. Ongoing operating cost saving and improvement in staff integration were achieved by the relocation. 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 continues to consider the sale of additional assets, especially non-core assets, including Mountaineer. Asset sales during 2002 and 2003 include the following:

Land Sales. Effective February 14, 2002, West Penn, through its subsidiary, The West Virginia Power & 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. In July 2003, the subsidiary of West Penn sold approximately 5,600 acres of land in Preston County, West Virginia to Allegheny Wood Products, Inc., which is not affiliated with Allegheny, for a net sales price of $9.6 million.

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.

8

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, for approximately $46.3 million in cash and a contingent amount of $5 million which was received on March 3, 2004 after satisfaction of certain post-closing obligations.

Restructuring and Cost-Reduction 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 on its core generating assets. The 540 MW combined-cycle generating plant in Springdale, Pennsylvania that commenced commercial operations on July 21, 2003 was the final sustained active new facility construction project in AE Supply’s pipeline. 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. During 2002, approximately 600 eligible employees accepted the ERO program, resulting in a charge of $82.6 million, before income taxes. In addition, Allegheny recorded a charge of $25.0 million, before income taxes, in 2002 relating to approximately 80 other employees whose positions had been eliminated. Allegheny substantially completed these planned workforce reductions in 2002.

Suspension of Dividend. The Board of Directors of AE did not declare a dividend on AE’s common stock for the fourth quarter of 2002. Covenants contained in Allegheny’s financing documents, 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 its independent auditors and other outside professional service firms. As previously discussed under Substantial Senior Management Changes above, Allegheny also hired a new corporate controller and other accounting professionals. Allegheny continues to address its controls environment and reporting procedures and expects to be in timely compliance with new requirements relating to internal controls mandated by the Sarbanes-Oxley Act of 2002. See Item 9A. “Controls and Procedures” and Note 2 to AE’s Consolidated Financial Statements, for a detailed discussion.

9

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:

10

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 OUR SUBSTANTIAL INDEBTEDNESS

Our substantial indebtedness could adversely affect our and our subsidiaries’ ability to operate successfully and meet contractual obligations.

Allegheny is substantially leveraged. One of our principal challenges is to manage our indebtedness while beginning the long-term process of reducing the amount of debt. At December 31, 2003, our consolidated indebtedness was approximately $5.7 billion. Approximately $3.2 billion of that indebtedness represented obligations of AE Supply and AGC, and the remainder constituted indebtedness of AE or one or more of the Distribution Companies. See AE’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a discussion of the principal components of our indebtedness.

Our substantial indebtedness could have important consequences to Allegheny. For example, it could:

11

Allegheny will have substantial debt service obligations for the foreseeable future and may need to engage in successive refinancing and capital-raising transactions in order to manage obligations to pay interest and retire principal. See AE’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Requirements,” for a schedule of Allegheny’s contractual payment obligations.

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

The New Loan Facilities, the indenture governing the 11 ⁷/8% Notes and the indenture governing the amended A-Notes and the amended B-Notes, issued in connection with the St. Joseph generating facility (collectively, the “Amended Notes”), contain restrictive covenants that limit the ability of AE and its subsidiaries and AE Supply and its subsidiaries to, among other things:

AGC’s indenture also restricts secured borrowings by AGC.

AE Supply has pledged its assets to secure its obligations under the New Loan Facilities and the A-Notes. The New Loan Facilities and the indentures governing the amended A-Notes and the 11 ⁷/8% Notes limit our ability to make strategic decisions. Covenant restrictions limit our ability to access capital markets or sell assets without using the proceeds to reduce indebtedness. These obligations could limit our ability to make capital expenditures, both for added capacity and existing facilities.

In addition, AE and AE Supply are required to meet certain financial tests under the New Loan Facilities, including an interest coverage ratio and a leverage ratio. A failure by AE or AE Supply to comply with the covenants contained in the New Loan Facilities could result in an event of default which could materially and adversely affect our financial condition.

Our substantial variable-rate indebtedness exposes us to interest rate risk.

