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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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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  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 2005 Annual Meeting of Stockholders are incorporated by reference to Part III of this Annual Report on Form 10-K.

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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., MONONGAHELA POWER COMPANY, THE POTOMAC EDISON COMPANY AND ALLEGHENY GENERATING COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY THE REGISTRANT ON ITS OWN BEHALF. NONE OF THE REGISTRANTS MAKES ANY REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.

PART I

ITEM 1.    BUSINESS

Overview

Allegheny is an integrated energy business that owns and operates electric generation facilities and delivers electric and natural gas services to customers in Pennsylvania, West Virginia, Maryland, Virginia and Ohio. AE, Allegheny’s parent holding company, was incorporated in Maryland in 1925 and is registered as a holding company under PUHCA. Allegheny operates its business primarily through AE’s various directly and indirectly owned subsidiaries.

Allegheny has two business segments:

The Delivery and Services Segment

The principal companies and operations in AE’s Delivery and Services segment include the following:

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The Distribution Companies assess delivery charges when other power suppliers transmit power along the Distribution Companies’ transmission grids. In April 2002, the Distribution Companies transferred operational control over their transmission systems to PJM. See “The PJM Market and the Distribution Companies’ PLR Obligations” below.

During 2004, the Delivery and Services segment had operating revenues of $2,764.1 million and net income of $103.3 million. At December 31, 2004, the Delivery and Services segment held $4.4 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 12, “Business Segments,” to the Consolidated Financial Statements.

The Generation and Marketing Segment

The principal companies and operations in AE’s Generation and Marketing segment include the following:

AE Supply is obligated under long-term contracts to provide the Distribution Companies with the power that they need to meet a majority of their PLR obligations. The Generation and Marketing segment sells power into PJM and purchases power from PJM to meet its obligations to the Distribution Companies under these contracts. See “The PJM Market and the Distribution Companies’ PLR Obligations” below.

Although most of the Generation and Marketing segment’s generation capacity participates in the PJM system, it owns generation capacity outside of PJM, including AGC’s interest in the Bath County generation station and generation facilities in Gleason, Tennessee and Wheatland, Indiana. The Gleason and Wheatland generation facilities have been classified as held for sale, and their results have been presented as discontinued operations in the accompanying Consolidated Statements of Operations.

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During 2004, the Generation and Marketing segment had operating revenues of $1,538.7 million and a net loss of $413.9 million. At December 31, 2004, the Generation and Marketing segment held $4.4 billion of identifiable assets. See “Managements Discussion and Analysis of Financial Condition and Results of Operations” and Note 12, “Business Segments,” to the Consolidated Financial Statements.

Intersegment Services

AESC was incorporated in Maryland in 1963 as a service company for AE. AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures and their respective subsidiaries have no employees. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had approximately 5,100 employees as of December 31, 2004.

The PJM Market and the Distribution Companies’ PLR Obligations

Allegheny’s business has been significantly influenced by state and federal deregulation initiatives, including the implementation of retail choice and plans to transition from cost-based to market-based rates, as well as by the development of wholesale electricity markets and RTOs, particularly PJM.

The Distribution Companies have PLR obligations to their customers in Pennsylvania, Maryland, Virginia and Ohio. AE Supply has long-term contracts with the Distribution Companies under which AE Supply provides the Distribution Companies with the majority of the power necessary to meet their PLR obligations. A majority of Allegheny’s generation assets participate in the PJM system, and most of the power that the Generation and Marketing segment generates is sold into PJM. Allegheny expects to sell power in excess of the Distribution Companies’ PLR obligations at market prices. Prevailing market prices are generally higher than the capped rates currently applicable to these PLR obligations.

For a more detailed discussion, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview.”

Challenges and Response

Prior to 1999, Allegheny functioned as an integrated regulated utility within its service area. In response to federal and state deregulation initiatives, however, Allegheny separated its energy generation business from its T&D business by transferring generation assets to AE Supply. Allegheny’s former senior management sought to transform AE Supply into a national power merchant in order to capitalize on these regulatory and other energy industry trends. As part of this strategy, AE Supply acquired generation assets, which collectively expanded Allegheny’s owned or controlled generation capacity by nearly one-third. AE Supply also began construction of new generation facilities. In addition, AE Supply purchased the energy trading division of Merrill Lynch in 2001. With this acquisition, the focus of AE Supply’s energy trading shifted from asset backed, short-term trading in and around its generation assets to more speculative trading activities. This expansion was financed primarily through debt.

Beginning in 2002, difficult market conditions, changes in the regulatory environment and Allegheny’s worsening credit profile placed Allegheny in a weakened financial position, which continued during 2003 and into 2004. Beginning in 2003, Allegheny’s new senior management implemented recovery plans and new long-term strategies.

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Allegheny’s long-term strategy is to focus on its core generation and T&D businesses. Allegheny’s management believes that this emphasis will enable Allegheny to take advantage of its regional presence, operational expertise and knowledge of its markets. Specific goals for enhancing long-term value include:

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Where You Can Find More Information

AE, Monongahela, Potomac Edison 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 with or to the SEC. You may read and copy any document that the registrants file with the SEC at the SEC’s public reference room 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 room. These SEC filings are also available to the public from the SEC’s website 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, statements of changes in beneficial ownership and other SEC filings, and any amendments to those reports, that AE, Monongahela, Potomac Edison and AGC file with or furnish to the SEC under the Exchange Act are made available free of charge on AE’s website at http://www.alleghenyenergy.com as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. Audited annual financial statements for AE Supply and West Penn, neither of which is a reporting company under the Exchange Act, also will be available on AE’s website. AE’s website and the information contained therein are not incorporated into this report.

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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 differ materially 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

Allegheny is subject to a variety of significant risks in addition to the matters set forth under “Special Note Regarding Forward-Looking Statements” above. Allegheny’s susceptibility to certain risks could exacerbate other risks. These risk factors should be considered carefully in evaluating Allegheny’s risk profile. Risks applicable to Allegheny include:

Risks Relating to Regulation

Allegheny is subject to substantial governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits and certificates may result in substantial costs to Allegheny.

Allegheny is subject to substantial regulation from federal, state and local regulatory agencies. Allegheny is required to comply with numerous laws and regulations and to obtain numerous authorizations, permits, approvals and certificates from governmental agencies. These agencies regulate various aspects of Allegheny’s business, including customer rates, service regulations, retail service territories, generation plant operations, sales of securities, asset sales and accounting policies and practices.

Allegheny is also subject to regulation by the SEC under PUHCA, which imposes a number of restrictions on the operations of registered utility holding companies and their subsidiaries. These restrictions include a requirement that, subject to a number of exceptions, the SEC approve in advance securities issuances, financings, acquisitions and dispositions of utility assets, or of securities of utility companies, and acquisitions by utility companies of other businesses. With limited exceptions, PUHCA requires that transactions between affiliated companies in a registered holding company system be performed at cost.

Allegheny cannot predict the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to it. Changes in regulations or the imposition of additional regulations could influence Allegheny’s operating environment and may result in substantial costs to Allegheny.

Allegheny’s costs to comply with environmental laws are significant, and the cost of compliance with present and future environmental laws could adversely affect its cash flow and profitability.

