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, 2001
Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification Number

1-267	ALLEGHENY ENERGY, INC. (A Maryland Corporation) 10435 Downsville Pike Hagerstown, Maryland 21740-1766 Telephone (301) 790-3400	13-5531602




333-72498	ALLEGHENY ENERGY SUPPLY COMPANY, LLC (A Delaware Limited Liability Company) 10435 Downsville Pike Hagerstown, Maryland 21740-1766 Telephone (301) 790-3400	23-3020481





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


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

(Continued) 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, 2001
Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification Number

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




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


ALLEGHENY GENERATING COMPANY, MONONGAHELA POWER COMPANY, THE POTOMAC EDISON COMPANY AND WEST PENN POWER COMPANY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I (l)(a) AND (b) OF FORM 10-K AND ARE THEREFORE FILING THIS FORM WITH A REDUCED DISCLOSURE FORMAT. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) have been subject to such filing requirements for the past 90 days. Yes __X__ No _____ as to all Registrants except Allegheny Energy Supply Company, LLC, which became subject to such filing requirements on January 8, 2002. 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. [ ] Securities registered pursuant to Section 12(b) of the Act:

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

Monongahela Power Company	Cumulative Preferred Stock, $100 par value; 4.40% 4.50%, Series C		American Stock Exchange American Stock Exchange

West Penn Power Company	8% Quarterly Income Debt Securities, Junior Subordinated Deferrable Interest Debentures, Series A		New York Stock Exchange

Allegheny Energy Supply Company, LLC	None	None

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

Allegheny Generating Company	Common Stock $1.00 par value		None

Allegheny Energy Supply Company, LLC	None		None

	Aggregate market value of voting stock (common stock) held by nonaffiliates of the registrants at March 1, 2002	Number of shares of common stock of the registrants outstanding at March 1, 2002

Allegheny Energy, Inc.	$4,401,621,593.60	125,276,479 ($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)

(a) All such common stock is held by Allegheny Energy, Inc., the parent company. (b) All such common stock is held by its parents, Monongahela Power Company and Allegheny Energy Supply Company, LLC. (c) There is no trading market in equity securities of Allegheny Energy Supply Company, LLC. ML IBK Positions, Inc. owns 1.967 percent of the ownership interest in Allegheny Energy Supply Company, LLC and Allegheny Energy, Inc. owns the rest.

CONTENTS
PART I:		Page

ITEM 1.	Business	1
	Corporate Restructuring	4
	Factors That May Affect Future Results	5
	Risk Factors	5
	Competition	19
	Natural Gas Competition	19
	Electric Energy Competition	20
	Activities at the Federal Level	21
	Activities at the State Level	22
	Competitive Actions	25
	Sales	31
	Regulated Electric Sales	31
	Regulated Gas Sales	33
	Unregulated Sales	34
	Regulatory Framework Affecting Electric Power Sales	34
	Electric Facilities	36
	Allegheny Map	40
	AE Supply Map	41
	Research and Development	43
	Capital Requirements and Financing	43
	Financing Programs	47
	Fuel Supply	50
	Rate Matters	53
	Environmental Matters	57
	Air Standards	57
	Water Standards	60
	Hazardous and Solid Wastes	62
	Regulation	63

ITEM 2.	Properties	63

ITEM 3.	Legal Proceedings	64

ITEM 4.	Submission of Matters to a Vote of Security Holders	67

PART II:

ITEM 5.	Market for the Registrants' Common Equity and Related Shareholder Matters	71

ITEM 6.	Selected Financial Data	72

ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	73

CONTENTS, continued

ITEM 7A	Quantitative and Qualitative Disclosure About Market Risk	74

PART III:

ITEM 8.	Financial Statements and Supplementary Data	79

ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	88

ITEM 10.	Directors and Executive Officers of the Registrants	88

ITEM 11.	Executive Compensation	90

ITEM 12.	Security Ownership of Certain Beneficial Owners and Management	95

ITEM 13.	Certain Relationships and Related Transactions	96

PART IV:

ITEM 14.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	96

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), incorporated in Maryland in 1925, is a diversified utility holding company which has experienced significant changes in its business as a result of the deregulation of electric generation in states where its subsidiaries operate. As deregulation of electric generation has been implemented, AE's subsidiaries have transferred their generating assets, excluding Monongahela Power Company's West Virginia jurisdictional assets, from their regulated utility businesses to an affiliated, unregulated generation business in accordance with approved deregulation plans. AE owns directly and indirectly various regulated and non-regulated subsidiaries (collectively and generically Allegheny, we, us or our).

