LOGO

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification Number
1-267	ALLEGHENY ENERGY, INC.	13-5531602
	(A Maryland Corporation)
	10435 Downsville Pike
	Hagerstown, Maryland 21740-1766
	Telephone (301) 790-3400

333-72498	ALLEGHENY ENERGY SUPPLY	23-3020481
	COMPANY, LLC
	(A Delaware Limited Liability Company)
	4350 Northern Pike
	Monroeville, Pennsylvania 15146-2841
	Telephone (412) 858-1600

1-5164	MONONGAHELA POWER COMPANY	13-5229392
	(An Ohio Corporation)
	1310 Fairmont Avenue
	Fairmont, West Virginia 26554
	Telephone (304) 366-3000

1-3376-2	THE POTOMAC EDISON COMPANY	13-5323955
	(A Maryland and Virginia Corporation)
	10435 Downsville Pike
	Hagerstown, Maryland 21740-1766
	Telephone (301) 790-3400

1-255-2	WEST PENN POWER COMPANY	13-5480882
	(A Pennsylvania Corporation)
	800 Cabin Hill Drive
	Greensburg, Pennsylvania 15601
	Telephone (724) 837-3000

0-14688	ALLEGHENY GENERATING COMPANY	13-3079675
	(A Virginia Corporation)
	10435 Downsville Pike
	Hagerstown, Maryland 21740-1766
	Telephone (301) 790-3400

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

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

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

Allegheny Energy, Inc.	Yes x	No ¨
Allegheny Energy Supply Company, LLC	Yes ¨	No x
Monongahela Power Company	Yes ¨	No x
The Potomac Edison Company	Yes ¨	No x
West Penn Power Company	Yes ¨	No x
Allegheny Generating Company	Yes ¨	No x

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

Registrant	Title of each class	Name of exchange on which registered
Allegheny Energy, Inc.	Common Stock, $1.25 par value	New York Stock Exchange Chicago Stock Exchange Pacific Stock Exchange

Monongahela Power Company	Cumulative Preferred Stock, $100 par value: 4.40 percent 4.50 percent, Series C	American Stock Exchange American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Allegheny Generating Company	Common Stock, $1.00 par value	None


	Aggregate market value of voting and non-voting common equity held by nonaffiliates of the registrants at June 30, 2003	Number of shares of common stock of the registrants outstanding at June 30, 2003

Allegheny Energy, Inc.	$1,072,943,406	126,975,551 ($1.25 par value)

Monongahela Power Company	None. (a)	5,891,000 ($50 par value)

The Potomac Edison Company	None. (a)	22,385,000 ($.01 par value)

West Penn Power Company	None. (a)	24,361,586 (no par value)

Allegheny Generating Company	None. (b)	1,000 ($1.00 par value)

Allegheny Energy Supply Company, LLC	None. (c)	(d)

(a)

All such common stock is held by Allegheny Energy, Inc., the parent company.

(b)

All such common stock is held by its parent companies, Monongahela Power Company and Allegheny Energy Supply Company, LLC.

(c)

As of June 30, 2003, ML IBK Positions, Inc. owned 1.974 percent of the ownership interests in Allegheny Energy Supply Company, LLC and Allegheny Energy, Inc. held the remainder. See ITEM 3. LITIGATION.

(d)

The registrant is a limited liability company, the interests in which are not represented by shares.

GLOSSARY

The following abbreviations and terms are used in this report to identify Allegheny Energy, Inc. and its subsidiaries:

ACC		Allegheny Communications Connect, Inc., a subsidiary of Allegheny Ventures.

AE		Allegheny Energy, Inc., a diversified utility holding company.

AE Supply		Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of Allegheny Energy, Inc., also a holding company.

AESC		Allegheny Energy Service Corporation, a wholly owned subsidiary of Allegheny Energy, Inc.

AGC		Allegheny Generating Company, an unregulated generation unit of Allegheny Energy Supply Company, LLC.

Allegheny		Allegheny Energy, Inc. together with its consolidated subsidiaries.

Allegheny Ventures		Allegheny Ventures, Inc., a nonutility, unregulated subsidiary of Allegheny Energy, Inc.

Distribution Companies		Collectively, Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company. The Distribution Companies do business as Allegheny Power.

Green Valley Hydro		Green Valley Hydro, LLC, a subsidiary of Allegheny Energy, Inc.

MGS		Mountaineer Gas Services, Inc., a subsidiary of Mountaineer Gas Company.

Monongahela		Monongahela Power Company, a regulated subsidiary of Allegheny Energy, Inc.

Mountaineer		Mountaineer Gas Company, a subsidiary of Monongahela Power Company.

Potomac Edison		The Potomac Edison Company, a regulated subsidiary of Allegheny Energy, Inc.

West Penn		West Penn Power Company, a regulated subsidiary of Allegheny Energy, Inc.

WVP		West Virginia Power, a division of Monongahela Power Company.

II.

The following abbreviations and acronyms are used in this report to identify entities and terms relevant to Allegheny’s business and operations:

CAAA		Clean Air Act Amendments of 1990

CDWR		California Department of Water Resources

Clean Air Act		Clean Air Act of 1970

CWA		Clean Water Act

EPA		United States Environmental Protection Agency

EPACT		National Energy Policy Act of 1992

FERC		Federal Energy Regulatory Commission (an independent commission within the Department of Energy)

EWG		Exempt wholesale generator

KWh		Kilowatt-hour

MW		Megawatt

MWh		Megawatt-hour

NSR		The New Source Performance Review Standards, or “New Source Review” applicable to facilities deemed “new” sources of emissions

OVEC		Ohio Valley Electric Corporation

PJM		PJM Interconnection, L.L.C., a regional transmission organization

PJM West		The commonly used name of the western extension of PJM Interconnection, L.L.C.

PLR		Provider-of-last-resort

PUHCA		Public Utility Holding Company Act of 1935, as amended

PURPA		Public Utility Regulatory Policies Act of 1978

RTO		Regional Transmission Organization

SEC		U.S. Securities and Exchange Commission

T&D		Transmission and Distribution

LOGO

CONTENTS

		Page
PART I:

ITEM 1.	Business	1
	Where You Can Find More Information	4
	Recent Events	4
	Previous Business Model	4
	Challenges Arising in 2002	5
	Continuing Challenges	7
	Allegheny’s Response	7
	Special Note Regarding Forward-Looking Statements	12
	Risk Factors	13
	Allegheny’s Sales and Revenues	31
	Generation and Marketing Revenues	31
	Regulated Electric Sales and Revenues	31
	Regulated Natural Gas Sales and Revenues	33
	Unregulated Services Revenues	33
	Construction and Other Capital Expenditures	34
	Electric Facilities	36
	Allegheny Map	39
	Fuel, Power, and Resource Supply	40
	Rate Matters	44
	Regulatory Framework Affecting Allegheny	46
	Federal Regulation	46
	State Legislation and Regulatory Developments	49
	Allegheny’s Competitive Actions	53
	Employees	58
	Environmental Matters	58
	Air Standards	58
	Water Standards	60
	Hazardous and Solid Wastes	63
	Penalties and Noncompliance	63
	Research and Development	63

ITEM 2.	Properties	64

ITEM 3.	Legal Proceedings	65

ITEM 4.	Submission of Matters to a Vote of Security Holders	71

PART II:

ITEM 5.	Market for the Registrants’ Common Equity and Related Stockholder Matters	73

ITEM 6.	Selected Financial Data	75
	Allegheny Energy, Inc.	76
	Allegheny Energy Supply Company, LLC	77
	Monongahela Power Company	78
	The Potomac Edison Company	79
	West Penn Power Company	80
	Allegheny Generating Company	81

CONTENTS (cont’d.)

		Page

ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	82
	Allegheny Energy, Inc.	83
	Allegheny Energy Supply Company, LLC	114
	Monongahela Power Company	136
	The Potomac Edison Company	147
	West Penn Power Company	156
	Allegheny Generating Company	165

ITEM 7A.	Quantitative and Qualitative Disclosure About Market Risk	170
	Allegheny Energy, Inc.	170
	Allegheny Energy Supply Company, LLC	174
	Monongahela Power Company	178
	The Potomac Edison Company	179
	West Penn Power Company	180
	Allegheny Generating Company	181

ITEM 8.	Financial Statements and Supplementary Data	182
	Allegheny Energy, Inc.	183
	Allegheny Energy Supply Company, LLC	248
	Monongahela Power Company	293
	The Potomac Edison Company	327
	West Penn Power Company	352
	Allegheny Generating Company	376

ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	400

PART III:

ITEM 10.	Directors and Executive Officers of the Registrants	400

ITEM 11.	Executive Compensation	407

ITEM 12.	Security Ownership of Certain Beneficial Owners and Management	424

ITEM 13.	Certain Relationships and Related Transactions	425

ITEM 14.	Controls and Procedures	425

PART IV:

ITEM 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	429

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.		430

SIGNATURES		431

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

In 2002, AE aligned its businesses into two segments:

The Generation and Marketing segment comprises our power generation operations, which are generally unregulated (other than Monongahela’s West Virginia jurisdictional generating assets), and our power marketing activities.

The Delivery and Services segment comprises our regulated electric and natural gas transmission and distribution (T&D) operations and includes other unregulated operations not related to power generation and T&D.

The Generation and Marketing Segment

Our principal companies and operations in this segment are:

AE Supply;

Allegheny Generating Company (AGC); and

The West Virginia jurisdictional generating assets of Monongahela. Monongahela generates electricity for its West Virginia customers.

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

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

The Delivery and Services Segment

Our principal companies in this segment are:

The Potomac Edison Company (Potomac Edison), West Penn Power Company (West Penn), and Monongahela (excluding its West Virginia jurisdictional generating assets). Each of these companies is a regulated electric public utility company;

Mountaineer Gas Company (Mountaineer). Mountaineer is a regulated public utility natural gas company and a subsidiary of Monongahela; and

Allegheny Ventures, Inc. (Allegheny Ventures). Allegheny Ventures is a nonutility, unregulated subsidiary of AE.