Allegheny’s 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 laws and regulations may require Allegheny to expend significant financial resources to, among other things, meet air emission standards, conduct site remediation, perform environmental monitoring, purchase emission allowances, use alternative fuels and modulate operations of its generation facilities in order to reduce emissions. If Allegheny fails to comply with applicable environmental laws and regulations, even if it is unable to do so due to factors beyond its control, it may be subject to civil liabilities or criminal penalties and may be required to incur significant expenditures to come into compliance. Alleged violations of environmental laws and regulations may require Allegheny to expend significant resources defending itself against these claims.

New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on Allegheny’s generation operations or require it to incur significant additional costs.

Applicable standards under the EPA’s NSR initiatives remain in flux. Under the Clean Air Act, modification of Allegheny’s generation facilities in a manner that causes increased emissions could subject Allegheny’s

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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 violation of NSR standards in connection with work believed by the companies to be routine maintenance.

On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue from the Attorneys General of Connecticut, New Jersey and New York and the Pennsylvania Department of Environmental Protection (“PADEP”) alleging that they made major modifications to some of their coal-fired generation facilities in West Virginia and Pennsylvania in violation of the Prevention of Significant Deterioration provisions of the Clean Air Act. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal district court in West Virginia on January 6, 2005. This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired power plants in West Virginia and Pennsylvania are in compliance with the Clean Air Act. The Attorneys General have filed a motion to dismiss the declaratory judgment action. If the action is dismissed based upon their motion, the Attorneys General may file an enforcement action against Allegheny in federal court in Pennsylvania. It is also possible that the EPA and other state authorities may join in the current declaratory judgment action or, if it is dismissed, a new action filed by the Attorneys General.

In December 2004, Pennsylvania adopted Renewable Portfolio Standard legislation. The new legislation requires that, by 2020, 18% of the energy used in Pennsylvania be derived from renewable and alternative sources. The new legislation includes a five-year exemption from this requirement for companies, such as the Distribution Companies, that are operating within transition periods under the current regulations governing the transition to market competition in Pennsylvania. The full requirement will apply to those companies when the applicable transition periods end. The legislation also includes a provision that will allow the Pennsylvania PUC to modify or eliminate these obligations if alternative energy sources are not reasonably available. Similar legislation has been adopted in Maryland. The Maryland law goes into effect on the later of the termination of the applicable transition period or July 1, 2006. See “Regulatory Framework Affecting Allegheny” below.

In addition, Allegheny incurs costs to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if Allegheny fails to obtain, maintain or comply with any required approval, operations at affected facilities could be halted or subjected to additional costs.

For additional information regarding environmental matters, see “Environmental Matters” below.

Shifting state and federal regulatory policies impose risks on Allegheny’s operations and capital structure.

Allegheny’s operations are subject to evolving regulatory policies, including initiatives regarding deregulation of the production and sale of electricity and the restructuring of transmission regulation. State or federal regulators may also take regulatory action as a result of the power outages that affected the Northeast and Midwest United States and Canada in August 2003. Any new requirements arising from these actions could lead to increased operating expenses and capital expenditures, the amount of which cannot be predicted at this time.

The continuation of below-market retail rate caps beyond the original scheduled end of transition periods could have adverse consequences for Allegheny. In the absence of a long-term power supply contract with a power generator, the Distribution Companies must purchase their power requirements at negotiated or market prices, whether from AE Supply or an alternative supplier. If retail rates are capped below the prices at which the Distribution Companies can obtain power, 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

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business through a variety of mechanisms, including through the extension of the current rate cap regimes, which are set below current market prices. Allegheny cannot predict to what extent these efforts will be successful. See “Regulatory Framework Affecting Allegheny” below.

Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have a material adverse effect on its results of operations and financial condition. At a minimum, these types of actions 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 its capital structure.

In addition, as a result of FERC’s efforts to implement a long-term rate design for the Midwest and Mid-Atlantic regions, the Distribution Companies may not fully recover their transmission costs and may have costs shifted to them from other transmission owners. Due to capped rates and the timing of state rate cases, the Distribution Companies may not be able to pass through increased transmission costs to these retail customers for some period of time.

Risks Related to Allegheny’s Substantial Debt

Covenants contained in Allegheny’s principal financing agreements restrict its operating, financing and investing activities.

Allegheny’s principal financing agreements contain restrictive covenants that limit its ability to, among other things:

These agreements limit Allegheny’s ability to implement strategic decisions, including its ability to access capital markets or sell assets without using the proceeds to reduce debt. In addition, Allegheny is required to meet certain financial tests under some of its loan agreements, including interest coverage ratios and leverage ratios. Allegheny’s failure to comply with the covenants contained in its financing agreements could result in an event of default, which could materially and adversely affect its financial condition.

Allegheny’s substantial debt could adversely affect its ability to operate successfully and meet contractual obligations.

Allegheny is substantially leveraged. One of its principal challenges is to manage its debt while continuing the long-term process of reducing the amount of its debt. At December 31, 2004, Allegheny had $5.0 billion of debt on a consolidated basis (including discontinued operations). Approximately $700 million of that amount represented AE’s obligations, $2.8 billion represented debt of AE Supply and AGC and the remainder constituted debt of one or more of the Distribution Companies.

Allegheny’s substantial debt could have important consequences to it. For example, it could:

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Allegheny may be unable to engage in desired financing transactions.

Allegheny has substantial debt service obligations for the foreseeable future and may need to engage in refinancing and capital-raising transactions in order to pay interest and retire principal. Allegheny also may undertake other types of financing transactions in order to meet its other financial needs and increase its equity ratios. Allegheny may be unable to successfully complete financing transactions due to a number of factors, including:

Allegheny currently anticipates that, in order to repay the principal of its outstanding debt, it may undertake one or more financing alternatives, such as refinancing or restructuring its debt, selling assets, reducing or delaying capital investments or raising additional capital. Allegheny can make no assurance that it can complete any of these types of financing transactions on terms satisfactory to it or at all, that any financing transaction would enable it to pay the interest or principal on its debt or meet its other financial needs or that any of these alternatives would be permitted under the terms of the agreements governing its outstanding debt.

Allegheny’s credit ratings and trading market liquidity may make it difficult for it to hedge its physical power supply commitments and resource requirements.

While Allegheny has made significant progress retiring unnecessary positions in the Western U.S. and other energy markets, its current credit ratings, together with a lack of market liquidity have made it difficult for it to retire a small number of remaining energy market positions. Market liquidity has significantly declined over the past three years. Absent a return to more liquid levels combined with an improvement in Allegheny’s credit ratings, it may not be possible for Allegheny to retire these remaining positions.

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

Allegheny’s risk management, wholesale marketing, fuel procurement and energy trading activities, including its 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 Allegheny’s policies and procedures are followed and decisions are made based on these models, its financial position and results of operations may be adversely affected if the judgments and assumptions underlying those models prove to be inaccurate.

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Risks Relating to Allegheny’s Operations

Allegheny’s generation 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 or efficiency. If Allegheny’s facilities, or the facilities of other parties upon which it depends, operate below expectations, Allegheny may lose revenues, have increased expenses or fail to receive the amount of power for which it has contracted.

Many of Allegheny’s facilities were originally constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to operate at peak efficiency or availability. If Allegheny underestimates required maintenance expenditures or is unable to make required capital expenditures due to liquidity constraints, it risks incurring more frequent unplanned outages, higher than anticipated maintenance expenditures, increased operation at higher cost of some of its less efficient generation facilities and the need to purchase power from third parties to meet its supply obligations.

Allegheny’s operating results are subject to seasonal and weather fluctuations.