Allegheny’s indebtedness under the New Loan Facilities, Monongahela Credit Facility and certain other indebtedness accrues interest at variable rates based on prevailing interest rates. If interest rates rise, we will be required to meet higher debt service obligations. If our operational cash flows do not increase with interest rate increases or are otherwise insufficient to cover our interest payment obligations, we may have difficulty meeting our debt service obligations.

Our liquidity position adversely affects our operations.

Our lack of liquidity may make it difficult for AE Supply to derive the maximum value from energy it produces in excess of its PLR obligations to the Distribution Companies under long-term power supply contracts, thereby reducing revenues realizable from operations. In addition, our liquidity position could adversely impact our ability to fund capital expenditures to maintain or improve plant reliability and to meet environmental and other governmental mandates.

12

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 and site remediation. Compliance with these legal requirements may require us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees, and permits at all of our facilities. Our liquidity position could adversely affect our ability to meet capital expenditure requirements above budgeted estimates.

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. If stricter requirements are imposed or if the costs ultimately incurred exceed amounts budgeted for such expenditures, our capital resources may be significantly pressured. Our projected capital expenditures are subject to significant increase due to factors beyond our control. 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.

Future regulations may also seek to reduce greenhouse gasses or other emissions, which would significantly affect the energy industry. 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 our compliance expenditures or accelerate the timing of the capital portion of those expenditures.

The status of our facilities’ compliance with the Clean Air Act is subject to uncertainty due to the EPA’s New Source Review initiatives.

Applicable standards under the EPA’s New Source Review (NSR) initiatives are in flux. Under the Clean Air Act of 1970 (Clean Air Act), major modification of certain existing emission sources (rather than performance of routine maintenance) could subject our existing facilities to the 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 emissions sources in connection with work believed by the companies to be routine maintenance under the statute and rules regulating emissions of nitrogen oxide (NO_x) and sulfur dioxide (SO₂) from coal-burning plants. The EPA has requested information from AE in connection with this NSR initiative.

The future of NSR regulation and its effect on ongoing enforcement and investigations is not clear. A recent judicial decision involving the EPA’s NSR initiative and 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, including Allegheny. However, the recent preliminary judicial decision in a case involving Duke Energy, and the final Routine Maintenance, Repair and Replacement (RMRR) rule recently released by the EPA, are more consistent with the energy industry’s historical compliance approach. Fourteen states and various other government and private groups have filed suit challenging the issuance of the RMRR. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the RMRR. The rule was scheduled to go into effect on December 26, 2003. The stay delays implementation of the rule until the case is decided. No assurance can be given that the RMRR will be upheld by the courts or with respect to its effect on any ongoing enforcement and investigations under the old NSR regulations as interpreted by the EPA.

13

Risks inherent in the process of obtaining required environmental approvals could adversely affect our ability to operate our facilities.

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 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 mandated 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 and write-downs.

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

Our failure to comply with environmental laws and regulations, even if caused by factors beyond our control, 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 Clean Air Act Amendment of 1990 (CAAA). If these actions are filed and ultimately resolved against us, substantial and expensive 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 NSR 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, often under terms requiring significant new capital expenditures for additional pollution control equipment.

We could incur additional substantial liabilities for environmental remediation.

Like other companies engaged in power generation, transmission and distribution, our operations involve the handling and use of hazardous materials and the generation of large volumes of waste. 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 Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the “Superfund” law, that can impose liability for the entire cost of cleaning up a site, regardless of fault, upon any one of a number of 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 investigation and remediation in the future if contamination is discovered or if operations cease at a facility.

We may undertake future asset sales. As part of any sale, we intend to transfer future environmental liability to the new owner. However, prospective purchasers may refuse to assume all liabilities and it is also 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.

14

RISKS ASSOCIATED WITH THE CAPITAL INTENSIVE NATURE OF OUR BUSINESS

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

The operation of power generation facilities involves many risks, including the risk of breakdown or failure of equipment, fuel interruption, and performance below expected levels of output, performance or efficiency. If our facilities operate below expectations, we may lose revenues or have increased expenses, including replacement power costs. See “Allegheny’s Sales and Revenues—Electric Facilities,” for a discussion of recent outages at our facilities at Hatfield’s Ferry, Pennsylvania and Pleasants, West Virginia. Many of our facilities were originally constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures, above budgeted amounts, to keep operating at peak efficiency or availability and is likely to require periodic upgrades and improvement.