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

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

Generation and Marketing Segment

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

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

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

Delivery and Services Segment

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

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

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

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

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

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

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

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

Allegheny Communications Connect, Inc. (ACC); and

Allegheny Energy Solutions, Inc. (AE Solutions).

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

Intersegment Services

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

Where You Can Find More Information

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

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

RECENT EVENTS

Previous Business Model

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

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

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

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

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

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

Challenges Arising in 2002

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

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

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

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

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

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

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

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

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

Continuing Challenges

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

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

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

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

Allegheny’s Response

Upon re-examining its business model and structure, Allegheny has adopted a long-term strategy of focusing on the core generation and T&D businesses in which it has been historically engaged. Allegheny will

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

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

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substantial senior management changes;

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completion of key financing transactions;

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exiting from Western energy markets;

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refocusing trading activities;

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asset sales;

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restructuring and cost-reducing initiatives; and

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improving internal controls and reporting.

Substantial Senior Management Changes

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

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

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

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

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

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

Completion of Key Financing Transactions

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

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

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

Exiting from Western Energy Markets

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

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

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

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

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

Refocusing Trading Activities

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

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

Asset Sales

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

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

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

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

Restructuring and Cost-Reducing Initiatives

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

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

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

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

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

Improving Internal Controls and Reporting

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

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:

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regulation and the status of retail generation service supply competition in states served by the Distribution Companies;

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the closing of various agreements;

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execution of restructuring activity and liquidity enhancement plans;

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results of litigation;

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financing requirements and plans to meet those requirements;

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demand for energy and the cost and availability of inputs;

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demand for products and services;

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capacity purchase commitments;

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results of operations;

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capital expenditures;

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regulatory matters;

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internal controls and procedures and outstanding financial reporting obligations;

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accounting issues; and

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stockholder rights plan.

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

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

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execution of restructuring activity and liquidity enhancement plans;

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complications or other factors that render it difficult or impossible to obtain necessary lender consents or regulatory authorizations on a timely basis;

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general economic and business conditions;

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changes in access to capital markets;

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the continuing effects of global instability, terrorism, and war;

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changes in industry capacity, development, and other activities by Allegheny’s competitors;

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changes in the weather and other natural phenomena;

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changes in technology;

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changes in the price of power and fuel for electric generation;

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changes in the underlying inputs, including market conditions, and assumptions used to estimate the fair values of commodity contracts;

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changes in laws and regulations applicable to Allegheny, its markets, or its activities;

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environmental regulations;

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the loss of any significant customers and suppliers;

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the effect of accounting policies issued periodically by accounting standard-setting bodies;

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additional collateral calls; and

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changes in business strategy, operations, or development plans.

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:

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risks unique to us in our current circumstances, such as the risks described under “Risks Related to Trading Market Exposures”, “Risks Associated with Our Capital Structure and Capital Requirements”, “Risks Related to our Internal Controls and Procedures and to our Business Model Transition”, and “Risks Related to Legal Proceedings”;

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risks that currently face us and similarly-situated companies in light of recent events and trends, such as the risks described under “Risks Associated with Competition”, “Other Risks Associated with Our Business”, “Risks Associated with Regulation”, “Risks Related to our Reliance on Other Companies” and “Risks Associated with Environmental Regulation”; and

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risks that generally affect us and similarly-situated companies, such as the risks described under “Risks Associated with the Capital-Intensive Nature of our Business.”

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

RISKS RELATED TO TRADING MARKET EXPOSURES

Our cash position is highly vulnerable to market volatility.

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

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

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

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

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

Our trading portfolio exposes us to counterparty credit risks.

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

RISKS ASSOCIATED WITH OUR CAPITAL STRUCTURE

AND CAPITAL REQUIREMENTS

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

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

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

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the delay in our filing audited financial statements;

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delays in satisfying other SEC reporting requirements;

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our ineligibility to avail ourselves of the “shelf” registration process until we have been current in our SEC filings for the required time period;

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equity ratios below the minimum levels required under our key PUHCA financing authorizations;

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potential concerns regarding our internal controls;

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the covenants in our Borrowing Facilities and in the indenture for the debt securities underlying our convertible preferred securities constrain our financing activities;

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capital market volatility due to geopolitical and economic factors;

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current credit ratings below investment grade;

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our overall financial condition; and

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past violations of covenants under our Borrowing Facilities and commodity contracts.

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

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

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

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

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

1. Facilities at AE Supply:

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A $987.7-million credit facility at AE Supply, of which $893.4 million is secured by substantially all the assets of AE Supply. Borrowings under the facility bear interest at a LIBOR-based rate plus a margin of six percent or a designated money center bank’s base rate plus a margin of five percent on the secured portion. The margin on the unsecured portion is 10.5 percent. This facility requires amortization payments of $23.6 million in September 2004 and $117.8 million in December 2004, and matures in April 2005;

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A $470-million credit facility at AE Supply, of which $420 million was committed and is outstanding and $50 million is no longer committed, and which is secured by substantially all the assets of AE Supply. Borrowings under the facility bear interest at a LIBOR-based rate plus a margin of six percent or a designated money center bank’s base rate plus a margin of five percent. This facility requires an amortization payment of $250.0 million in December 2003, and payment of the balance in September 2004;

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A $270.1-million credit facility related to construction financing for AE Supply’s new facility in Springdale, Pennsylvania that is secured by a combination of that facility and the other assets of AE Supply. Borrowings under the facility bear interest at a LIBOR-based rate plus a margin of six percent or a designated money center bank’s base rate plus a margin of five percent on the secured portion. The margin on the unsecured portion is 10.5 percent. The facility requires amortization payments of $6.4 million in September 2004 and $32.2 million in December 2004, and matures in April 2005;

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

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A $305-million unsecured credit facility under which AE, Monongahela, and West Penn are the designated borrowers, and AE has borrowed the full facility amount. Borrowings under this facility bear interest at a LIBOR-based rate, plus five percent or a designated money center bank’s base rate plus four percent. This facility amortizes at the rate of $7.5 million per quarter, starting with the first quarter of 2003, and matures in April of 2005; and

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A $10-million unsecured credit facility at Monongahela. This facility bears interest at a LIBOR-based rate plus four percent and matures in December 2003.

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

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

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

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

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

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borrow funds;

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incur liens and guarantee indebtedness;

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sell assets;

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enter into a merger or other change of control transaction;

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make investments;

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prepay indebtedness;

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amend contracts;

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pay dividends and other distributions on equity securities; and

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operate our business by requiring us to adhere to an agreed business plan.

AGC’s indenture also restricts additional secured borrowings.

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

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

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

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

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fixed-charge coverage ratio of 1.10 through the first quarter of 2005 and

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maximum debt-to-capital ratio of 75 percent in 2003 and 72 percent from 2004 through the first quarter of 2005.

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

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

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minimum earnings before interest, taxes, depreciation, and amortization (EBITDA), as defined under the Borrowing Facilities, of $100 million year-to-date by June 30, 2003, increasing to $304 million by December 31, 2003, and to $430 million in stated increments for the 12 months ending each quarter through the first quarter of 2005;

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interest coverage ratio of not less than 0.75 year-to-date by June 30, 2003, increasing to 1.10 by December 31, 2003, and to 1.50 by December 31, 2004, through the first quarter of 2005; and

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minimum net worth of $800 million as of June 30, 2003 (subject to downward adjustment under specified circumstances).

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

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

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

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

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

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

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

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75 percent of the proceeds of sales of assets of AE and subsidiaries other than AE Supply and its subsidiaries, up to $400 million, and 100 percent thereafter;

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75 percent of the proceeds of sales of assets of AE Supply and its subsidiaries up to $800 million, and 100 percent thereafter, excluding AE Supply’s new facility in Springdale, Pennsylvania;

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100 percent of the proceeds of any sale of AE Supply’s new facility in Springdale, Pennsylvania;

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100 percent of the net proceeds of debt issuances (excluding specified exemptions, including an exemption of up to $50 million for the Distribution Companies and an exemption for refinancings meeting certain criteria);

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100 percent of net proceeds from equity issuances;

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50 percent of AE and its subsidiaries’ (excluding AE Supply’s and its subsidiaries’) excess cash flow (as defined under the Borrowing Facilities); and

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50 percent of AE Supply’s excess cash flow (as defined under the Borrowing Facilities).

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

Our liquidity position adversely affects our operations.

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

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

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

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

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

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

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

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

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

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incorrectly valuing assets;

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retaining liabilities; and

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diverting management and other resources to asset sale transactions and away from continuing operations.

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

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

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

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workforce reductions;

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the wind-down and relocation of our energy trading operations; and

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the suspension and discontinuation of generating facility construction.

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

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losing the assistance of experienced personnel;

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compromising the loyalty of retained employees;

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incurring severance, pension, and other restructuring costs;

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diverting management resources to the implementation of restructurings and away from continuing operations;

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failing to maintain sufficient personnel to manage operational challenges; and

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failing to realize anticipated net cost reductions.

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

RISKS RELATED TO OUR INTERNAL CONTROLS AND

PROCEDURES AND TO OUR BUSINESS MODEL TRANSITION

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

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

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

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

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

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

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

RISKS ASSOCIATED WITH COMPETITION

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

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

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

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

OTHER RISKS ASSOCIATED WITH OUR BUSINESS

Seasonal fluctuations pressure our facilities and operating results.

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

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

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

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

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

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

RISKS ASSOCIATED WITH REGULATION

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

RISKS ASSOCIATED WITH THE CAPITAL-INTENSIVE

NATURE OF OUR BUSINESS

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

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

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

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

RISKS RELATED TO LEGAL PROCEEDINGS

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

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

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

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

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

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

Our Borrowing Facilities limit our ability to settle litigation.