As a result of the deregulation activities, AE has aligned its businesses into three principal business segments: regulated utility operations, unregulated generation operations and other unregulated operations. The regulated utility operations segment consists primarily of (i) three regulated electric public utility companies, Monongahela Power Company (Monongahela) (Monongahela also has a regulated natural gas utility division as a result of its purchase of West Virginia Power in 1999), The Potomac Edison Company (Potomac Edison), and West Penn Power Company (West Penn), and (ii) a regulated public utility natural gas company, Mountaineer Gas Company (Mountaineer), which is a subsidiary of Monongahela (all collectively doing business as Allegheny Power, and collectively Monongahela, Potomac Edison and West Penn and their subsidiaries are referred to herein as the Distribution Companies). The regulated utility operations segment operates electric transmission and distribution (T&D) systems and natural gas distribution systems. It also generates electric energy in its West Virginia jurisdiction where deregulation of electric generation has not yet been implemented. Allegheny Power delivers electricity to approximately 1.5 million customers in parts of Maryland, Ohio, Pennsylvania, Virginia and West Virginia. Through the acquisition of West Virginia Power and Mountaineer, Allegheny Power also delivers natural gas to approximately 230,000 customers in West Virginia.

The Allegheny family of companies also includes an unregulated generation operations segment, consisting primarily of Allegheny Energy Supply Company, LLC (AE Supply), including Allegheny Generating Company (AGC). AE Supply is an unregulated energy company that develops, owns, operates and controls electric generating capacity and, through its energy marketing and trading division, supplies and trades energy and energy-related commodities in domestic retail and wholesale markets. AE Supply manages its generating assets as an integral part of its wholesale marketing, fuel procurement, risk management and energy trading activities. AGC owns and sells generating capacity to its parent companies, AE Supply and Monongahela.

The other unregulated operations segment consists of Allegheny Ventures, Inc. (Allegheny Ventures),

a non-utility, unregulated subsidiary of AE. Allegheny Ventures actively invests in and develops energy-related projects and provides energy consulting and management services and natural gas and other energy-related services through its subsidiary Allegheny Energy Solutions, Inc. Additionally, Allegheny Ventures invests in and develops fiber optic projects, including fiber and data services, through its subsidiary Allegheny Communications Connect, Inc.

Monongahela
, incorporated in Ohio in 1924, operates its T&D system in northern West Virginia and an adjacent portion of Ohio. It owns generating capacity in West Virginia and Pennsylvania. In all jurisdictions, Monongahela is doing business under the trade name Allegheny Power. Including the assets of West Virginia Power, which were acquired by Monongahela in 1999, Monongahela serves about 390,000 electric customers and about 24,000 retail and wholesale natural gas customers in a service area of about 13,000 square miles with a population of about 815,000. Monongahela owns approximately 698 miles of natural gas distribution pipelines, and during 2001 sold approximately 2.963 billion cubic feet (Bcf) of gas. In June 2001, Monongahela transferred approximately 352 megawatts (MW) of generating assets and a portion of its ownership in AGC to AE Supply at net book value. Monongahela's remaining generating assets, 2,115 MW which serve customers in West Virginia, and its entitlement to capacity in the Ohio Valley Electric Corporation (OVEC) will not be transferred unless tax changes and implementation authorization related to the deregulated power market in West Virginia have been enacted or the West Virginia Public Service Commission otherwise takes regulatory action, and the Securities and Exchange Commission approves the transfer. The seven largest communities served by Monongahela have populations ranging from 10,900 to 33,900. This service area has navigable waterways and substantial deposits of bituminous coal, glass sand, natural gas, rock salt, and other natural resources. Its service area's principal industries produce coal, chemicals, iron and steel, fabricated products, wood products, and glass. There are two municipal electric distribution systems and two rural electric cooperative associations in its electric service territory. Except for one of the cooperatives, in 2001 they purchased all of their power from Monongahela.