If we underestimate required maintenance expenditures, or are unable to meet required capital expenditure levels due to liquidity constraints, 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 obligate us to purchase power from third parties to meet our supply obligations.

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

Much of the value of our business consists of our portfolio of unique power generation and transmission and distribution 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 accidents or 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.

RISKS RELATED TO OUR LIQUIDITY POSITION AND LIQUIDITY ENHANCEMENT EFFORTS

As part of our plan to improve our liquidity, we may engage in further sales of assets and businesses, however, market conditions and other factors limit the feasibility of this strategy.

We may seek to sell additional assets and 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 these assets and businesses. Asset sales under such conditions could result in the incurrence of substantial losses. Buyers may also find it difficult to obtain financing to purchase salable assets.

Several factors specific to us have rendered asset sales particularly challenging. We are subject to constraints under the Public Utility Holding Company Act of 1935, as amended (PUHCA), 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 significant delays or uncertainties in the transaction process.

Further asset sale activity would expose us to attendant risks and liabilities.

Risks commonly encountered in connection with asset sale activity include:

15

We may be unable to timely engage in desired financing transactions.

Our liquidity strategy may include periodic equity and other financing transactions in order to meet amortization obligations and to increase Allegheny’s equity ratios. We may be unable to successfully access the capital markets for a variety of reasons including:

If we are unable to access the capital markets to meet our anticipated financing needs, we will need to raise funds through a combination of additional borrowings, asset sales and operations. No assurance can be given that we will be able to generate sufficient funds to meet our projected liquidity needs on a timely basis, acceptable terms, or at all.

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

Covenants contained in the agreements governing the New Loan Facilities, the 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 will apply significant cash in future periods to satisfy estimated pension plan liabilities.

Our under-funded pension liabilities have increased in recent periods due to declining interest rates and financial market performance, and because of our implementation of early retirement initiatives to reduce headcount. As of December 31, 2003, our current under-funded pension liability was $339.6 million, and our pension liabilities may increase if our assumptions regarding investment performance or prevailing interest rates change or if actual investments underperform expectations. We intend to apply cash in future periods to reduce our outstanding under-funded pension liability, and cash so applied will be unavailable for other uses.

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

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

In July 2002, as part of our cost-saving efforts, we announced our intent to reduce our consolidated workforce by approximately 10 percent. As part of this initiative, we achieved workforce reductions through a voluntary early retirement option program, selected staff reductions and a Staffing Reduction Separation Program, which collectively resulted in substantial charges to earnings. The reorganization of our energy trading division included the relocation of the trading operations and resulted in a charge to earnings related to costs associated with the relocation. We may undertake further efforts of this nature. In pursuing this strategy, we have incurred and could incur in the future risks commonly encountered in connection with such a strategy.

16

RISKS RELATED TO TRADING MARKET EXPOSURES

Our credit ratings and trading market liquidity render it difficult for us to hedge our physical power supply commitments and resource requirements.

Our current credit ratings, together with a lack of market liquidity, particularly in long-term electricity and natural gas markets, has rendered it difficult for us to retire unnecessary energy market positions entered into in connection with our prior business model. Market liquidity has significantly declined over the past two years. Absent a return to more liquid levels combined with an improvement in our credit ratings, it may not be possible for us to retire unnecessary positions.

Our credit position has also rendered it difficult for us to hedge our power supply obligations and fuel requirements. In the absence of effective hedges for these purposes, we must satisfy power and fuel shortfalls in the spot markets, which are volatile and can be more costly than expected.