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

RISK RELATED TO OUR RELIANCE ON OTHER COMPANIES

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

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

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

RISKS ASSOCIATED WITH ENVIRONMENTAL REGULATION

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We could incur additional substantial liabilities for environmental remediation.

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

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

ALLEGHENY’S SALES AND REVENUES

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

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

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

The Generation and Marketing Segment

Generation and Marketing Revenues

(In Millions)		2002			2001			Percent Change
Generation & Marketing Revenues		$	945.3		$	1,928.1		(51.0	)%

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

The Delivery and Services Segment

Regulated Electric Sales and Revenues

	2002		2001		Percent Change
Regulated Kilowatt-hour Sales:
Residential		15,152		14,454	4.8	%
Commercial		10,059		9,616	4.6	%
Industrial		20,131		19,884	1.2	%
Wholesale and Other		1,443		1,502	(3.9	)%
Total Regulated Kilowatt-hour Sales:		46,785		45,456	2.9	%

Regulated Electric Revenues (In Millions):
Residential	$	1,052.4	$	1,002.1	5.0	%
Commercial		594.3		554.0	7.3	%
Industrial		803.8		772.3	4.1	%
Wholesale and Other		39.7		66.6	(40.4	)%
Total Regulated Electric Revenues:	$	2,490.2	$	2,395.0	4.0	%

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

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

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

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

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

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

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

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

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

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

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

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

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

Regulated Natural Gas Sales and Revenues

	2002		2001		Percent Change
Regulated Natural Gas—Bcf Sales
Residential		17.6		18.8	(6.4	)%
Commercial		8.9		12.3	(27.6	)%
Industrial		.3		.7	(57.1	)%
Wholesale		.3		.8	(62.5	)%
Transportation and Other		36.6		31.3	16.9	%
Total Regulated Natural Gas—Bcf Sales		63.7		63.9	(.3	)%

Regulated Natural Gas Revenues (In Millions)
Residential	$	142.3	$	139.1	2.3	%
Commercial		65.2		79.8	(18.3	)%
Industrial		1.8		4.1	(56.1	)%
Wholesale and Other		1.8		4.1	(56.1	)%
Transportation and Other		10.5		8.0	31.3	%
Total Regulated Natural Gas Revenue		221.6	$	235.1	(5.7	)%

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

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

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

Unregulated Services Revenues

(In Millions)		2002			2001			Percent Change
Unregulated Services Revenues		$	643.5		$	139.5		361.3	%

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

CONSTRUCTION AND OTHER CAPITAL EXPENDITURES

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

	2002		2003		2004
(In Millions)	(Actual)		(Estimated)
AE Supply
Total Generation	$	205.2	$	176.7	$	103.4
Environmental Portion		157.0		51.2		71.1

Monongahela
Total Generation		42.9		18.4		27.2
Environmental Portion		39.1		12.5		19.8

AGC
Total Generation		1.4		9.7		6.0
Environmental Portion		—		—		—

Total Generation and Marketing Construction Expenditures	$	249.5	$	204.8	$	136.6

Potomac Edison*
T&D		45.7		59.1		59.8
Environmental		—		—		—

West Penn*
T&D		57.9		45.4		58.9
Environmental		—		—		—

Monongahela*
T&D		49.8		50.6		45.2
Environmental		—		—		—

Allegheny Ventures		0.4		—		—

AESC		0.4		2.1		3.8

Total Delivery and Services Construction Expenditures	$	154.2	$	157.2	$	167.7

Total Construction Expenditures	$	403.7	$	362.0	$	304.3

Includes allowance for funds used during construction (AFUDC), which is a non-cash cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. AFUDC was as follows for 2002 (in millions): Monongahela $3.1, Potomac Edison $(0.1), and West Penn, $0.6.

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

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

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

Recently Completed Projects

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

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

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

Discontinued Projects

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

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

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

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

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

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

The Delivery and Services Segment

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

ELECTRIC FACILITIES

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

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

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

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

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

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

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

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

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

ALLEGHENY STATIONS

(as of December 31, 2002)

Maximum Generating Capacity (MW) (a)

			Regulated		Unregulated
Allegheny Station			Monongahela		AE Supply and Other		Service Commencement Dates (b)
	Units	Total
Coal-Fired (Steam):
Albright (Albright, WV)	3	292	184		108		1952-4
Armstrong (Adrian, PA)	2	356			356		1958-9
Conemaugh (c) (New Florence, PA)	2	83			83	(c)	2001
Fort Martin (Maidsville, WV)	2	1,107	212		895		1967-8
Harrison (Haywood, WV)	3	1,961	417		1,544		1972-4
Hatfield’s Ferry (Masontown, PA)	3	1,710	400		1,310		1969-71
Hunlock (d) (Hunlock Creek, PA)	1	24			24	(d)	2000(d)
Mitchell (Courtney, PA)	1	288			288		1963
Ohio Valley Electric Corp. (e) (Chelsea, OH) (Madison, IN)	11	280	78	(e)	202	(e)
Pleasants (Willow Island, WV)	2	1,300	277		1,023		1979-80
Rivesville (Rivesville, WV)	2	142	121		21		1943-51
R. Paul Smith (Williamsport, MD)	2	116			116		1947-58
Willow Island (Willow Island, WV)	2	243	207		36		1949-60

Gas-Fired:
AE Nos. 1 & 2 (Springdale, PA)	2	88			88		1999
AE Nos. 8 & 9 (Gans, PA)	2	88			88		2000
AE Nos. 12 & 13 (Chambersburg, PA)	2	88			88		2001
Buchanan (f) (Oakwood, VA)	2	43			43		2002
Gleason (Gleason, TN)	3	526			526		2001
Hunlock CT (d) (Hunlock Creek, PA)	1	22			22	(d)	2000
Lincoln (Manhattan, IL)	8	672			672		2001
Wheatland (Wheatland, IN)	4	512			512		2001

Oil-Fired Steam:
Mitchell (g) (Courtney, PA)	1	82			82		1948-49

Pumped-Storage and Hydro:
Bath County (h) (Warm Springs, VA)	6	960	221	(h)	739	(h)	1985; 2001
Lake Lynn (i) (Lake Lynn, PA)	4	52			52		1926
Potomac Edison Hydroelectric (i)	21	6			6		Various

Total Allegheny-Owned Capacity	92	11,041	2,117		8,924

PURPA GENERATION (j)

Maximum Generating Capacity (MW)

		Allegheny Company Purchaser
PURPA Generation Project	Project Total	Monongahela	Potomac Edison		West Penn	AE Supply And Other	PURPA Contract Termination Date

Coal-Fired: Steam
AES Beaver Valley (Monaca, PA)	125				125		12/13/2016
Grant Town (Grant Town, WV)	80	80					05/28/2028
West Virginia University (Morgantown, WV)	50	50					04/17/2027
AES Warrior Run (k) (Cumberland, MD)	180		180	(k)			02/10/2030

Hydro:
Allegheny Lock and Dam 5 (Freeport, PA)	6				6		09/30/2034
Allegheny Lock and Dam 6 (Freeport, PA)	7				7		06/30/2034
Hannibal Lock and Dam (New Martinsville, WV)	31	31					06/01/2034

Total Other Capacity	479	161	180		138

Total Allegheny-Owned and PURPA Committed Generating Capacity (a)	11,520	2,278	180		138	8,924

(a)

Nominal maximum generating capacity.

(b)

When more than one year is listed as a commencement date for a particular source, the dates refer to the years in which operations commenced for the different units at that source.

(c)

This figure represents capacity entitlement through ownership of Allegheny Energy Supply Conemaugh, LLC, which owned a 4.86-percent interest in the Conemaugh Generating Station. In June 2003, AE Supply sold its 83-MW share to UGI Development Company, an indirect, wholly-owned subsidiary of UGI.

(d)

This figure represents Allegheny Energy Supply Hunlock Creek’s capacity entitlement through its 50-percent ownership in Hunlock Creek Energy Ventures. AE Supply Hunlock Creek’s access to output at maximum generating capacity is indicated on the table for the steam and natural gas-fired facilities. AE Supply Hunlock Creek’s output is sold exclusively to AE Supply. The Hunlock service commencement date for the coal units refers to the year in which part ownership was acquired by AE.

(e)

This figure represents capacity entitlement through AE’s ownership of OVEC shares.

(f)

AE Supply owns Buchanan Energy Company of Virginia, LLC, which is in equal partnership with Consol Energy, Inc. as owners of Buchanan Generation, LLC. AE Supply operates and dispatches 100 percent of Buchanan Generation’s 86 MW.

(g)

This figure represents capacity of Mitchell Unit 2. Mitchell originally had two oil-fired units, but Mitchell Unit 1 was retired on December 31, 2002.

(h)

This figure represents capacity entitlement through ownership of AGC: 22.97 percent by Monongahela and 77.03 percent by AE Supply.

(i)

AE Supply has a 30-year license for Lake Lynn, effective December 1994. Potomac Edison’s license for hydroelectric facilities Dam No. 4 and Dam No. 5, located in both West Virginia and Maryland will expire November 30, 2024. Potomac Edison has received 30-year licenses, effective January 1994, for the Shenandoah, Warren, Luray, and Newport projects located in Virginia. The FERC accepted Potomac Edison’s surrender of the license for the Harpers Ferry Dam No. 3 and issued an order, effective October 1994. Green Valley Hydro controls 3 MW.

(j)

Generating capacity available through state utility commission-approved arrangements pursuant to PURPA.

(k)

Potomac Edison, as required under the terms of a Maryland Restructuring Settlement, began to offer the 180-MW output of the AES Warrior Run project to the wholesale market beginning July 1, 2000, and will continue to do so for the term of the settlement. Revenue received from the sale reduces the AES Warrior Run Surcharge paid by Maryland customers. AES Warrior Run output is presently being sold to AE Supply under the terms of a three-year contract, which expires December 31, 2004. (See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, for additional information on the AES Warrior Run project and Surcharge.)