Electrical power generation is generally a seasonal business, and weather patterns can have a material impact on Allegheny’s operating performance. Demand for electricity peaks during the summer and winter months, and market prices typically also peak during these times. During periods of peak demand, the capacity of Allegheny’s generation facilities may be inadequate, which could require it to purchase power at a time when the market price for power is very high. In addition, although the operational costs associated with the Delivery and Services segment are not weather-sensitive, the segment’s revenues are subject to seasonal fluctuation. Accordingly, Allegheny’s annual results and liquidity position may depend disproportionately on its performance during the winter and summer.

Allegheny’s revenues, costs and results of operations are subject to other risks beyond its control, including, but not limited to, accidents, storms, natural catastrophes and terrorism.

Much of the value of Allegheny’s business consists of its portfolio of power generation and T&D assets. Allegheny’s ability to conduct its operations depends on the integrity of these assets. The cost of repairing damage to its facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events may exceed reserves or insurance, if any, for repairs, which may adversely impact Allegheny’s results of operations and financial condition. Although Allegheny has taken, and will continue to take, reasonable precautions to safeguard these assets, Allegheny can make no assurance that its facilities will not face damage or disruptions or that it will have sufficient reserves or insurance to cover the cost of repairs. In addition, in the current geopolitical climate, enhanced concern regarding the risks of terrorism throughout the economy may impact Allegheny’s operations in unpredictable ways. Insurance coverage may not cover costs associated with any of these risks adequately or at all.

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, the Distribution Companies are required to provide electricity at capped rates to retail customers who do not choose an alternate electricity generation supplier or who return to utility service from alternate suppliers. The Distribution Companies satisfy the majority of these obligations by purchasing power from AE Supply under long-term agreements. Those agreements provide for the supply of a significant portion of the Distribution Companies’ energy needs at the

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mandated capped rates and for the supply of a specified remaining portion at rates based on market prices. The amount of energy priced at market rates increases over each contract term. The majority of AE Supply’s normal operating capacity is dedicated to these contracts with the Distribution Companies.

These power supply agreements present risks for both AE Supply and the Distribution Companies. At times, AE Supply may not earn as much as it otherwise could by selling power priced at capped rates to the Distribution Companies instead of into competitive wholesale markets. In addition, AE Supply’s obligations under these power supply agreements could exceed its available generation capacity, which may require AE Supply to buy power at prices that are higher than the sale prices in the power supply agreements. Changes in customer switching behavior could also alter AE Supply’s obligations under these agreements. Conversely, the Distribution Companies’ capped rates may be below current wholesale market prices through the applicable transition periods. As a consequence, the Distribution Companies may at times pay more for power than they can charge retail customers and may be unable to pass the excess costs on to their retail customers.

The supply and price of fuel and emissions credits may impact Allegheny’s financial results.

Allegheny is dependent on coal for much of its electric generation capacity. Allegheny has coal supply contracts in place that partially mitigate its exposure to negative fluctuations in coal prices. Allegheny can make no assurance, however, that the counterparties to these agreements will fulfill their obligations to supply coal. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations. In addition, the suppliers under these agreements may not be required to supply coal to Allegheny under certain circumstances, such as in the event of a natural disaster. If Allegheny is unable to obtain its coal requirements under these contracts, it may be required to purchase coal at higher prices, which could have a material adverse effect on its financial condition, cash flow and results of operations.

Allegheny estimates that it may purchase sulfur dioxide (“SO₂”) emission allowances for up to 50,000 tons for 2005 and an average of approximately 100,000 tons per year for 2006 through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced, and the type of fuel used, by its generation facilities. Fluctuations in the availability or cost of emission allowances could have a material adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Allegheny is currently involved in significant litigation that, if not decided favorably to Allegheny, could materially adversely affect its results of operations, cash flows and financial condition.

Allegheny is currently involved in a number of lawsuits, including lawsuits relating to breach of contract and its involvement in the energy trading business. Allegheny intends to vigorously pursue these matters, but the results of these lawsuits cannot be determined. Adverse outcomes in these lawsuits could require Allegheny to make significant expenditures and could have a material adverse effect on its results of operations, cash flows and financial condition. See “Legal Proceedings.”

The Distribution Companies and other AE subsidiaries are and may become subject to legal claims arising from the presence of asbestos or other regulated substances at some of their 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, and may continue to be, present at Allegheny-owned facilities where suitable alternative materials are not available. Allegheny’s management believes that any remaining asbestos at Allegheny-owned facilities is contained. The continued presence of asbestos and other regulated substances at Allegheny-owned facilities, however, could result in additional actions being brought against Allegheny. See “Legal Proceedings.”

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Allegheny may be required to make significant contributions to satisfy underfunded pension liabilities.

Allegheny’s underfunded pension liabilities have increased in recent periods due to declining interest rates and financial market performance and because of the implementation of early retirement initiatives to reduce headcount. Allegheny made a total contribution to pension plans during 2004 of $27.7 million, including $0.3 million to the SERP. Minimum required funding contributions are anticipated to increase beyond 2004. However, these anticipated mandatory contributions will change in the future if Allegheny’s assumptions regarding prevailing interest rates change, if actual investments under-perform or out-perform expectations or if actuarial assumptions or asset valuation methods change.

Allegheny also contributed $28.1 million to its postretirement benefits other than pensions in 2004. These costs may increase in 2005.

Changes in PJM market policies and rules may impact Allegheny’s financial results.

Substantially all of Allegheny’s generation assets and power supply obligations are located within the PJM market. Any changes in PJM policies or market rules, including changes that are currently under consideration by FERC, could adversely affect Allegheny’s financial results.

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

The energy sector has been the subject of highly-publicized allegations of misconduct. Negative publicity of this nature may make legislatures, regulatory authorities and tribunals less likely to view energy companies favorably, which could cause them to make decisions or take actions that are adverse to Allegheny. Power outages, such as those that affected the Northeast and Midwest United States and Canada in August 2003, could exacerbate negative sentiment regarding the energy industry.

Allegheny is dependent on its ability to successfully access capital markets. An inability to access capital may adversely affect Allegheny’s business.

Allegheny relies on access to the capital markets as a source of liquidity and to satisfy any of its capital requirements that are not met by the cash flow from its operations. Capital market disruptions, or a downgrade in Allegheny’s credit ratings, could increase Allegheny’s cost of borrowing or could adversely affect its ability to access one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

Risks Relating to Internal Controls and Procedures and Operational Enhancements

Allegheny’s internal controls and procedures have been substantially deficient, and it continues to expend significant resources to improve internal controls and procedures.

In August 2002, Allegheny’s independent registered public accounting firm, PricewaterhouseCoopers LLP (“PwC”), advised Allegheny that it considered AE’s and its subsidiaries’ internal controls to have material

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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. In March 2004, PwC advised AE’s Audit Committee that although management had made significant progress in addressing the specific control weaknesses previously identified, not all of these deficiencies had been remedied and certain internal control weaknesses remained. In September 2004, PwC advised AE’s Audit Committee that certain material weaknesses remained and required remediation. As of December 31, 2004, these material weaknesses have been remediated, although some deficiencies remain. Allegheny intends to expend additional resources to further improve its internal controls.

Refocusing its business subjects Allegheny to risks and uncertainties.