Our risk management, wholesale marketing, fuel procurement and energy trading activities, including our decisions to enter into power sales or purchase 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 RELATED TO OUR INTERNAL CONTROLS

AND PROCEDURES AND REFOCUSING OUR BUSINESS

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

In August 2002, AE and its independent auditors recognized that the internal controls and procedures of AE and its subsidiaries had material weaknesses. The term “material weakness” refers to an organization’s internal control deficiency in which the design or operation of a component of internal control does not reduce to a relatively low level the risk that a material misstatement may be contained in the organization’s financial statements. These material weaknesses and related accounting errors led to delays in the production of annual financial statements for 2002 and for quarterly periods of 2002 and 2003. These delays in turn led to delays in our filing of annual and quarterly reports under the Exchange Act and under agreements governing our indebtedness, which resulted in technical defaults under certain debt agreements. As of January 23, 2004, we are current in our Exchange Act reporting obligations. We have implemented measures to improve and augment our internal controls and procedures, including enhancement of systems, processes, policies, procedures and controls. However, certain material weaknesses remain. Our auditors have advised us of material weaknesses noted during their audit of our 2003 financial statements. See Item 9A. “Controls and Procedures.”

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

17

identifying incipient strategic and oversight issues. In some areas, adequate automated control systems are not in place, and we therefore will need to devote personnel resources to account verification and reconciliation. The use of temporary augmented controls and procedures and the installation of new systems have resulted in significant additional costs. Management continues to focus on remedying internal control deficiencies, with a goal of correcting them by the end of 2004.

We have applied substantial resources at all relevant managerial levels toward the task of improving our internal control environment. These efforts, in which we have involved several external professional service firms, continue. In addition, we need to hire additional employees and train existing employees to fill positions currently serviced by external professional service firms. 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. If our efforts are not successful, we could experience further reporting deficiencies and be unable to comply on a timely basis with the requirements relating to internal controls set forth in the Sarbanes-Oxley Act of 2002.

Refocusing our business subjects us to risks and uncertainties.

Commencing in the second half of 2002 and continuing through 2003, management reassessed our position within the energy industry, the business environment, and our relative strengths and weaknesses. As a result of this reassessment, management implemented significant changes to our operations as management reorients Allegheny to function as an integrated utility company, to the extent practicable and permissible under relevant regulatory constraints. For example, we have reoriented our trading operations, reduced the size of our workforce, sold assets, closed our positions in Western energy markets and engaged in significant financing transactions, among other changes. In addition, substantial changes have been made to our senior management. Our circumstances in 2002 represented a substantial transformation from our historical role as a component of an integrated utility business. Current and previous changes in our business model were prompted by internal decision making and by the changing regulatory and market environments.

We continue to be in a state of transition, and additional changes to our business are being and will be considered from time to time as management seeks to carry out our new strategy. These transitions have been, and will be, unavoidably disruptive to our established organizational culture and systems. In addition, consideration and planning of strategic changes diverts management attention from day-to-day operations. There can be no assurance that we will ultimately be successful in transitioning our business model.

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.

We are involved in several suits seeking substantial damage awards against us. Among these suits are 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. 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. Further information regarding these legal proceedings, as well as other matters, is provided under Item 3. “Legal Proceedings.”

18

We are involved in shareholder suits and other litigation and are a subject of agency inquiries, including 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 past subpoenas from the SEC and Commodity Futures Trading Commission (CFTC) directed to us. The SEC has recently requested that AE voluntarily produce certain documents in connection with an informal investigation of AE and its subsidiaries. Many of these documents were previously provided in response to subpoenas that AE received in 2002. AE is cooperating fully with the SEC. We cannot predict the ultimate outcome or effect of these matters. See Item 3. “Legal Proceedings.”

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 Allegheny that would claim exposure to asbestos or other hazardous substances.

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. Demand for electricity peaks during the summer and winter months and market prices also peak during these times in our markets. During periods of peak demand, the capacity of our generating facilities may be inadequate, which could require us to purchase power at a time when the market price for power is very high. Also, our annual results and liquidity position may depend disproportionately on our performance during the winter and summer.

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

The energy sector has 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 and its affiliates in a favorable light and may cause Allegheny to be susceptible to adverse outcomes with respect to decisions by such bodies. The power outages that affected the Northeast and Midwest United States and Canada in August 2003 could exacerbate negative sentiment regarding the energy industry.

19

RISKS ASSOCIATED WITH REGULATION

We are regulated under PUHCA, which constrains our ability to engage in financing transactions and asset sales, limits subsidiary dividends, and could impede AE from providing financial support to AE Supply.