LOGO

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

Miles of Transmission and Distribution Lines

and Number of Substations

	Underground	Above- Ground	Total Miles	Total Miles Consisting of 500-Kilovolt (kV) Lines	Number of Transmission and Distribution Substations
Monongahela	538	22,715	23,253	235	340
Potomac Edison	3,959	17,868	21,827	174	277
West Penn	2,265	23,987	26,252	276	679
AGC (a)	0	87	87	87	1
Total	6,762	64,657	71,419	772	1,297

(a)

Total Bath County transmission lines, of which AGC owns an undivided 40 percent interest and Virginia Power and Electric Company owns the remainder.

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

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

FUEL, POWER, AND RESOURCE SUPPLY

Generation and Marketing Segment

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

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

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

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

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

The Delivery and Services Segment

Electric Power

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

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

•

Monongahela. In Ohio, the transition period for residential and small business customers ends on December 31, 2005. The transition period ceases for all other Ohio customers at the end of 2003.

•

Potomac Edison. In Maryland, the transition period for residential customers ends December 31, 2008. The transition period ends December 31, 2004, for commercial and industrial customers. In Virginia, the transition period continues until July 1, 2007.

•

West Penn. The Pennsylvania transition period terminates at the end of 2008 for all customers.

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

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

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

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

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

Distribution Company	State	Percentage of Total 2002 Power Purchases for PLR Obligations from AE Supply by Jurisdiction (a)	Percentage of Total 2002 Power Purchases for PLR Obligations from AE Supply in Aggregate (b)	Termination Date of Power Sale Agreement with AE Supply
Monongahela	Ohio	100 percent	4 percent	December 31, 2005
Potomac Edison	Maryland	100 percent	26 percent	December 31, 2008
Potomac Edison	West Virginia	100 percent	8 percent	December 31, 2017*
Potomac Edison	Virginia	99 percent	8 percent	July 1, 2007
West Penn	Pennsylvania	94 percent	54 percent	December 31, 2008

Pending Public Service Commission of West Virginia (West Virginia PSC) approval because there is no PLR obligation in West Virginia.

(a)

The percentage of total power requirements that each jurisdiction purchases from AE Supply.

(b)

The percentage of AE Supply’s total sales for all PLR load each jurisdiction represents.

Natural Gas Supply

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

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

	Twelve Months Ended December 31, 2002
	Volume (Mmcf)	Percent of Total
MGS-Owned/Controlled Production	1,444	5.3
Consumers Gas Utility Company	3	—
Hope Gas, Inc.	59	—
Cabot Oil & Gas Marketing Corporation	791	3
Energy Corporation of America	2,694	10
Other Appalachian Basin Producers/Suppliers	1,712	6.3
AEP Energy Services	500	1.8
Amerada Hess Corporation	610	2.2
Anadarko Energy Services	1,507	5.5
BP/Amoco	3,444	12.7
Cinergy Marketing & Trading, L.P.	1,141	4.2
Conoco, Inc.	1,785	6.6
Coral Energy, L.P.	969	3.6
EnergyUSA-TPC	1,161	4.3
Idacorp Energy, L.P.	1,662	6.1
Marathon Oil Company	200	1
Mirant Americas Energy Marketing, L.P.	1,374	5.1
Noble Gas Marketing, Inc.	2,879	10.6
Occidental Energy Marketing, Inc.	29	—
PG&E Energy Trading-Gas Corporation	672	2.5
Virginia Power Energy Marketing, Inc.	2,486	9.2

Totals	27,122	100

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

Natural Gas 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 Gulf and Columbia Gas to Monongahela’s local distribution facilities in West Virginia.

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

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

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

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

RATE MATTERS

Monongahela

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

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

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

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

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

Potomac Edison

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

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

West Penn

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

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

AGC

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

REGULATORY FRAMEWORK AFFECTING ALLEGHENY

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

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

Federal Regulation

Federal Legislation, Competition, and RTOs

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

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

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

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

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

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

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

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

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

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

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

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

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

PUHCA

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

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

PURPA

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

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

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

Federal Initiatives

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

State Legislation and Regulatory Developments

Maryland

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

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

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

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

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

Ohio

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

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

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

Pennsylvania

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

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

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

Virginia

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

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

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

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

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

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

West Virginia

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

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

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

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

ALLEGHENY’S COMPETITIVE ACTIONS

The Generation and Marketing Segment

AE Supply

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

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

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

Long-Term Power Sales Agreements

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

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

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

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

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

Terminated and Assigned Long-Term Contracts

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

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

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

Certain Purchase and Transportation Contracts

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

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

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

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

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

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

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

The Delivery and Services Segment

Distribution Companies

Retail Access

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

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

Participation in RTOs

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

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

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

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

Natural Gas Distribution

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

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

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

Allegheny Ventures

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

In December 2001, AE Solutions entered into an agreement to provide design, construction, and installation services for seven natural gas-fired turbine generators for the SMEPA. The seven units, with a combined output of approximately 450 MW, will be located at three sites in southern Mississippi. The units will be owned by SMEPA. Construction started in May 2002, with installation of all of the units to be completed by May 2006.

EMPLOYEES

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

ENVIRONMENTAL MATTERS

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

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

Air Standards

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

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

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

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

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

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

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

Pending Initiatives

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

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

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

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

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

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

Water Standards

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

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

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

TMDL Program

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

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

Cooling Water Intake

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

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

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

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

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

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

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

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

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

Other Issues

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

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

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

Hazardous and Solid Wastes

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

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

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

Penalties and Noncompliance

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

RESEARCH AND DEVELOPMENT

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

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

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

ITEM 2.

PROPERTIES

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

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

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

ITEM 3.

LEGAL PROCEEDINGS

Settlement of Litigation Related to Power Supply Contracts with CDWR

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

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

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

Putative Class Actions Under California Statutes

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

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

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

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

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

Nevada Power Contracts

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

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

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

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

Nevada Power Company and Sierra Pacific Resources, Inc. v.

Merrill Lynch & Co., Merrill Lynch Capital Services, Inc.,

Allegheny Energy, Inc., and Allegheny Energy Supply Company, LLC

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

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

Litigation Against Merrill Lynch

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

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

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

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

Putative Shareholder, Derivative, and Benefit Plan Class Actions

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

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

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

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

Claims Related to Alleged Asbestos Exposure

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

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

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

Comprehensive Environmental Response,

Compensation, and Liability Act of 1980 (CERCLA) Claims

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

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

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

Clean Air Act and CAAA Matters

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

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

Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in most cases. AE believes that its subsidiaries’ generating facilities have been operated in accordance with the Clean Air Act and the rules implementing it. The experience of other energy companies, however, suggests that in recent years, the EPA has narrowed its view regarding the scope of the definition of “routine maintenance” under its rules, thereby broadening the range of actions subject to compliance with new source review standards. Under previous EPA interpretations, these same actions did not trigger application of

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

Belmont Substation

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

Suits Related to Gleason Generating Facility

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

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

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

SEC Subpoena

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

CFTC Subpoenas

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

EPMI Adversary Proceeding

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

Ordinary Course of Business

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

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

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

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

Nominees for Director	Votes For	Votes Withheld
Frank A. Metz, Jr.	104,904,846	3,683,708
Alan J. Noia	104,920,548	3,668,006
Steven H. Rice	105,007,960	3,580,594

The following indicates the results on the other votes:

Shareholder Action Items Referenced Above	Votes For	Votes Against	Abstentions	Total
(2)	102,047,599	5,712,526	817,819	108,577,944
(3)	46,991,073	39,321,399	2,515,302	88,827,774
(4)	7,057,999	77,659,490	4,115,697	88,833,186
(5)	34,899,562	51,684,756	2,239,310	88,823,628
(6)	29,051,930	57,517,191	2,257,807	88,826,928
(7)	11,231,186	74,114,914	3,491,091	88,837,191
(8)	24,523,230	61,428,886	2,884,372	88,836,488
(9)	48,143,789	38,588,132	2,094,949	88,826,870

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

2003 Matters

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

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

Votes For		Votes Against		Abstentions		Total
65,697,385		13,147,511		1,965,860		80,810,756

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

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

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

PART II

ITEM 5.

MARKET FOR THE REGISTRANTS’ COMMON EQUITY AND RELATED SHAREHOLDER MATTERS

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

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

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

	2002							2001
	Dividend	High		Low		Close		Dividend	High		Low		Close
1^st Quarter	43 cents	$	41.35	$	32.26	$	41.35	43 cents	$	48.22	$	41.06	$	46.26
2^nd Quarter	43 cents	$	43.53	$	25.75	$	25.75	43 cents	$	54.79	$	45.74	$	48.25
3^rd Quarter	43 cents	$	26.95	$	11.73	$	13.10	43 cents	$	48.82	$	35.84	$	36.70
4^th Quarter	None	$	12.00	$	3.80	$	7.56	43 cents	$	39.90	$	33.25	$	36.22

	2003
	Dividend	High		Low		Close
1^st Quarter	None	$	10.30	$	4.82	$	6.21
2^nd Quarter	None	$	9.69	$	6.26	$	8.45

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

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

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

AE Supply

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

AGC

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

Monongahela

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

Potomac Edison

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

West Penn

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

Recent Sales of Unregistered Securities

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

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

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

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

ITEM 6.

SELECTED FINANCIAL DATA

		Page No.
Allegheny		76

AE Supply		77

Monongahela		78

Potomac Edison		79

West Penn		80

AGC		81

Allegheny Energy, Inc.

ITEM 6. SELECTED FINANCIAL DATA

ALLEGHENY ENERGY, INC.