Since late 2002, Allegheny has been reassessing the business environment, its position within the energy industry and its relative strengths and weaknesses. As a result of this reassessment, Allegheny has implemented significant changes to its operations as part of its overall strategy to function as an integrated utility company, to the extent practicable and permissible under relevant regulatory constraints. For example, Allegheny has reduced the size of its workforce and made substantial changes to senior management. Additional changes to Allegheny’s business will be considered as management seeks to strengthen financial and operational performance. These changes may be disruptive to Allegheny’s established organizational culture and systems. In addition, consideration and planning of strategic changes diverts management attention and other resources from day to day operations.

Allegheny may engage in sales of assets and businesses; however, market conditions and other factors may hinder this strategy.

Allegheny may continue to sell non-core assets. Sales prices for energy assets and businesses could fluctuate due to prevailing conditions. Asset sales under poor market conditions could result in substantial losses. Buyers also may find it difficult to obtain financing to purchase these assets. As part of any asset sale, Allegheny faces challenges associated with valuing the assets correctly and limiting its environmental or other retained liabilities. These transactions also may divert management attention and other resources from day to day operations.

Several factors specific to Allegheny could make asset sales particularly challenging. Allegheny and potential purchasers are subject to regulatory approvals, which can impose delays and structuring complications on asset sale transactions. Potential buyers may be reluctant to enter into agreements to purchase assets from Allegheny if they believe that required consents and approvals will result in significant delays or uncertainties in the transaction process.

Allegheny may fail to realize the benefits that it expects from its cost-savings initiatives.

Allegheny has undertaken and expects to continue to undertake cost-savings initiatives. However, Allegheny can make no assurance that it will realize on-going cost savings or any other benefits from these initiatives. Even if Allegheny realizes the benefits of its cost savings initiatives, any cash savings that it achieves may be offset by other costs, such as environmental compliance costs and higher fuel, operating and maintenance costs, or could be passed on to customers through revised rates. Staff reductions may reduce Allegheny’s workforce below the level needed to effectively manage its business and service its customers. Allegheny’s failure to realize the anticipated benefits of its cost-savings initiatives could have a material adverse effect on its business, results of operations and financial condition.

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ALLEGHENY’S SALES AND REVENUES

The Generation and Marketing Segment’s Sales and Revenues

The Generation and Marketing segment had operating revenues of $1,538.7 million and $956.2 million in 2004 and 2003, respectively. For more information regarding the Generation and Marketing segment’s operating revenues, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 12, “Business Segments,” to the Consolidated Financial Statements.

The Delivery and Services Segment’s Sales and Revenues

The Delivery and Services segment had operating revenues of $2,764.1 million and $2,705.8 million in 2004 and 2003, respectively. These revenues included revenue from electric sales, regulated natural gas sales and unregulated services. The following tables describe the segment’s kWh sales and revenues from electric sales:

Intersegment Eliminations

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Revenues from natural gas sales have been reclassified to discontinued operations. These revenues included:

For more information regarding the Delivery and Services segment’s revenues, see “Management’s Discussion and Analysis of Financial Condition and Operating Results” and Note 12, “Business Segments,” to the Consolidated Financial Statements.

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CAPITAL EXPENDITURES

The table below shows total capital expenditures for Allegheny in 2004 and estimated capital expenditures for 2005 and 2006, as well as the environmental control expenditures that are included in these capital expenditures or estimated capital expenditures.

The Delivery and Services segment’s capital expenditures of $160.5 million for 2004 are shown net of $10.8 million in proceeds from the sale of land by WVP.

The Generation and Marketing segment’s capital expenditures include projects at generation facilities for environmental control upgrades and to remediate or prevent equipment failure. The Delivery and Services segment’s capital expenditures include projects to upgrade distribution lines and substations, as well as transmission and subtransmission systems enhancements. The amounts shown above include allowance for funds used during construction (“AFUDC”) for the Distribution Companies. AFUDC includes the non-cash cost, for the period of construction, of borrowed funds used for construction purposes and a reasonable rate on other funds used in construction.

AE Supply ceased construction of, or planning for, several generation projects in 2002 in response to market conditions, including overcapacity and lower wholesale power prices, and to conserve liquidity. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 7, “Asset Impairments,” to the Consolidated Financial Statements for information regarding charges for discontinued generation projects.

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ELECTRIC FACILITIES

All of Allegheny’s owned or controlled generation capacity is part of the Generation and Marketing segment and is owned or controlled by AE, AE Supply, Monongahela or AGC. In addition, the Distribution Companies are obligated to purchase 479 MW of power through state utility commission-approved arrangements pursuant to PURPA. This PURPA capacity is part of the Delivery and Services segment. See “PURPA Capacity” below.

Allegheny’s owned and controlled capacity as of December 31, 2004 was 10,851 MW, of which 7,819 MW (72.1%) were coal-fired, 1,907 MW (17.6%) were natural gas-fired, 1,043 MW (9.6%) were pumped-storage and hydroelectric and 82 MW (0.7%) were oil-fired. These amounts include capacity to which AE Supply is entitled in conjunction with AE’s sale of a portion of its interest in OVEC.

AE holds a 3.5% equity stake in, and is a sponsoring company of, OVEC. Currently, AE Supply and Monongahela are entitled to 9% (203 MW) and 3.5% (78 MW), respectively, of OVEC capacity. OVEC supplies power to its sponsoring companies under an intercompany power agreement that expires on March 12, 2006. In December 2004, AE sold a 9% equity interest in OVEC to Buckeye Power Generating, LLC (“Buckeye”). In addition, AE Supply assigned to Buckeye all of its rights and obligations under a new OVEC intercompany power agreement effective on March 13, 2006. AE Supply retained its rights under the current agreement to 9% of the power from the OVEC electric generation facilities through March 12, 2006.

In December 2004, AE Supply sold its subsidiary, Allegheny Energy Supply Lincoln Generating Facility, LLC (“Lincoln”). Lincoln’s assets included the 672 MW natural gas-fired Lincoln Generating Facility located in Manhattan, Illinois. AE Supply is also currently seeking to sell its Gleason Generating Facility in Gleason, Tennessee and its Wheatland Generating Facility in Wheatland, Indiana.

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The following table shows the nominal maximum operational generation capacity owned or controlled by Allegheny, as of December 31, 2004. This generation is included in the Generation and Marketing segment.

Nominal Maximum Operational Generation Capacity (MW)

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Significant 2004 Outages

On November 3, 2003, a fire occurred in Unit No. 2 at the Hatfield’s Ferry generation station located near Masontown, Pennsylvania. Hatfield’s Ferry Unit No. 2 is a 570 MW coal-fired generation unit owned by AE Supply and Monongahela. As a result of the fire, the unit’s generator, turbine and certain associated equipment sustained significant damage. On February 9, 2004, a generator failure occurred in Unit No. 1 at the Pleasants generation station located in Willow Island, West Virginia. Pleasants Unit No. 1 is a 650 MW coal-fired generation unit owned by AE Supply and Monongahela. As a result of the generator failure, the unit’s generator and associated equipment sustained damage. Both units returned to service in June 2004.

As a result of these outages, Allegheny had less power to sell into the PJM market, and its operating results were adversely affected. The estimated lost revenues (net of fuel cost savings) associated with the Hatfield’s Ferry and Pleasants outages were approximately $58 million and $35 million, respectively, for 2004. Allegheny continues to pursue additional insurance recoveries in connection with these outages.