AE and its subsidiaries are subject to regulation under PUHCA. PUHCA limits the dividends that subsidiaries may pay from undistributed surplus. In addition, PUHCA requires that we obtain prior approval from the SEC in order to incur indebtedness or issue equity, purchase or sell utility assets, or merge or consolidate with other companies. PUHCA also constrains AE’s ability to make equity contributions to AE Supply and enter into financing transactions for AE Supply’s benefit. 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.

We may be subject to conflicting regulatory policies that may adversely affect our ability to participate fully in competitive power markets. Moreover, these regulatory policies are continuing to evolve as a result of various legislative and regulatory initiatives regarding deregulation, regulation, or restructuring of the energy industry, including deregulation of the production and sales of electricity. We may also see additional regulatory action taken by state or federal regulators as a result of the August 14, 2003 blackout. Any such new requirements could lead to increased operating expenses and capital expenditures, which cannot be predicted at this time.

One of the most significant risks we face is choosing the correct business strategy to respond to evolving state policies regarding retail rate regulation. Compulsory continuation of retail rate caps beyond the original scheduled end of transition periods could have adverse consequences for the Distribution Companies. In the absence of a long-term power supply contract with a power generator, the Distribution Companies’ power requirements must be purchased at negotiated or market prices, whether from AE Supply or an alternative supplier. If retail rates are capped below the level at which power can be procured on the market, the power will be sold at a loss. Legislators, regulators and consumer and other groups have sought to extend retail rate-regulation in the states in which the Distribution Companies do business through a variety of mechanisms, including through the extension of the current rate cap regimes. We cannot predict to what extent these efforts will be successful. Allegheny believes that the previously approved transfer of certain generating assets to AE Supply, which is a FERC-regulated company, establishes significant impediments to direct state re-regulation of AE Supply’s generation assets. 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.

20

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 adopted by the FERC, we cannot predict whether they will actually receive these incentives or other incentives that may become available. Moreover, if we do receive such incentives, they may not be fully recoverable due to state retail rate freezes, or other factors.

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

In order to comply with the FERC requirements designed to open access to the transmission network, 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 a surcharge 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, or after the transition period. For a further discussion of the financial impact of our participation in PJM, see “Allegheny’s Competitive Actions—The Delivery and Services Segment—Distribution Companies—Participation in RTOs,” below.

The FERC’s efforts to create and expand large Regional Transmission Organizations 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. The purpose of this policy is to promote generation competition within and between RTOs in certain regions. 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 large 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 regional 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 that 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 “Allegheny’s Competitive Actions—The Delivery and Services Segment—Distribution Companies—Participation in RTOs,” below.

In addition, expanding PJM may increase opportunities for AE Supply to sell its output 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

21

repeal retail access programs. It is also possible that inefficiencies may emerge as markets expand that may impair our ability to compete. For a further discussion, see “Regulatory Framework Affecting Allegheny—Federal Legislation, Competition, and RTOs,” below.

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

PJM uses a locational marginal pricing (LMP) method to price both generation and end-use customer demand at a particular time and location on the electricity transmission network. LMP recognizes that the marginal price of electricity may be different at different locations on the system and at different times. Differences in prices between two locations in the region at the same time reflect physical limitations in the transmission lines to move power across the system. These limits are referred to as transmission congestion. In concept, when there is enough transmission capacity to get power from the cheapest source of generation to all potential buyers on the system, there is no congestion and there would be only one price throughout the region. When there is congestion, such as may occur on a hot summer day, the most economical generators may not be able to reach all of their potential buyers. Allegheny may incur increased costs associated with such congestion if it cannot adequately hedge this exposure under the terms of PJM’s FERC-approved tariff.

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. Allegheny may incur increased costs associated with such congestion if it cannot adequately hedge this exposure under the terms of PJM’s FERC-approved tariff.

RISKS 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 AE Supply with adequate transmission capacity, it may not be able to deliver wholesale electric power to its customers.

AE Supply depends on power transmission and distribution facilities owned and operated by utilities and power companies to deliver its electricity output. Certain of these facilities are owned by subsidiaries of AE and others are owned by third parties. AE Supply’s dependence on these facilities and the companies that own them exposes it 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 output. 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 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 and Midwest United States and Canada in August 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.