Year ended December 31 (a)	2002			2001		2000		1999		1998
(In millions, except per share data)
Total operating revenues (b)	$	2,988.5		$	3,425.1	$	2,653.1	$	2,808.4	$	2,576.4
Cost of revenues		1,701.2			1,116.8		832.7		1,096.0		933.4
Other operating expenses		1,786.4			1,348.3		1,099.3		1,073.4		1,035.1
Consolidated income (loss) before extraordinary charge and cumulative effect of accounting change (c) (d)	$	(502.2	)	$	448.9	$	313.7	$	285.4	$	263.0
Earnings per share
Consolidated income (loss) before extraordinary charge and cumulative effect of accounting change—basic	$	(4.00	)	$	3.74	$	2.84	$	2.45	$	2.15
—diluted	$	(4.00	)	$	3.73	$	2.84	$	2.45	$	2.15
Dividends declared per share	$	1.29		$	1.72	$	1.72	$	1.72	$	1.72

Short-term debt	$	1,132.0		$	1,238.7	$	722.2	$	641.1	$	258.8
Long-term debt due within one year		257.2			353.1		160.2		189.7		—
Debentures, notes and bonds (e)		3,662.2			—		—		—		—

Total short-term obligations	$	5,051.4		$	1,591.8	$	882.4	$	830.8	$	258.8

Long-term debt and QUIDS (e)	$	115.9		$	3,200.4	$	2,559.5	$	2,254.5	$	2,179.3
Capital leases		39.1			35.3		34.4		.9		1.1

Total long-term obligations	$	155.0		$	3,235.7	$	2,593.9	$	2,255.4	$	2,180.4

Total assets	$	10,600.3		$	11,032.5	$	7,697.0	$	6,852.4	$	6,535.2

Notes:

(a)

See Notes 2, 3, 4, 5, 6, 7, 8, 14, 26, and 27 to the Consolidated Financial Statements for factors and transactions that affect trends and comparability of financial data for the years 2000, 2001, 2002, and subsequent to December 31, 2002.

(b)

Certain amounts for years prior to 2002 have been reclassified for comparative purposes, including the effects of Emerging Issues Task Force (EITF) Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” as discussed in Note 4 to the consolidated financial statements.

(c)

In 1998 and 1999, Allegheny recorded extraordinary charges of $275.4 million and $17.0 million, net of income taxes, respectively, as a result of discontinuing the application of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” as a result of deregulation plans adopted in Pennsylvania for West Penn and Maryland for Potomac Edison.

(d)

In 1999, West Penn recorded an extraordinary charge of $10.0 million, net of income taxes, as a loss on reacquired debt.

(e)

As discussed in Note 3, $3,662.2 million of long-term debt was reclassified as short-term as a result of debt covenant violations.

Allegheny Energy Supply Company, LLC

ITEM 6. SELECTED FINANCIAL DATA

ALLEGHENY ENERGY SUPPLY COMPANY, LLC AND SUBSIDIARIES

Year ended December 31 (a)	2002			2001		2000		1999 (b)
(In millions)
Total operating revenues (c)	$	683.0		$	1,657.7	$	900.8	$	140.9
Cost of revenues		615.9			660.9		469.3		100.3
Consolidated (loss) income before cumulative effect of accounting change	$	(583.7	)	$	234.8	$	75.5	$	9.5

Short-term debt		797.0			685.9		165.8		—
Long-term debt due within one year		114.4			219.1		—		—
Debentures, notes and bonds (d)	$	1,747.8		$	—		—		—

Total short-term obligations	$	2,659.2		$	905.0	$	165.8		—

Long-term debt (d)	$	91.7		$	1,130.0	$	563.4	$	356.2
Capital leases		—			—		—		—

Total long-term obligations	$	91.7		$	1,130.0	$	563.4	$	356.2

Total assets	$	5,505.3		$	5,838.2	$	2,607.6	$	1,375.5

Notes:

(a)

See notes 2, 3, 4, 5, 6, 7, 8, 23, and 24 to the consolidated financial statements for factors and transactions that affect trends and comparability of financial data for the years 2000, 2001, 2002 and subsequent to December 31, 2002.

(b)

From November 18, 1999 inception to December 31, 1999.

(c)

Certain amounts for years prior to 2002 have been reclassified for comparative purposes, including the effects of Emerging Issues Task Force (EITF) Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts,” as discussed in Note 4 to the consolidated financial statements.

(d)

As discussed in Note 3, $1,747.8 million of long-term debt was reclassified as short-term as a result of debt covenant violations.

Monongahela Power Company And Subsidiaries

ITEM 6. SELECTED FINANCIAL DATA

MONONGAHELA POWER COMPANY, INC.

Year ended December 31 (a)	2002		2001		2000		1999 (b)		1998
(In millions)
Total operating revenues	$	917.0	$	937.7	$	828.0	$	673.3	$	645.1
Consolidated income before extraordinary charge and Cumulative effect of accounting Change	$	33.7	$	89.5	$	94.6	$	92.3	$	82.4

Short-term debt	$	—	$	14.3	$	37.0	$	—	$	49.0
Long-term debt due within one year		65.9		30.4		100.0		65.0		—
Debentures, notes and bonds (c)		690.1		—		—		—		—

Total short-term obligations	$	756.0	$	44.7	$	137.0	$	65.0	$	49.0

Long-term debt and QUIDS (c)	$	28.5	$	784.3	$	606.7	$	503.7	$	453.9
Capital leases		14.3		11.6		11.1		.7		.7

Total long-term obligations	$	42.8	$	795.9	$	617.8	$	504.4	$	456.6

Total assets	$	1,821.1	$	2,017.2	$	2,005.7	$	1,626.4	$	1,519.8

Notes:

(a)

See Notes 2, 3, 4, 5, 6, 8, 10, 12, 19, 20, 23 and 24 to the consolidated financial statements for factors and transactions that affect trends and comparability of financial data for the years 2000, 2001, 2002 and subsequent to December 31, 2002.

(b)

In December 1999, Monongahela Power acquired West Virginia Power for approximately $95 million.

(c)

As discussed in Note 3, $690.1 million of long-term debt was reclassified as short-term as a result of debt covenant violations.

The Potomac Edison Company And Subsidiaries

ITEM 6. SELECTED FINANCIAL DATA

POTOMAC EDISON COMPANY AND SUBSIDIARIES

Year ended December 31 (a)	2002		2001		2000		1999		1998
(In millions)
Total operating revenues	$	870.2	$	864.5	$	827.8	$	753.3	$	737.5
Cost of revenues		610.1		589.7		441.7		291.4		279.2
Other operating expenses		179.7		162.6		232.1		288.9		266.9
Consolidated income before extraordinary charge (b)	$	32.7	$	48.0	$	84.4	$	100.6	$	101.5

Short-term debt	$	—	$	24.2	$	32.9	$	—	$	—
Long-term debt due within one year		—		—		—		75.0		—
Notes and bonds (c)		416.0		—		—		—		—

Total short-term obligations	$	416.0	$	24.2	$	32.9	$	75.0	$	—

Long-term debt and QUIDS (c)	$	—	$	415.8	$	410.0	$	510.3	$	578.8
Capital leases		10.3		9.2		9.9		—		—

Total long-term obligations	$	10.3	$	425.0	$	419.9	$	510.3	$	578.8

Total assets	$	1,161.7	$	1,110.4	$	1,099.0	$	1,613.6	$	1,728.6

Notes:

(a)

See Notes 2, 3, 4, 7 and 16 to the consolidated financial statements for factors and transactions that affect trends and comparability of financial data for the years 2000, 2001, 2002 and subsequent to December 31, 2002.

(b)

In 1999, Potomac Edison recorded extraordinary charges of $17.0 million, net of income taxes, respectively, as a result of discontinuing the application of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” as a result of deregulation plans adopted in Maryland for Potomac Edison.

(c)

As discussed in Note 3, $416.0 million of long-term debt was reclassified as short-term as a result of debt covenant violations.

West Penn Power Company And Subsidiaries

ITEM 6. SELECTED FINANCIAL DATA

WEST PENN POWER COMPANY AND SUBSIDIARIES

Year ended December 31 (a)	2002		2001		2000		1999		1998
(In millions)
Total operating revenues	$	1,153.1	$	1,114.5	$	1,045.6	$	1,354.2	$	1,078.7
Cost of revenues		677.6		633.3		583.0		626.1		388.7
Other operating expenses		316.3		269.1		246.2		462.8		459.0
Consolidated income before extraordinary charge (b) (c)	$	94.0	$	109.8	$	102.4	$	137.6	$	112.6

Short-term debt	$	—	$	—	$	—	$	—	$	55.8
Notes payable to affiliate		—		—		—		—		9.3
Long-term debt due within one year		76.0		103.8		60.2		49.7		—
Notes and bonds (d)		510.2		—		—		—		—

Total short-term obligations		586.2		103.8		60.2		49.7		65.1

Long-term debt and QUIDS (d)	$	—	$	574.6	$	678.3	$	966.0	$	837.7
Capital leases		12.1		12.3		11.3		—		.2

Total long-term obligations	$	12.1	$	586.9	$	689.6	$	966.0	$	837.9

Total assets	$	1,806.1	$	1,775.2	$	1,792.5	$	1,852.7	$	2,887.7

Notes:

(a)

See Notes 2, 3, 4, 6, 16, and 17 to the consolidated financial statements for factors and transactions that affect trends and comparability of financial data for the years 2000, 2001, 2002, and subsequent to December 31, 2002.

(b)

In 1998, West Penn recorded an extraordinary charge of $275.4 million as a result of discontinuing the application of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” as a result of deregulation plans adopted in Pennsylvania.

(c)

In 1999, West Penn recorded an extraordinary charge of $10.0 million, net of income taxes, as a loss on reacquired debt.

(d)

As discussed in Note 3, $510.2 million of long-term debt was reclassified as short-term as a result of debt covenant violations.