PURPA Capacity

The following table shows additional generation capacity available to the Distribution Companies through state utility commission-approved arrangements pursuant to PURPA. PURPA requires electric utility companies, such as the Distribution Companies, to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying small power production and cogeneration facilities. The amounts shown in this table are included in the Delivery and Services segment. See “Regulatory Framework Affecting Allegheny—Federal Regulation and Rate Matters—PURPA” below.

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The following table sets forth the existing miles of tower and pole T&D lines and the number of substations of the Distribution Companies and AGC as of December 31, 2004:

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

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FUEL, POWER AND RESOURCE SUPPLY

Generation and Marketing Segment

Coal Supply

Allegheny purchased 16.9 million tons of coal in 2004 at an average price of $30.53 per ton delivered. Allegheny purchased this coal primarily from mines in Pennsylvania, West Virginia and Ohio. However, Allegheny considers sources of coal supply from other viable regions. During 2004, Allegheny conducted test burns of Powder River Basin coal from Wyoming at several generation facilities.

Historically, Allegheny has purchased coal from a limited number of suppliers. Of Allegheny’s coal purchases in 2004, 76% came from subsidiaries of two companies, the larger of which represented 58% of the total tons purchased. As of February 17, 2005, Allegheny had contracts in place for the delivery of approximately 17 million tons of coal in 2005 at an average price of $34.70 per ton delivered. This represents approximately 95% of estimated coal to be consumed in 2005. Due to various industry factors, including increased mining costs, rail transportation constraints and operational difficulties, some coal suppliers are under increased financial pressure, which has had, and may continue to have, negative effects on coal supplier performance.

As existing long-term contracts expire, Allegheny plans to enter into multi-year contracts to secure a reliable coal supply. These new arrangements are expected to be at higher prices than the expiring contracts.

Allegheny owns undeveloped coal reserves estimated to contain in excess of 120 million tons of higher sulfur coal recoverable by deep mining. Allegheny is evaluating a number of alternatives related to these undeveloped reserves.

Natural Gas Supply

AE Supply purchases natural gas services to supply its natural gas-fired facilities. In 2004, AE Supply purchased its natural gas requirements principally in the spot market. In addition, one of AE Supply’s subsidiaries has a month-to-month natural gas agreement in place with a supplier. The natural gas provided under this agreement is used at the Buchanan facility.

Natural Gas Transportation Contracts

Dominion Transmission Transportation Contract.    AE Supply has a long-term agreement with Dominion Transmission, Inc. for the transportation of natural gas under a tariff approved by FERC. This agreement provides for the transportation of 95,000 decatherms of natural gas per day through May 31, 2013, from Oakford, Pennsylvania to AE Supply’s combined cycle plant in Springdale, Pennsylvania.

Equitable Gas Transportation Contract.    AE Supply has a long-term agreement with Equitable Gas Company, a division of Equitable Resources, Inc., for the transportation of natural gas under a tariff approved by FERC. This agreement provides for transportation of 90,000 decatherms of natural gas per day through December 31, 2012 from Greene County, Pennsylvania to the Hatfield’s Ferry generation station in Masontown, Pennsylvania. This transportation agreement was purchased for anticipated natural gas reburn opportunities at Hatfield’s Ferry. Natural gas reburn reduces NOx emissions at a generation station by using natural gas instead of coal for a portion of the generation station’s anticipated fuel requirements. This process is used at Hatfield’s Ferry when the price of natural gas makes reburn economic relative to other NOx emission management activities.

El Paso Transportation Contract.    AE Supply has a long-term agreement with El Paso Natural Gas Company for the transportation of natural gas under tariffs approved by FERC. This agreement provides for the

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transportation of gas from western Texas and northern New Mexico to the southern California border and was purchased for anticipated natural gas deliveries to the La Paz combined-cycle generation facility in Arizona. This project has been cancelled. In August 2003, AE Supply obtained a permanent release of approximately 85% of its capacity obligation under this contract. In November 2004, AE Supply entered into a release for the balance of this capacity.

Kern River Transportation Contract.    AE Supply has a long-term agreement with Kern River Gas Transmission Company for the transportation of natural gas under a tariff approved by FERC. This agreement provides for the transportation of 45,122 decatherms of natural gas per day through April 30, 2018 from Opal, Wyoming to Nevada and southern California. This transportation agreement was purchased for anticipated natural gas deliveries into southern California and at the Las Vegas Cogeneration II combined-cycle generation facility in Las Vegas, Nevada. In June 2004, AE Supply entered into a long-term capacity release for the full contract volume through October 2007. AE Supply recorded charges of $15.5 million related to this release in 2004.

The Delivery and Services Segment

Electric Power

Allegheny reorganized its corporate structure in response to electric utility deregulation within its service area between 1999 and 2001. The Distribution Companies, with the exception of Monongahela and its West Virginia generation assets, do not produce their own power. Monongahela transferred a portion of its generation assets relative to its Ohio and FERC generation assets, including a portion of its ownership interest in AGC, to AE Supply in 2001. Potomac Edison transferred substantially all of its generation assets to AE Supply in 2000. West Penn transferred all of its generation assets to AE Supply in 1999.

The Distribution Companies are obligated to provide electricity at capped rates to customers who do not retain an alternate electricity generation supplier during the applicable deregulation transition period. The transition periods vary across Allegheny’s service area.

These transition periods could be altered by legislative, judicial or, in some cases, regulatory actions. See “Regulatory Framework Affecting Allegheny” below.

AE Supply is contractually obligated to provide power to the Distribution Companies during the relevant state deregulation transition periods under the terms of power supply agreements with the Distribution Companies. AE Supply also sells power to Potomac Edison to serve customers in Potomac Edison’s West Virginia service territory. Sales under AE Supply’s power sales agreements with West Penn, Monongahela (with respect to its Ohio customers) and Potomac Edison currently consume a majority of the normal operating capacity of AE Supply’s generation assets. These power sales agreements include both fixed price and market-based pricing components. These pricing components may not fully reflect the cost of supplying this power. As a result, AE Supply currently absorbs a portion of the risk of fuel price increases and increased costs of environmental compliance.

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The Distribution Companies purchase a majority of the power required to satisfy their respective PLR obligations from AE Supply. The purchases are made under the terms of power sales agreements with AE Supply, which will terminate as set forth in the chart below. When the power sales agreements with AE Supply terminate, the Distribution Companies will be unable to rely on the previously dedicated supply of power at specified contract prices to meet their respective power supply requirements.

The arrangements to serve the PLR obligations of the Distribution Companies following the termination of these agreements have not been determined and are subject to active legislative and regulatory actions in Pennsylvania and Virginia. In Maryland, a final state commission order that prescribes a wholesale bidding process to procure market-based full requirements service for end use customers was issued on September 30, 2003. The bid solicitation process began on October 1, 2003. By January 28, 2005, the Distribution Companies had completed two full bid solicitations, securing PLR service for eligible Maryland commercial and industrial customers through May 31, 2006.

In Ohio, the market development period for medium to large commercial and industrial customers and streetlighting terminated on December 31, 2003. PUCO authorized Monongahela to issue a request for proposals for wholesale power to supply approximately 130 MW of market-based retail rate service to these customers, effective January 1, 2004. AE Supply won the competitive bid process to serve the load, subject to approval of its bid by PUCO. In October 2003, PUCO denied approval of the wholesale bid and new retail rates and continued the fixed rates for these customer classes until December 31, 2005. See “Regulatory Framework Affecting Allegheny—State Legislation, Rate Matters and Regulatory Developments,” below for a more detailed discussion of legal and regulatory actions relating to this matter.