22

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 wholesale market prices 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 Item 1. “Business, 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. In addition, unscheduled outages at AE Supply’s generating facilities, such as the current outages at the Hatfield’s Ferry and Pleasants power stations could cause a shortage of available capacity. See Item 1. “Business—Electric Facilities,” for a discussion of recent outages of our facilities at Hatfield’s Ferry, Pennsylvania and Pleasants, West Virginia.

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 or increased environmental compliance costs, AE Supply would have to absorb the difference. Similarly, if AE Supply is required to purchase power to meet its 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 Item 1. “Business—Regulatory Framework Affecting Allegheny—State Legislation and Regulatory Developments,” below.

23

ALLEGHENY’S SALES AND REVENUES

Allegheny’s revenues are derived primarily from generation and marketing and delivery and services, which include, regulated electric sales and revenues, regulated natural gas sales and revenues, and unregulated services revenues and other revenues.

Regulated natural gas revenues totaled $268.8 million, $221.6 million, and $235.1 million in 2003, 2002, and 2001, respectively. Unregulated services revenues totaled $38.1 million, $643.5 million, and $139.5 million in 2003, 2002, and 2001, 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 Operating Revenues

The Generation and Marketing segment’s operating revenues increased as a result of increased affiliate sales to the Distribution Companies, increased PLR obligations and lower purchased energy and transmission costs, offset by increased aggregate net realized and unrealized losses (collectively, trading losses) at AE Supply.

The Delivery and Services Segment

Regulated Electric Sales and Revenues

The all-time Peak Load for the Distribution Companies was 8,437 MW on January 23, 2003. Peak Load refers to the maximum one time demand (MW) on the system.

Allegheny’s 2003 regulated electric revenues were derived as follows: Pennsylvania, 42.8 percent; West Virginia, 28.9 percent; Maryland, 19.6 percent; Virginia, 6.1 percent; and Ohio, 2.6 percent. Allegheny’s 2003 regulated electric revenues were derived from: residential customers, 42.8 percent; commercial customers, 23.8 percent; industrial customers, 32.3 percent; and wholesale and other customers, 1.1 percent.

24

Monongahela’s regulated KWh sales increased 0.2 percent from 2002 to 2003 as a result of an increase of 0.7 percent and 0.8 percent in commercial and industrial, and decreases of 0.6 percent and 11.9 percent in residential and wholesale and other sales, respectively. Monongahela’s regulated electric revenues increased 0.4 percent from 2002 to 2003 as a result of increases of 0.3 percent, and 1.7 percent, and 10.9 percent in commercial, industrial and wholesale and other revenues, respectively, and a decrease of 0.9 percent in residential revenues.

Monongahela’s all-time Peak Load was 2,080 MW on July 22, 2002. Monongahela’s 2003 Peak Load was 2,049 MW on August 21, 2003.

Monongahela’s 2003 regulated electric revenues represented 24.7 percent of Allegheny’s 2003 regulated electric revenues. Monongahela’s 2003 regulated electric revenues were derived as follows: West Virginia, 89.5 percent, and Ohio, 10.5 percent. Monongahela’s 2003 regulated electric revenues were derived from: residential customers, 39.3 percent; commercial customers, 23.9 percent; industrial customers, 35.8 percent; and wholesale and other customers, 1.0 percent.

Potomac Edison’s regulated KWh sales increased 1.4 percent from 2002 to 2003 as a result of increases of 6.2 percent, 2.6 percent, and 2.4 percent in residential, commercial, and industrial sales, respectively, and a decrease of 50.4 percent in wholesale and other sales. Potomac Edison’s regulated electric revenues increased 4.7 percent from 2002 to 2003 as a result of increases of 5.7 percent, 1.9 percent, and 6.9 percent in residential, commercial, and industrial revenues, respectively, and a decrease of 22.8 percent in wholesale and other revenues.

Potomac Edison’s all-time Peak Load was 3,095 MW on January 16, 2004.