Allegheny Generating Company

ITEM 6. SELECTED FINANCIAL DATA

ALLEGHENY GENERATING COMPANY

Year ended December 31	2002		2001		2000		1999		1998
(In millions)
Affiliated operating revenues	$	64.1	$	68.5	$	70.0	$	70.6	$	73.8
Net income	$	18.6	$	20.3	$	21.9	$	21.2	$	22.8
Other operating expenses	$	25.8	$	25.5	$	27.6	$	26.5	$	26.2

Short-term debt	$	55.0	$	—	$	—	$	—	$	—
Long-term debt due within one year		50.0		—		—		—		—
Debentures (a)		99.3		—		—		—		—

Total short-term obligations	$	204.3	$	—	$	—	$	—	$	—

Long-term debt (a)	$	—	$	149.2	$	149.0	$	148.9	$	148.8
Capital leases		—		—		—		—		—

Total long-term obligations	$	—	$	149.2	$	149.0	$	148.9	$	148.8

Total assets	$	597.6	$	591.6	$	602.0	$	620.9	$	639.5

Notes:

(a)

As discussed in Note 2, $99.3 million of long-term debt was reclassified as short-term as a result of debt covenant violations.

ITEM

7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

		Page No.

Allegheny		83

AE Supply		114

Monongahela		136

Potomac Edison		147

West Penn		156

AGC		165

Allegheny Energy, Inc.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

ALLEGHENY ENERGY, INC.

OVERVIEW

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

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

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

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

REVIEW OF OPERATIONS

Critical Accounting Policies and Estimates

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

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

Allegheny Energy, Inc.

majority of Allegheny’s commodity contracts continue to be recorded at their fair value under the FASB’s Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133—an amendment of FASB Statement No. 133,” and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities—an amendment of FASB Statement No. 133” (collectively referred to as SFAS No. 133). At December 31, 2002, the fair value of Allegheny’s commodity contracts represented a net asset position of $429.7 million. Fair values for exchange-traded instruments, principally futures and certain options, are based on actively quoted market prices. In establishing the fair value of commodity contracts that do not have quoted market prices, such as physical contracts, over-the-counter options, and swaps, management makes estimates using available and estimated market data and pricing models, which may change from time to time. Allegheny has several contracts that are unique, which extend to 2010 and beyond, and are valued using proprietary pricing models. Inputs to the models include estimated forward natural gas and electricity prices, interest rates, estimates of market volatility for natural gas and electricity prices, the correlation of natural gas and electricity prices, and other factors such as generating unit availability and location, as appropriate. These inputs require management judgments and assumptions. Allegheny’s models also adjust the fair value of commodity contracts to reflect uncertainty in prices, operational risks related to generating facilities, and risks related to the performance of counterparties. These inputs become more challenging, and the models become less precise, the further into the future these estimates are made. Additionally, various factors, including reduced market liquidity, have significantly affected the merchant energy marketplace during 2002. Market liquidity and the number of creditworthy participants have been dramatically reduced, and trading and origination opportunities have been significantly curtailed within energy markets. Actual effects on Allegheny’s consolidated financial position, cash flows, and results of operations may vary significantly from expected results if the judgments and assumptions underlying those models’ inputs prove to be wrong or the models prove to be unreliable.

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

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

Year	Price Per megawatt-hour (MWh) Peak/Off-Peak		Volume Megawatt (MW)
2003	$	61 / $61	250
2004	$	61 / $60	500
2005	$	61 / $59	750
2006 - 2011	$	61 / $58	800

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

Allegheny Energy, Inc.

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

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

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

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

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

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

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

Allegheny Energy, Inc.

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

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

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

(In millions)	1-Percentage-Point Increase			1-Percentage-Point Decrease
Change in the discount rate:
Pension and OPEB benefit obligation	$	(134.8	)	$	151.0
Net periodic cost-pension and OPEB		(2.2	)		7.0
Change in expected return on plan assets:
Net periodic cost-pension and OPEB		(9.0	)		9.0

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

Allegheny Energy, Inc.

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

Earnings (Loss) Summary

	Consolidated Net (Loss) Income
(In millions, except per share data)
	2002			2001			2000
Delivery and Services	$	84.1		$	187.5		$	162.3
Generation and Marketing		(586.3	)		261.4			151.3

Consolidated (loss) income before extraordinary charge and cumulative effect of accounting change		(502.2	)		448.9			313.6
Extraordinary charge, net (see Note 14 to consolidated financial statements)		—			—			(77.0	)
Cumulative effect of accounting change, net (see Notes 7 and 9 to consolidated financial statements)		(130.5	)		(31.1	)		—

Consolidated net (loss) income	$	(632.7	)	$	417.8		$	236.6


	Basic Earnings (Loss) Per Share
	2002			2001			2000
Delivery and Services	$	.67		$	1.56		$	1.47
Generation and Marketing		(4.67	)		2.18			1.37

Consolidated (loss) income before extraordinary charge and cumulative effect of accounting change		(4.00	)		3.74			2.84
Extraordinary charge, net (see Note 14 to consolidated financial statements)		—			—			(.70	)
Cumulative effect of accounting change, net (see Notes 7 and 9 to consolidated financial statements)		(1.04	)		(.26	)		—

Consolidated net (loss) income	$	(5.04	)	$	3.48		$	2.14

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

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

Allegheny Energy, Inc.

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

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

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

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

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

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

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

Allegheny Energy, Inc.

Operating Revenues

Total operating revenues for 2002, 2001, and 2000 were as follows:

(In millions)	2002			2001			2000
Delivery and Services:
Regulated electric	$	2,490.2		$	2,395.0		$	2,303.5
Regulated natural gas		221.6			235.1			103.6
Transmission services and bulk power		72.1			100.7			83.0
Unregulated services		643.5			139.5			22.6
Other affiliated and nonaffiliated energy Services		93.3			88.9			61.9

Total Delivery and Services revenues		3,520.7			2,959.2			2,574.6
Generation and Marketing:
Wholesale*		(485.9	)		383.6			(71.2	)
Retail, affiliated, and other		1,431.2			1,544.5			1,516.9

Total Generation and Marketing revenues		945.3			1,928.1			1,445.7
Eliminations:
Delivery and Services intersegment revenues		(1,468.9	)		(1,472.3	)		(1,367.2	)
Generation and Marketing change in fair value of intersegment contract		(8.6	)		10.1			—

Total operating revenues	$	2,988.5		$	3,425.1		$	2,653.1

In accordance with Emerging Issues Task Force (EITF) Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts,” energy trading revenues are reported net, which has resulted in negative revenue amounts for certain years displayed above. (See Note 4 to the consolidated financial statements for additional information).

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

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

Allegheny Energy, Inc.

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

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

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

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

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

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

Allegheny Energy, Inc.

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

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

During 2002 and 2001, Allegheny traded electricity, natural gas, oil, coal, and other energy-related commodities. Allegheny recorded contracts entered into in connection with energy trading at fair value on the consolidated balance sheet, with all changes in fair value recorded as gains and losses on the consolidated statement of operations in operating revenues. The realized revenues from energy trading activities are recorded on a net basis in operating revenues on the consolidated statement of operations in accordance with EITF Issue No. 02-3.

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

The following table disaggregates the net fair value of commodity contract assets and liabilities, excluding Allegheny’s generating assets and provider-of-last-resort (PLR), as of December 31, 2002, based on the underlying market price source and the contract delivery periods:

	Fair value of contracts at December 31, 2002
Classifications of contracts by source of fair value (In millions)	Delivery by December 31, 2003			Delivery from January 1, 2004, to December 31, 2005			Delivery from January 1, 2006, to December 31, 2007			Delivery from January 1, 2008, and beyond			Total fair value
Prices actively quoted	$	(39.5	)	$	(38.6	)	$	(9.5	)	$	(4.9	)	$	(92.5	)
Prices provided by other external sources		—			(1.6	)		(2.1	)		(2.1	)		(5.8	)
Prices based on models		4.6			146.7			233.3			143.4			528.0

Total	$	(34.9	)	$	106.5		$	221.7		$	136.4		$	429.7

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

Allegheny Energy, Inc.

Approximately $528.0 million of Allegheny’s commodity contracts were classified above as prices based on models (even though a portion of these contracts are valued based on observable market prices). The most significant variables to Allegheny’s models used to value these contracts are the forward prices for both electricity and natural gas. These forward prices are based on observable market prices to the extent prices are available in the market. Generally, electricity forward prices are actively quoted for about one year, and some observable market prices are available for about three years. After three years, the forward prices for electricity are based on the forward price of natural gas and a marginal heat rate for generation (based on more efficient natural gas-fired generation) to convert natural gas into electricity. For natural gas, forward prices are generally actively quoted for about three years, and some observable market prices are available for about five years. Beyond five years, natural gas prices are escalated, based on trends in prior years.

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

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

(In millions)	2002
Net fair value of commodity contract assets and (liabilities) at January 1,	$	760.4
Unrealized losses on commodity contracts, net during 2002:
Fair value of structured transactions when entered into during 2002		12.2
Changes in fair value attributable to changes in valuation techniques and assumptions as a result of significant market changes during 2002		(608.1	)
Other unrealized gains on commodity contracts, net		237.6

Total unrealized losses on commodity contracts, net during 2002		(358.3	)
Net options paid or received*		27.6

Net fair value of commodity contract assets and liabilities at December 31,	$	429.7

Amount is net of $46.5 million of option premium expirations.

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

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

Allegheny Energy, Inc.

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

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

On February 21, 2002, the California PUC approved a rate agreement with the CDWR in order for the CDWR to issue Power Supply Revenue Bonds to repay the State of California’s general fund and other outstanding loans and pay its ongoing long-term purchased power costs. The agreement creates two streams of revenue for the CDWR by calling for the California PUC to impose bond charges and power charges on retail electric customers sufficient to pay the CDWR’s debt service and operating expenses, including payment of its long-term power purchase agreements with Allegheny. In September 2002, the CDWR’s Power Supply Revenue Bonds received the following long-term ratings: Moody’s Investors Service (Moody’s), A3; Standard and Poor’s, BBB+; and Fitch Ratings (Fitch), A-. To date, all payments to Allegheny by the CDWR for purchased power have been made on time and in full.