Mountaineer, a subsidiary of Monongahela, is a natural gas distribution company incorporated in West Virginia in 1957. Mountaineer serves approximately 205,000 retail natural gas customers in West Virginia. Mountaineer owns approximately 4,000 miles of natural gas distribution pipelines. During 2001, Mountaineer sold or transported 58.45 (Bcf) of gas. Mountaineer Gas Services, Inc. (MGS), a subsidiary of Mountaineer, operates natural gas producing properties, gas gathering facilities, and intra-state transmission pipelines and is engaged in the sale and marketing of natural gas in the Appalachian basin. MGS owns more than 375 natural gas wells and has a net revenue interest in about 100 wells of which it is not the operator.

Potomac Edison, incorporated in Maryland in 1923 and in Virginia in 1974, operates its T&D system in portions of Maryland, Virginia, and West Virginia. In all jurisdictions, Potomac Edison is doing business under the trade name Allegheny Power. Potomac Edison serves about 411,000 electric customers in a service area of about 7,300 square miles with a population of about 782,000. In August 2000, Potomac Edison transferred all of its generation assets (except for its 3 MW of Virginia hydroelectric assets), its interest in AGC and its entitlement to capacity in OVEC to AE Supply pursuant to state legislation and regulatory proceedings. On June 1, 2001, Potomac Edison transferred its 3 MW of hydroelectric assets located within Virginia to its subsidiary, Green Valley Hydro, LLC, and distributed its ownership of Green Valley Hydro, LLC to AE. The six largest communities served by Potomac Edison have populations ranging from 11,900 to 40,100. Potomac Edison's service area's principal industries produce aluminum, cement, fabricated products, rubber products, sand, stone, and gravel.

West Penn
, incorporated in Pennsylvania in 1916, operates its T&D system in southwestern and north and south-central Pennsylvania. West Penn is doing business under the trade name Allegheny Power. West Penn serves about 684,000 electric customers in a service area of about 9,900 square miles with a population of about 1,399,000. In November 1999, West Penn transferred all of its generation assets, its interest in AGC and its entitlement to capacity in OVEC to AE Supply pursuant to state legislation and regulatory proceedings. The 10 largest communities served by West Penn have populations ranging from 11,200 to 38,900. West Penn's service area has navigable waterways and substantial deposits of bituminous coal, limestone, and other natural resources. Its service area's principal industries produce steel, coal, fabricated products, and glass.

AE Supply
, a Delaware limited liability company, was formed in November 1999 to take advantage of the opportunity to transfer to AE Supply at net book value some of the generation assets of the Distribution Companies as a result of economic factors and federal and state legislative and regulatory changes related to the development of competitive markets. AE Supply is expanding its generation fleet through the announced construction and development of new facilities, acquisition of contractual rights to control generating capacity and planned expansions to existing facilities. In March 2001, AE Supply also acquired Global Energy Markets, the energy marketing and trading business of Merrill Lynch, which now operates as the Energy Marketing and Trading division of AE Supply. This division helps optimize AE Supply's portfolio of generating assets by significantly enhancing its risk management, wholesale marketing, fuel procurement and energy trading activities on a nationwide basis. AE Supply manages all of its generation assets as an integrated portfolio with its risk management, wholesale marketing, fuel procurement and energy trading activities.

AE Supply, as part of its generating asset and energy commodity portfolio, interfaces the electric generating capacity represented by AE Supply's generating assets and the electric generation operation owned by Monongahela, and various customers or markets. In 2000, an arrangement was put in place between Monongahela and AE Supply to create this interface. Under this arrangement, Monongahela sells the amount of its real time, available bulk power generation that exceeds its regulated load to AE Supply and conversely Monongahela buys generation from AE Supply when regulated load at times exceeds that amount of real time, available bulk power generation. Monongahela (for its Ohio service territory), Potomac Edison and West Penn also purchase generation from AE Supply under long-term power sales agreements to meet their default service obligations. These transactions take place under the terms of tariffs filed with the Federal Energy Regulatory Commission.

AGC
, organized in 1981 under the laws of Virginia, is jointly owned as follows: Monongahela, 22.97% and AE Supply, 77.03%. AGC has no employees, and its only asset is a 40% 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. AGC's 960-MW share of generating capacity of the station is sold to its two parents. The remaining 60% interest in the Bath County Station is owned by Virginia Electric and Power Company (Virginia Power).