A portion of the Distribution Companies’ PLR obligations is satisfied by PURPA contract purchases. Most of the rest of the power necessary to meet the PLR obligations of the Distribution Companies and Potomac Edison’s regulated service obligations in West Virginia is purchased from AE Supply. The table below shows the percentage of power for each jurisdictional set of customers that was purchased by the Distribution Companies from AE Supply in 2004:

Natural Gas Supply

In August 2004, Monongahela signed a definitive agreement to sell its natural gas operations in West Virginia, including Mountaineer, for $141 million in cash and the assumption of approximately $87 million of long-term debt, subject to certain closing adjustments. The sale is subject to regulatory approval and is expected

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to be completed in mid- to late-2005. These natural gas operations are shown as discontinued operations in the accompanying financial statements.

Monongahela’s regulated natural gas sales operations are carried out through Mountaineer and its Monongahela divisions. West Virginia is in the path of major natural gas supply routes from the Gulf of Mexico to the Northeast, and Monongahela has direct access to the Columbia Gas Transmission Corporation (“Columbia Gas”) and the Tennessee Gas Pipeline interstate pipeline systems. Monongahela’s principal natural gas requirements are supplied from wells located in Appalachia and the Gulf of Mexico producing basins. Monongahela’s ownership of MGS provides direct access to less than 5% of Monongahela’s total annual natural gas needs. A small part of MGS’ output is sold to third parties. Approximately 75% to 85% of Monongahela’s natural gas supply requirements are purchased on a forward basis up to 18 months in advance. The remainder, including MGS production, is purchased on a one-year or more forward basis primarily at index-based prices.

As a result of Allegheny’s past liquidity issues, coupled with natural gas price increases, Monongahela was required to prepay for some of its future natural gas purchases during 2004. Monongahela believes that it will have access to sufficient natural gas supplies to meet its anticipated requirements.

Natural Gas Transportation and Storage Capacity

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

To ensure continuous, uninterrupted service to its customers, Mountaineer has long-term transportation and storage service agreements with Columbia Gas and Columbia Gulf. These contracts cover a wide range of transportation services and volumes. Under both Mountaineer’s and WVP’s Purchased Gas Adjustment clauses, purchased gas costs including transportation and storage services, if prudently incurred, are recovered from the respective companies’ customers.

Typically, large commercial and industrial end-users of natural gas use natural gas sales and/or transportation contracts for load management purposes. Under these contracts, users purchase and/or transport natural gas with the understanding that they may be forced to shut down their use of natural gas or switch to alternate sources of energy during periods of high demand for natural gas. In addition, during times of extraordinary supply problems, curtailments of deliveries to some classes of customers (typically large industrial customers) with interstate transportation contracts may be necessary, but only in accordance with guidelines established by appropriate federal and state regulatory agencies.

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REGULATORY FRAMEWORK AFFECTING ALLEGHENY

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

AE and all of its subsidiaries are also subject to the broad jurisdiction of the SEC under PUHCA. In addition, Allegheny’s communications subsidiary, ACC, is subject, to a limited extent, to the jurisdiction of the Federal Communications Commission and state communications regulatory commissions. Allegheny is subject to numerous other local, state and federal laws, regulations and rules.

Federal Regulation and Rate Matters

FERC, Competition and RTOs

FERC is an independent agency within the U.S. Department of Energy that regulates the transmission and wholesale of electricity under the authority of the FPA. Under the FPA, FERC regulates the rates, terms and conditions of wholesale power sales and transmission services offered by public utilities.

The FPA gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity. Entities such as the Distribution Companies and AE Supply that sell electricity at wholesale or own transmission facilities are considered “public utilities” subject to FERC jurisdiction. Public utilities must obtain FERC approval of their wholesale rate schedules. Rates for transmission service are determined on a cost of service basis, or, if the utility has demonstrated that it does not have market power, FERC may grant market-based rate authority, which allows transactions to be priced based on prevailing market conditions.

Over the past decade, FERC has taken a number of steps to foster increased competition within the electric industry. Among other things, FERC requires public utilities to offer non-discriminatory, open-access transmission services. In addition, FERC imposed standards of conduct governing communications between employees conducting transmission functions and employees engaged in wholesale power sale activities. These standards of conduct are intended to prevent utilities from giving their power marketing businesses preferential access to transmission system information. FERC also has taken steps to encourage utilities to participate in RTOs, such as PJM, by transferring control over their transmission assets to RTOs.

Following FERC’s initiative to promote competition, a number of states, including Pennsylvania, Maryland, Virginia and Ohio, adopted retail access legislation, which permitted utilities to transfer their generation assets to affiliated companies or third parties. Similar to many other utilities, the Distribution Companies restructured their businesses in Pennsylvania, Maryland, Virginia and Ohio between 1996 and 2001 to comply with retail restructuring requirements in those states by, among other things, transferring generation assets serving customers in those states to AE Supply.

However, this trend toward restructuring and increased competition for retail markets has slowed in response to events over the past several years. Among other things, significant price volatility (particularly in the California wholesale market), allegations of improper trading activities and overall declines in electricity demand and in the economy, generally, have contributed to this slowdown. Market-based competition within the wholesale markets is now continuing with greater FERC oversight, and some states have moved away from electricity choice at the retail level by delaying the implementation of retail competition (as in Virginia) or rejecting it outright (as in West Virginia). Delays, discontinuations or reversals of electricity marketing restructurings in states in which Allegheny operates could have a material adverse effect on its results of operation and financial condition. See “State Legislation, Rate Matters and Regulatory Developments” below.

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In April 2002, the Distribution Companies transferred functional control of their transmission assets to PJM. As part of its approval of the transfer of control, FERC permitted a transmission rate surcharge designed to allow the Distribution Companies to recover $85 million in revenues that would otherwise not be collectible once they joined PJM. In 2004, 2003 and 2002, the Distribution Companies recovered approximately $35 million, $27 million and $23 million of these surcharges, respectively. FERC also allowed the Distribution Companies to collect a surcharge to recover the costs associated with Allegheny’s integration into PJM, which expired at the end of 2004. Accordingly, the Distribution Companies have fully recovered all of these surcharges as of December 31, 2004.

The Distribution Companies also may be impacted by recent FERC actions with respect to the transmission rate design within PJM. Beginning in November 2003, FERC issued a series of orders related to transmission rate design for the PJM and Midwest Independent Transmission System Operator regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for the region. In November 2004, FERC rejected long-term regional rate proposals from the Distribution Companies and others and ordered the continuation of the existing rate design and the implementation of a transition charge for this region through March 31, 2006. FERC also authorized three transmission owners to submit filings that would enable them to assess additional transition charges against the Distribution Companies and other utilities in PJM. Allegheny estimates that these additional charges, if accepted by FERC, will result in net transmission charges to the Distribution Companies of approximately $0.5 million for the four-month period ended March 31, 2005 and approximately $8.9 million for the twelve-month period ended March 31, 2006. In February 2005, FERC accepted these transition charges, effective December 1, 2004, subject to an evidentiary hearing regarding the data and methodology used to determine the charges and proposed adjustments. The order expected to be issued by FERC may require the Distribution Companies to refund some portion of the amounts received from these transition charges or entitle the Distribution Companies to receive additional revenue from these charges. In addition, the Distribution Companies may be required to pay additional amounts as a result of surcharges imposed on the transition charges previously billed to the Distribution Companies.