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

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

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

There has been, and may continue to be, significant volatility in the market prices for electricity and natural gas at the wholesale level, which will affect Allegheny’s operating results. Similarly, volatility in interest rates

Allegheny Energy, Inc.

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

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

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

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

	PLR				Excess Generation And Trading						Total Generation And Marketing
(In millions)	2002		2001		2002			2001			2002			2001
Operating revenues:
Physical	$	1,472.3	$	1.395.9	$	(178.6	)	$	5.0		$	1,293.7		$	1,400.9
Financial		—		—		(348.4	)		527.2			(348.4	)		527.2

Total operating revenues		1,472.3	$	1,395.9		(527.0	)		532.2			945.3			1,928.1

Cost of revenues:
Fuel for electric generation		564.4		519.4		27.1			41.0			591.5			560.4
Purchased energy and transmission:
Physical		39.7		59.7		82.9			103.0			122.6			162.7
Financial		—		—		10.2			(2.4	)		10.2			(2.4	)
Natural gas purchases
Financial		—		—		—			8.0			—			8.0

Total cost of revenues		604.1		579.1		120.2			149.6			724.3			728.7

Net revenues	$	868.2	$	816.8	$	(647.2	)	$	382.6		$	221.0		$	1,199.4

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

Cost of Revenues

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

Allegheny Energy, Inc.

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

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

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

(In millions)	2002			2001			2000
Delivery and Services:
From PURPA generation*	$	200.2		$	191.6		$	191.0
Other purchased energy		1,473.9			1,422.7			1,342.0

Total purchased energy for Delivery and Services		1,674.1			1,614.3			1,533.0
Generation and Marketing purchased energy and transmission		132.8			160.3			90.8
Eliminations:
Delivery and Services expense		(1,439.1	)		(1,406.1	)		(1,320.6	)
Generation and Marketing expense		(20.9	)		(61.4	)		(42.9	)

Total purchased energy and transmission	$	346.9		$	307.1		$	260.3

*PURPA cost (cents per kWh)		5.6			5.4			5.5

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

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

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

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

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

Allegheny Energy, Inc.

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

(In millions)	2002		2001		2000
Delivery and Services	$	660.3	$	209.1	$	56.1
Generation and Marketing		—		8.0		—

Total natural gas purchases	$	660.3	$	217.1	$	56.1

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

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

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

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

Other Operating Expenses

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

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

Allegheny Energy, Inc.

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

(In millions)	2002			2001			2000
Delivery and Services	$	442.0		$	400.0		$	358.3
Generation and Marketing		711.6			435.2			286.6
Eliminations:
Generation and Marketing expense		(9.2	)		(4.8	)		(3.7	)

Total operation expense	$	1,144.4		$	830.4		$	641.2

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

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

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

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

(In millions)	2002		2001		2000
Delivery and Services	$	157.4	$	149.0	$	134.3
Generation and Marketing		151.2		152.5		113.6

Total depreciation and amortization expenses	$	308.6	$	301.5	$	247.9

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

Allegheny Energy, Inc.

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

(In millions)	2002		2001		2000
Delivery and Services	$	137.4	$	122.0	$	112.4
Generation and Marketing		88.4		94.4		97.8

Total taxes other than income taxes	$	225.8	$	216.4	$	210.2

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

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

Other Income and Expenses, Net

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

Interest Charges and Preferred Dividends

Interest on debt for 2002, 2001, and 2000 was as follows:

(In millions)	2002			2001			2000
Delivery and Services	$	137.1		$	160.1		$	148.3
Generation and Marketing		172.5			129.5			83.4
Eliminations:
Delivery and Services intersegment interest		(.3	)		—			—
Generation and Marketing intersegment interest		(4.7	)		(11.9	)		(3.8	)

Total interest on debt and preferred dividends	$	304.6		$	277.7		$	227.9

The increase in total interest charges and preferred dividends of $26.9 million and $49.8 million for 2002 and 2001, respectively, resulted from increased average long-term and short-term debt outstanding. The increase in average long-term debt outstanding was primarily the result of AE Supply borrowing $380 million at 8.13 percent under a credit agreement in November 2001 and issuing $400 million of unsecured 7.80-percent notes in March 2001. In April 2002, AE Supply issued $650.0 million of 8.25-percent notes due April 15, 2012. AE Supply used the net proceeds from the notes to repay short-term indebtedness of $630.0 million, which included a bridge loan for $550.0 million that was entered into in connection with the acquisition of 1,710 MW of generating assets in the Midwest in May 2001, and for general corporate purposes. In April 2002, West Penn issued $80.0 million of 6.625-percent notes due April 15, 2012. In May 2002, West Penn used the net proceeds

Allegheny Energy, Inc.

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

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

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

Federal and State Income Tax (Benefit) Expense

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

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

Minority Interest

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

Extraordinary Charges, Net

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

Cumulative Effect of Accounting Change, Net

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

Allegheny Energy, Inc.

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

Other Comprehensive Income

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

FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES

Liquidity and Capital Requirements

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

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

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

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

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

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

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

Following is a summary of the terms of the Borrowing Facilities:

Facilities at AE Supply:

•

A $987.7-million credit facility (the Refinancing Credit Facility) at AE Supply, of which $893.4 million is secured by substantially all the assets of AE Supply. Borrowings under the facility bear interest at a London Interbank Offer Rate (LIBOR)-based rate plus a margin of six percent or a designated money center bank’s base rate plus a margin of five percent on the secured portion. The interest rate margin applicable to unsecured borrowings under the facility is 10.5 percent. This facility requires amortization payments of approximately $23.6 million in September 2004 and $117.8 million in December 2004, and matures in April 2005;

•

A $470.0-million facility at AE Supply, of which $420.0 million was committed and is outstanding and $50.0 million is no longer committed. The facility is secured by substantially all of AE Supply’s assets. Borrowings under the facility bear interest at a LIBOR-based rate plus a margin of six percent or a designated money center bank’s base rate plus a margin of five percent. This facility requires an amortization payment of $250.0 million in December 2003, and payment of the balance of $170.0 million in September 2004; and

•

A $270.1-million credit facility (the Springdale Credit Facility) associated with financing for the construction of AE Supply’s new generating facility in Springdale, Pennsylvania, and which is secured by a combination of that facility and substantially all of AE Supply’s other assets. Borrowings under the facility bear interest at a LIBOR-based rate plus a margin of six percent or a designated money center bank’s base rate plus a margin of five percent on the secured portion. The interest rate margin applicable to unsecured borrowings under the facility is 10.5 percent. This facility requires amortization payments of $6.4 million in September 2004, $32.2 million in December 2004, and matures in April 2005.

Facilities at AE and subsidiaries, other than AE Supply:

•

A $305.0-million unsecured facility under which AE, Monongahela and West Penn are the designated borrowers, and AE has borrowed the full facility amount. Borrowings under this facility bear interest at a LIBOR-based rate plus a margin of five percent or a designated money center bank’s base rate plus a margin of four percent;

•

$25.0-million unsecured credit facility at AE. This facility had an interest rate of a designated money center bank’s base rate plus four percent and was retired in July 2003; and

•

A $10.0-million unsecured credit facility at Monongahela. This facility bears interest at a LIBOR-based rate plus four percent and matures in December 2003.

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

The $420.0 million committed and borrowed by AE Supply under the $470.0-million facility represents new liquidity, and the remaining facilities and restructured A-Notes represent refinanced indebtedness.

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

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

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

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

•

fixed-charge coverage ratio of 1.10 through the first quarter of 2005; and

•

maximum debt-to-capital ratio of 75 percent in 2003 and 72 percent from 2004 through the first quarter of 2005.

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

•

minimum earnings before interest, taxes, depreciation, and amortization (EBITDA), as defined in the agreement, of $100.0 million by June 30, 2003, increasing to $304 million by December 31, 2003, to $430.0 million in increments for the 12 months ending each quarter through the first quarter of 2005;

•

interest coverage ratio of not less than 0.75 through June 30, 2003, increasing to 1.10 by December 31, 2003, and 1.50 by December 31, 2004, through the first quarter of 2005; and

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•

minimum net worth of $800.0 million (subject to downward adjustment under specific circumstances).

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

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

•

75 percent of the proceeds of sales of assets of AE and its subsidiaries, other than AE Supply and its subsidiaries, up to $400.0 million, and 100 percent thereafter;

•

75 percent of the proceeds of sales of assets of AE Supply and its subsidiaries up to $800.0 million, and 100 percent thereafter, other than AE Supply’s new generating facility in Springdale, Pennsylvania;

•

100 percent of the proceeds of any sale of AE Supply’s new generating facility in Springdale, Pennsylvania;

•

100 percent of the net proceeds of debt issuances (excluding specified exemptions, including an exemption of up to $50 million for the Distribution Companies and refinancings meeting certain criteria);

•

100 percent of net proceeds from equity issuances;

•

50 percent of AE and its subsidiaries’ (excluding AE Supply’s and its subsidiaries’) excess cash flow (as defined in the Borrowing facilities); and

•

50 percent of AE Supply’s excess cash flow (as defined under the Borrowing Facilities).

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

	Payments Due by Period
Contractual Cash Obligations and Commitments (In millions)	Payments by December 31, 2003		Payments from January 1, 2004, to December 31, 2005		Payments from January 1, 2006, to December 31, 2007		Payments from January 1, 2008, and beyond		Total
Short-term debt	$	1,132.0	$	—	$	—	$	—	$	1,132.0
Long-term debt due within one year*		253.4		—		—		—		253.4
Debentures, notes and bonds classified as current*		—		537.4		1,092.4		2,041.0		3,670.8
Long-term debt*		—		—		15.4		101.1		116.5
Capital lease obligations		9.3		20.1		13.7		11.3		54.4
Operating lease obligations		23.1		335.0		10.0		33.6		401.7
PURPA purchased power		213.8		406.0		418.4		4,393.7		5,431.9
Fuel purchase commitments		406.1		627.1		129.5		—		1,162.7

Total	$	2,037.7	$	1,925.6	$	1,679.4	$	6,580.7	$	12,223.4

Does not include unamortized debt expense, discounts, premiums, and terminated interest rate swaps that were accounted for as fair value hedges under SFAS No. 133 (see Note 9 to the consolidated financial statements).