Potomac Edison’s 2003 regulated electric revenues represented 32.5 percent of Allegheny’s 2003 regulated electric revenues. Potomac Edison’s 2003 electric revenues were derived as follows: Maryland, 60.4 percent; West Virginia, 20.9 percent; and Virginia, 18.7 percent. Potomac Edison’s 2003 regulated electric revenues were derived from: residential customers, 46.4 percent; commercial customers, 22.5 percent; industrial customers, 29.5 percent; and wholesale and other customers, 1.6 percent. Potomac Edison’s regulated electric revenues from one industrial customer, the Eastalco Aluminum Company (Eastalco) near Frederick, Maryland, totaled more than ten percent of its total regulated electric revenues, and represented 19.5 percent of its 2003 MWh sales to customers.

West Penn’s regulated KWh sales decreased 2.6 percent from 2002 to 2003 as a result of increases of 2.7 percent, and 0.3 percent in residential and commercial sales, respectively, and decreases of 2.7 percent and 82.5 percent in industrial and wholesale and other sales, respectively. West Penn’s regulated electric revenues decreased 1.0 percent from 2002 to 2003 as a result of increases of 1.8 percent and 0.3 percent in residential and commercial revenues, respectively, and decreases of 2.7 percent and 83.7 percent in industrial revenues and wholesale and other revenues, respectively.

West Penn’s all-time Peak Load was 3,677 MW on August 6, 2001. West Penn’s 2003 Peak Load was 3,470 MW on January 23, 2003.

West Penn’s 2003 regulated electric revenues represented 42.8 percent of Allegheny’s 2003 regulated electric revenues. All of West Penn’s 2003 regulated electric revenues were derived from Pennsylvania. West Penn’s 2003 regulated electric revenues were derived from: residential customers, 42.1 percent; commercial customers, 24.7 percent; industrial customers, 32.4 percent; and wholesale and other customers, 0.8 percent.

25

Regulated Natural Gas Sales and Revenues

West Virginia Power (WVP) and Mountaineer accounted for 4.6 percent and 95.4 percent of total regulated Bcf sales, respectively. Mountaineer accounted for all transportation sales. All of Allegheny’s 2003 regulated natural gas revenues were derived from West Virginia.

Unregulated Services Revenues

Allegheny’s unregulated services revenues decreased 94.1 percent from 2002 to 2003, as a result of the sale of Fellon-McCord and Alliance Energy Services, LLC on December 31, 2002.

Other Revenues

Intersegment Eliminations

26

CONSTRUCTION AND OTHER CAPITAL EXPENDITURES

The table below shows construction and environmental control expenditures for Allegheny in 2003 and estimated expenditures for 2004 and 2005.

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. During 2003, the Generation and Marketing segment completed construction of a 540 MW combined-cycle generating plant in Springdale, Pennsylvania. Commercial operation of the facility began on July 21, 2003. This combined-cycle facility includes two natural gas-fired combustion turbines and one steam turbine. The Delivery and Services segment’s construction expenditures include projects to upgrade distribution lines and substations, as well as, transmission and subtransmission systems enhancements.

27

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. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 8. “Financial Statements and Supplementary Data”—Note 6 for information regarding charges for discontinued generating projects.

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

ELECTRIC FACILITIES

All of the generating capacity is part of the Generation and Marketing segment and either owned or controlled 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. The Bath County Station uses reversible pumping/generating equipment to raise 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 with the pumping/generating equipment operating in reverse mode.

AE’s and AE Supply’s owned capacity (including AGC) as of December 31, 2003 totaled 9,381 MW, of which 5,923 MW (63.1 percent) are coal-fired, 2,579 MW (27.5 percent) are natural gas-fired, 797 MW (8.5 percent) are pumped-storage and hydroelectric, and 82 MW (0.9 percent) are oil-fired.

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 3.5 percent interests, 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 on March 12, 2006.

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

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

28

The following table shows nominal maximum operational generating capacity owned by Allegheny, or acquired under the Public Utility Regulatory Policies Act of 1978 (PURPA) contracts as of December 31, 2003:

ALLEGHENY STATIONS

(as of December 31, 2003)

Nominal Maximum Operational Generating Capacity (MW)

29

PURPA GENERATION (j)

Nominal Maximum Operational Generating Capacity (MW)