Substantially all of Allegheny’s generation assets and power supply obligations are located within the PJM market. Any changes in PJM policies and/or market rules, including changes that are currently under consideration by FERC, could adversely affect Allegheny’s financial results. These matters include proposed revisions to PJM’s tariff concerning the auction of financial transmission rights and the allocation mechanism for the auction revenues; changes in transmission congestion patterns due to the proposed implementation of PJM’s regional transmission expansion planning protocol or other required transmission system upgrades; the effects throughout the system of new members joining PJM and new generation retirement rules and reliability pricing issues.

By September 30, 2005, AE Supply, the Distribution Companies and other Allegheny entities that had market-based rate authority granted by FERC are required to file a triennial analysis of market power with FERC. This filing is required as a condition to continuing to sell electric energy at wholesale and market rates.

PUHCA

Any entity that owns, controls or has the power to vote 10% or more of the outstanding voting securities of an “electric utility company,” or a holding company for an electric utility company, is subject to SEC regulation under PUHCA.

PUHCA imposes financial and operational conditions and restrictions on many aspects of a registered holding company system’s business. PUHCA restricts a registered holding company system from expanding into other businesses by prohibiting it from engaging in activities that are not functionally related to its core business. PUHCA also requires registered holding company systems to confine themselves to a single integrated public utility system. Most important in light of Allegheny’s past liquidity issues, PUHCA requires pre-approval from

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the SEC for, among other things, the issuance of debt or equity securities and for the sale or acquisition of utility assets. The SEC, in certain matters, also requires state approvals as a condition to authorizations, even though such approvals might not be required under applicable state laws. Thus, the PUHCA approval process introduces significant lead times into routine transactions under normal circumstances.

Additionally, under PUHCA, the SEC has imposed a common equity to total capitalization ratio on the utilities that it regulates, thus imposing additional operating constraints not imposed on other utilities. Allegheny’s current common equity ratio is below the level required under its current financing authorizations, which has required it to obtain additional authorizations.

Many of Allegheny’s competitors are not regulated under PUHCA and, therefore, do not face these constraints.

PURPA

PURPA requires electric utility companies such as the Distribution Companies to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying small power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by FERC. State public service commissions or legislatures establish the rates paid for electric energy purchased from these qualifying facilities.

The Distribution Companies have committed to purchase 479 MW of qualifying PURPA capacity. In 2004, payments for PURPA capacity and energy pursuant to these contracts totaled approximately $197.8 million. The average cost to the Distribution Companies of these power purchases was 5.2 cents/kWh. The Distribution Companies are currently authorized to recover substantially all of these costs in their retail rates. The Distribution Companies’ obligations to purchase power from qualified PURPA projects in the future may exceed amounts they are authorized to recover from their customers, which could result in losses related to the PURPA contracts.

State Legislation, Rate Matters and Regulatory Developments

Pennsylvania

The Electricity Generation Customer Choice and Competition Act (the “Customer Choice Act”) gave all retail electricity customers in Pennsylvania the right to choose their electricity generation supplier as of January 2, 2000. Under the Customer Choice Act and a subsequent restructuring settlement approved by the Pennsylvania PUC, West Penn transferred its generation assets to AE Supply. West Penn retained its T&D assets. West Penn’s T&D assets are subject to traditional regulated utility ratemaking (i.e., cost-based rates). As part of West Penn’s restructuring settlement, West Penn is subject to rate caps on its T&D rates through December 31, 2005 and on its generation rates through December 31, 2008. West Penn is the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver.

West Penn has long-term power sales agreements with AE Supply to provide West Penn with the amount of electricity necessary to meet the majority of its PLR retail obligations (and certain wholesale contracts) during the Pennsylvania transition period. As directed by the Customer Choice Act, the Pennsylvania PUC has issued draft PLR service rules addressing the utilities’ obligation to serve customers at the end of their respective transition periods.

In November 2003, West Penn requested approval to issue additional transition bonds up to amounts originally authorized to securitize the portion of West Penn’s stranded costs that are not recoverable on a timely basis due to operation of the generation rate cap. In September 2004, West Penn, the Pennsylvania Office of Consumer Advocate, the Office of Small Business Advocate and The West Penn Power Industrial Intervenors

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filed a Joint Petition for Settlement and for Modification of the 1998 Restructuring Settlement (the “Joint Petition”). In March 2005, the parties filed an amendment to the Joint Petition, adding additional parties. If the joint petition is approved, West Penn will be allowed to securitize up to $115 million of additional transition costs (including the deferred portion of the competitive transition charge (“CTC”) from 1999 through 2004) through the issuance of transition bonds. Under the proposed settlement, distribution rate caps will be extended from 2005 to 2007, and generation rate caps will be extended from 2008 to 2010, with additional generation rate increases occurring in 2007, 2009 and 2010. These increases will gradually move generation rates closer to market-based rates.

In August 2004, West Penn filed its annual CTC reconciliation for the twelve months ended July 31, 2004. The reconciliation showed a twelve-month underrecovery of $13.2 million, for a cumulative underrecovery of approximately $78.3 million. In October 2004, West Penn filed a Petition for Continued Deferral of CTC Underrecovery as Regulatory Asset. The Pennsylvania PUC approved the reconciliation and granted authorization to record the 2004 cumulative underrecovery as a regulatory asset, for full and complete recovery, with an annual interest rate of 11%.

Recently enacted legislation requires the implementation of an alternative energy portfolio standard in Pennsylvania which will require electric distribution companies and retail electric suppliers in Pennsylvania to obtain certain percentages of their energy supplies from alternative sources. The new legislation includes a five-year exemption from this requirement for companies, such as West Penn, that are operating within a transition period under the current regulations governing the transition to market competition in Pennsylvania. The full requirement will apply to those companies when the transition period ends. The legislation also includes a provision that will allow the Pennsylvania PUC to modify or eliminate these obligations if alternative sources are not reasonably available. The law directs that all costs related to the purchase of electricity from alternative energy sources and payments for alternative energy credits will be fully recovered pursuant to an automatic energy adjustment clause. The Pennsylvania PUC initiated a proceeding in January 2005 to investigate implementation and enforcement of the legislation.

West Virginia

In 1998, the West Virginia legislature passed legislation directing the West Virginia PSC to determine whether retail electric competition was in the best interests of West Virginia and its citizens. In response, the West Virginia PSC submitted a plan to introduce full retail competition on January 1, 2001. The West Virginia legislature approved, but never implemented, this plan. In March 2003, the West Virginia legislature passed a bill that clarified the jurisdiction of the West Virginia PSC over electric generation facilities. Based on these actions, Allegheny has concluded that retail competition and the deregulation of generation is no longer likely in West Virginia. In 2000, Potomac Edison received approval to transfer its West Virginia generation assets to AE Supply. The West Virginia PSC never acted on a similar petition by Monongahela, and Monongahela agreed to withdraw its petition.

In July 2003, Potomac Edison, Monongahela and certain other interested parties filed a stipulation with the West Virginia PSC on issues related to their generation asset transfers, including the amount transferred to AE Supply representing Ohio’s allocated share of Monongahela’s generation. The West Virginia PSC has not yet approved the stipulation and the parties to the agreement have initiated discussions to consider modifications to the agreement.