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

Payments Due by Period

Contractual Cash Obligations and Commitments

(In millions)

Payments by
December 31,
2003

Payments
from
January 1,
2004, to
December 31,

2005

Payments
from
January 1,
2006, to
December 31,

2007

Payments
from
January 1,
2008, and
beyond

Total

Borrowing Facilities*

292.3

1,725.5

380.0

—

2,397.8

Excludes $50.0 million of additional funding never borrowed by AE Supply under the Borrowing Facilities.

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

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

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

Cash Flows

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

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

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

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

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

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

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

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

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Financing

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

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

There were no shares of common stock repurchased in 2001 and 2000.

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

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

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

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

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

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

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

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

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

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

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

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

The amounts accumulated in other comprehensive income related to these contracts were reclassified to earnings during July and August of 2001, when the hedged transactions were executed. As a result, a loss of $5.0 million,

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

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

On March 19, 2002, AE Supply entered into two treasury lock agreements to hedge its exposure to changing United States Treasury interest rates on the forecasted issuance of long-term, fixed-rate debt in April 2002. These treasury lock agreements were accounted for as cash flow hedges. In April 2002, these contracts were settled for a loss of $1.6 million, before income taxes ($1.0 million, net of income taxes). The unrealized loss was recorded in other comprehensive income. In April 2002, AE Supply began reclassifying to earnings the amounts in accumulated other comprehensive income for these treasury lock agreements over the life of the 10-year debt. For 2002, $.1 million, before income taxes ($.1 million, net of income taxes), was reclassified from accumulated other comprehensive income to earnings.

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

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

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

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

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

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

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

NEW ACCOUNTING STANDARDS

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

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

•

All new contracts that are not derivatives as defined by SFAS No. 133 entered into subsequent to October 25, 2002, should be accounted for on the accrual basis of accounting as executory contracts and would not qualify for mark-to-market accounting.

•

The effective date for the full rescission of Issue No. 98-10 will be for fiscal periods beginning after December 15, 2002. The effect of rescinding Issue No. 98-10 will be reported as a cumulative effect of a change in accounting principle in accordance with Accounting Principles Board (APB) Opinion No. 20, “Accounting Changes.”

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

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

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

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

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

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

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

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

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

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

ALLEGHENY ENERGY SUPPLY COMPANY, LLC

OVERVIEW

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

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

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

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REVIEW OF OPERATIONS

Critical Accounting Policies and Estimates

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

Commodity Contracts: Through December 31, 2002, commodity contracts related to AE Supply’s energy trading activities were recorded at their fair value in accordance with the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Energy Trading and Risk Management Activities.” As of January 1, 2003, EITF Issue No. 98-10 was rescinded. However, the vast majority of AE Supply’s commodity contracts continue to be recorded at their fair value under the FASB’s Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133—an amendment of FASB Statement No. 133,” and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities—an amendment of FASB Statement No. 133” (collectively referred to as SFAS No. 133). At December 31, 2002, the fair value of AE Supply’s commodity contracts represented a net asset position of $428.2 million. Fair values for exchange-traded instruments, principally futures and certain options, are based on actively quoted market prices. In establishing the fair value of commodity contracts that do not have quoted market prices, such as physical contracts, over-the-counter options, and swaps, management makes estimates using available and estimated market data and pricing models, which may change from time to time. AE Supply has several contracts that are unique, which extend to 2010 and beyond, and are valued using proprietary pricing models. Inputs to the models include estimated forward natural gas and electricity prices, interest rates, estimates of market volatility for natural gas and electricity prices, the correlation of natural gas and electricity prices, and other factors such as generating unit availability and location, as appropriate. These inputs require management judgments and assumptions. AE Supply’s models also adjust the fair value of commodity contracts to reflect uncertainty in prices, operational risks related to generating facilities, and risks related to the performance of counterparties. These inputs become more challenging, and the models become less precise, the further into the future these estimates are made. Additionally, various factors, including reduced market liquidity, have significantly affected the merchant energy marketplace during 2002. Market liquidity and the number of creditworthy participants have been dramatically reduced, and trading and origination opportunities have been significantly curtailed within energy markets. Actual effects on AE Supply’s financial position, cash flows, and results of operations may vary significantly from expected results if the judgments and assumptions underlying those models’ inputs prove to be wrong or the models prove to be unreliable. AE Supply’s accounting for commodity contracts is discussed under “Operating Revenues” and Note 4 to the consolidated financial statements. Also, see Note 9 to the consolidated financial statements and “Derivative Instruments and Hedging Activities” for additional information regarding our accounting for derivative instruments under SFAS No. 133.

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

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

Year	Price Per Megawatt-hour (MWh) Peak/Off-Peak		Volume in Megawatts (MW)
2003	$	61 / $61	250
2004	$	61 / $60	500
2005	$	61 / $59	750
2006 - 2011	$	61 / $58	800

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

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

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

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

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

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

Earnings (Loss) Summary

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

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

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

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

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

Operating Revenues

Total operating revenues for 2002, 2001, and 2000 were as follows:

(In millions)	2002			2001		2000
Retail	$	36.9		$	133.1	$	197.2
Wholesale*		(489.0	)		389.1		(73.7	)
Affiliated		1,135.1			1,135.5		777.3

Total operating revenues	$	683.0		$	1,657.7	$	900.8

In accordance with EITF Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts,” energy trading revenues are reported net, which has resulted in negative revenue amounts for certain years displayed above. (See Note 4 to the consolidated financial statements for additional information).

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

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

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

During 2002 and 2001, AE Supply traded electricity, natural gas, oil, coal, and other energy-related commodities. AE Supply recorded contracts entered into in connection with energy trading at fair value on the consolidated balance sheet, with all changes in fair value recorded as gains and losses on the consolidated statement of operations in operating revenues. The realized revenues from energy trading activities are recorded on a net basis in operating revenues on the consolidated statement of operations in accordance with EITF No. 02-3.

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

The following table disaggregates the net fair value of commodity contract assets and liabilities, excluding AE Supply’s generating assets and provider-of-last-resort (PLR), as of December 31, 2002, based on the underlying market price source and the contract delivery periods:

	Fair value of contracts at December 31, 2002
Classifications of contracts by source of fair value (In millions)	Delivery by December 31, 2003			Delivery from January 1, 2004, to December 31, 2005			Delivery from January 1, 2006, to December 31, 2007			Delivery from January 1, 2008, and beyond			Total fair value
Prices actively quoted	$	(39.5	)	$	(38.6	)	$	(9.5	)	$	(4.9	)	$	(92.5	)
Prices provided by other external sources		—			(1.6	)		(2.1	)		(2.1	)		(5.8	)
Prices based on models		5.0			144.8			233.3			143.4			526.5

Total	$	(34.5	)	$	104.6		$	221.7		$	136.4		$	428.2

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

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Allegheny Energy Supply Company, LLC

Approximately $526.5 million of AE Supply’s commodity contracts were classified above as prices based on models, even though a portion of these contracts are valued based on observable market prices. The most significant variables to AE Supply’s models used to value these contracts are the forward prices for both electricity and natural gas. These forward prices are based on observable market prices to the extent prices are available in the market. Generally, electricity forward prices are actively quoted for about one year, and some observable market prices are available for about three years. After three years, the forward prices for electricity are based on the forward price of natural gas and a marginal heat rate for generation (based on more efficient natural gas-fired generation) to convert natural gas into electricity. For natural gas, forward prices are generally actively quoted for about three years, and some observable market prices are available for about five years. Beyond five years, natural gas prices are escalated, based on trends in prior years.

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

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

(In millions)	2002
Net fair value of commodity contract assets and (liabilities) at January 1,	$	750.3
Unrealized losses on commodity contracts, net during 2002:
Fair value of structured transactions when entered into during 2002		12.2
Changes in fair value attributable to changes in valuation techniques and assumptions		(608.1	)
Other unrealized gains on commodity contracts, net		246.2

Total unrealized losses on commodity contracts, net during 2002		(349.7	)
Net options paid or received*		27.6

Net fair value of commodity contract assets and liabilities at December 31	$	428.2

Amount is net of $46.5 million of option premium expirations.

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

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

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Allegheny Energy Supply Company, LLC

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

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

On February 21, 2002, the California PUC approved a rate agreement with the CDWR in order for the CDWR to issue Power Supply Revenue Bonds to repay the State of California’s general fund and other outstanding loans and pay its ongoing long-term purchased power costs. The agreement creates two streams of revenue for the CDWR by calling for the California PUC to impose bond charges and power charges on retail electric customers sufficient to pay the CDWR’s debt service and operating expenses, including payment of its long-term power purchase agreements with AE Supply. In September 2002, the CDWR’s Power Supply Revenue Bonds received the following long-term ratings: Moody’s, A3; Standard and Poor’s, BBB+; and Fitch, A-. To date, all payments to AE Supply by the CDWR for purchased power have been made on time and in full.

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

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

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

There has been, and may continue to be, significant volatility in the market prices for electricity and natural gas at the wholesale level, which will affect AE Supply’s operating results. Similarly, volatility in interest rates will affect AE Supply’s operating results. The effects may be either positive or negative, depending on whether West Penn, Potomac Edison, and Monongahela are net buyers or sellers of electricity and natural gas.

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Allegheny Energy Supply Company, LLC

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

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

PLR

Excess Generation
and Trading

Total Generation and
Marketing

(In millions)

2002

2001

2002

2001

ALLEGHENY GENERATING CO 10-K