On September 27, 2004, Monongahela, Mountaineer and Mountaineer Gas Holding Limited Partnership (“Mountaineer Holdings”) filed a joint petition with the West Virginia PSC for approval to transfer the stock of Mountaineer and certain other natural gas distribution assets owned by Monongahela to Mountaineer Holdings, the prospective buyer of Monongahela’s West Virginia natural gas business. In a separate petition also filed on September 27, 2004, Mountaineer filed to increase its distribution rates by approximately $23 million, or 9.6%, annually. Mountaineer Holdings’ obligation to complete this transaction is conditioned on approval of a rate increase that is not materially different from the increase requested. The West Virginia PSC issued an order suspending the rates until September 8, 2005 and directing the administrative law judge to render a decision in this matter no later than July 11, 2005.

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Monongahela’s natural gas distribution business is divided into two components for purposes of its Purchased Gas Adjustments (“PGA”): West Virginia Power Gas Services (“WVPGS”) and Mountaineer. WVPGS and Mountaineer file with the West Virginia PSC to adjust their PGA every year. The PGA mechanism compares the revenue received for recovery of projected gas expenses to the actual gas expenses incurred by WVPGS or Mountaineer and defers any difference as a regulatory asset or liability to be collected or returned, respectively, to customers in the next proceeding. The PGA generally has no effect on earnings. An annual PGA period normally begins with service provided on and after November 1 and concludes on October 31 of the following year.

On October 7, 2004, an administrative law judge for the West Virginia PSC approved an interim PGA increase, effective on November 1, 2004, of $4.1 million, or 12.5%, for WVPGS and $26.4 million, or 9.7%, for Mountaineer. In January 2005, the West Virginia PSC issued a second interim decision, which became final in February 2005, approving final PGA rates that were higher than the prior year’s rates, but lower than the first approved interim rates, effective February 1, 2005. These rates resulted in an increase over the prior year of $3.9 million, or 11.8%, for WVPGS and $25.0 million, or 9.2%, for Mountaineer. The estimated annual total revenue increases reflect the companies’ agreement to defer half of the under-recovered balances as of June 30, 2004. Approximately $1 million for WVPGS and $7 million for Mountaineer will be deferred until the next PGA proceeding. Carrying charges will accumulate on these deferred amounts at Allegheny’s cost of debt calculated for a one-year period, which will also be recovered in the next PGA proceeding.

Maryland

Maryland adopted electric industry restructuring legislation in 1999, which gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation suppliers. In 2000, Potomac Edison transferred its Maryland generation assets to AE Supply. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates for all customers were capped through 2004 and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates). Potomac Edison is the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver.

The Maryland transition period lasted through December 31, 2004 for commercial and industrial customers and extends through December 31, 2008 for residential customers. Potomac Edison has long-term power sales agreements with AE Supply to provide the amount of electricity necessary to meet the majority of Potomac Edison’s PLR retail obligations (and certain wholesale contracts) during the Maryland transition period. Potomac Edison will procure the wholesale electric supply services necessary to serve its PLR obligations after the expiration of the transition period and before the expiration of its PLR obligations through a competitive bid process. Potomac Edison will be allowed to recover its costs for providing these services, including a return for its shareholder, through an administrative charge.

In January 2005, a previously approved increase in Potomac Edison’s distribution rates went into effect.

In 2000, the Maryland PSC issued an order imposing standards of conduct between Maryland utilities and their affiliates. In 2005, the Maryland PSC is expected to issue final regulations to provide standards governing a utility’s conduct with its affiliates in Maryland.

Recently enacted legislation requires the implementation of a renewable energy portfolio standard in Maryland. Beginning upon the later of the expiration of the transition period for any particular customer class served by a supplier or January 1, 2006, retail electricity suppliers in Maryland will have to obtain certain percentages of their energy supplies from renewable energy resources. The law provides that if renewable resources are too expensive, or are unavailable in quantities sufficient to meet the standard in any given year, suppliers can opt instead to pay a “compliance fee.” The law directs the Maryland PSC to allow electric suppliers to recover their costs from customers, including any compliance fees that they incur.

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Virginia

Under the Virginia Electric Utility Restructuring Act of 1999 (as amended, the “Restructuring Act”), Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Potomac Edison transferred all of its Virginia generation assets to AE Supply in 2000, except certain small hydro facilities, which were transferred to Green Valley Hydro. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates are capped through 2010, subject to certain exceptions. Potomac Edison has two opportunities to petition the Virginia SCC for changes to its T&D rates, between January 1, 2004 and June 30, 2007 and once again after July 1, 2007. The Restructuring Act requires the Virginia SCC to adjust Potomac Edison’s capped rates not more than once annually for the timely recovery of costs prudently incurred after July 1, 2004 for transmission or distribution system reliability or to comply with state or federal environmental laws or regulations. In addition, after July 1, 2007, Potomac Edison will have the right to recover annually certain purchased power expenses as an exception to capped rates. Potomac Edison is the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver.

Potomac Edison has long-term power sales agreements with AE Supply to provide Potomac Edison with the amount of electricity necessary to meet the majority of its PLR retail obligations (and a wholesale contract) through June 30, 2007. After that, Potomac Edison will purchase its PLR requirements from the wholesale market and recover certain costs from customers through a purchased power adjustment clause.

On October 8, 2004, the Virginia SCC approved Potomac Edison’s application to transfer control of its transmission facilities to PJM subject to the requirement that both Potomac Edison and PJM submit annual reports to the Virginia SCC beginning October 1, 2005.

Ohio

The Ohio General Assembly adopted legislation in 1999 to restructure its electric utility industry, provide retail electric customers the right to choose their electricity generation supplier and begin a transition to market rates. The 1999 legislation granted Ohio’s residential customers a 5% reduction in the generation portion of their rates until December 31, 2005, which is when the transition period ends. Pursuant to a settlement, Monongahela’s transition period for large industrial, commercial and street lighting customers was scheduled to end on December 31, 2003, but, as discussed below, has been extended by PUCO until December 31, 2005. Under the regulatory transition plan, Monongahela transferred its Ohio generation assets to AE Supply in June 2001. Monongahela retained its T&D assets. Monongahela’s T&D rates are capped through the end of the transition period for all customers and, thereafter, are subject to traditional regulated utility ratemaking (i.e., cost-based rates). Monongahela is the PLR for customers who do not choose an alternate supplier or whose alternate supplier does not deliver.

In July 2003, PUCO authorized Monongahela to issue a request for proposals for wholesale power to supply approximately 130 MW of new standard market-based retail rate service to its large industrial and commercial customers and to its street lighting customers. In October 2003, PUCO denied approval of the wholesale bid and new retail rates and froze the current fixed rates for these customer classes until December 31, 2005. In February 2004, Monongahela appealed PUCO’s decision to the Ohio Supreme Court. On December 30, 2004, the Ohio Supreme Court affirmed PUCO’s October 2003 order extending Monongahela’s rate freeze for large commercial and industrial customers past the end of 2003.

In February 2004, Monongahela filed for an injunction in federal court seeking to recover, in retail rates, its costs of purchasing power in the wholesale market. In May 2004, the court partially granted Monongahela’s request, ruling that the Ohio legislation adopted in 1999 to restructure the electric utility industry was unconstitutional to the extent it did not permit Monongahela to make a claim with PUCO that its rates are confiscatory. Monongahela requested reconsideration of the court’s order, which the court partially granted by retaining jurisdiction over this matter. PUCO initiated a proceeding in compliance with the federal court’s directive. In June 2004, Monongahela filed its application for rate relief, which PUCO denied in December 2004

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