Allegheny Ventures
, incorporated in Delaware in 1994, is an unregulated subsidiary of AE which, through its subsidiaries, invests in and develops fiber and data services and energy-related projects and provides energy consulting and management services and natural gas and other energy-related services. Allegheny Communications Connect, Inc., a Delaware corporation, and Allegheny Energy Solutions, Inc., a Delaware corporation, are both wholly owned subsidiaries of Allegheny Ventures. On November 1, 2001, Allegheny Ventures completed the acquisition of Fellon-McCord Associates, Inc. (Fellon-McCord),

an energy consulting and management services company, Alliance Gas Services, Inc. and Alliance Energy Services Partnership, a provider of natural gas and other energy-related services largely to commercial and industrial end-use customers. Alliance Energy Services Partnership is owned 50% by Allegheny Ventures and 50% by Alliance Gas Services, Inc.

Allegheny Energy Service Corporation
(AESC), a wholly owned subsidiary of AE, was incorporated in Maryland in 1963 as a service company for Allegheny. Aside from a few employees obtained by AE Supply as part of the Midwest asset acquisition and employees obtained by Allegheny Ventures as part of the Fellon-McCord transaction, AE, AE Supply, the Distribution Companies, AGC, Allegheny Ventures and their subsidiaries have no employees. Their officers and non-officers 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 for services provided by AESC's employees. On December 31, 2001, AESC had approximately 5,600 employees.

Corporate Restructuring

In November 2001, AE Supply and its parent, AE, filed applications with the Securities and Exchange Commission (SEC) and the Federal Energy Regulatory Commission (FERC) seeking authorizations under the Public Utility Holding Company Act of 1935, as amended (PUHCA) and the Federal Power Act to restructure the corporate organization by creating a new Maryland holding company into which AE Supply will then merge. AE Supply will thereby be changed from a Delaware limited liability company into a Maryland corporation. AE Supply and its parent, AE, also sought authorization to merge Allegheny Energy Global Markets, LLC, one of AE Supply's wholly owned subsidiaries, into this new Maryland holding company, which will then continue to conduct AE Supply's energy commodity marketing and trading activities as the Energy Marketing and Trading division. On December 31, 2001, AE Supply received SEC and FERC approvals to effect this reorganization. Effective December 31, 2001, Allegheny Energy Global Markets, LLC, was merged into AE Supply, excluding its employees, an operating lease and related leasehold improvements for its New York office, certain computer software and telecommunications equipment, and other miscellaneous assets, which were transferred to AESC, a subsidiary of AE. AE Supply will be merged into the yet-to-be-formed Maryland holding company in 2002.

On July 23, 2001, AE Supply together with AE and other affiliates, filed a U-1 application with the SEC, seeking authorization under the PUHCA to effect an initial public offering of up to 18% of the common stock of the yet-to-be-formed Maryland holding company, which would own 100% of AE Supply, and then distribute the remaining common stock owned by AE to its shareholders on a tax-free basis. In October 2001, AE and AE Supply announced that the proposed initial public offering would be delayed due to market and other conditions. On January 31, 2002, AE and AE Supply announced that the initial public offering would not be pursued. On February 8, 2002, AE and AE Supply filed an amendment to the U-1 application filed on July 23, 2001, with the SEC, withdrawing AE Supply's initial public offering application.

Factors That May Affect Future Results

In addition to the historical information contained herein, this report contains a number of "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. These include statements with respect to deregulation activities and movements toward competition in states served by the Distribution Companies; markets; products; services; prices; capacity purchase commitments; results of operations; capital expenditures; regulatory matters; liquidity and capital resources; the effect of litigation; and accounting matters. All such forward-looking information is necessarily only estimated. 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: general and economic and business conditions, including the continuing effects of the September 11, 2001 terrorists' attacks; changes in industry capacity, development, and other activities by Allegheny's competitors; changes in the weather and other natural phenomena; changes in technology; changes in the price of power and fuel for electric generation; changes in the underlying inputs and assumptions used to estimate the fair values of commodity contracts; changes in laws and regulations applicable to Allegheny; its markets, or its activities; litigation; environmental regulations; the loss of any significant customers and suppliers; the effect of accounting policies issued periodically by accounting standard-setting bodies; and changes in business strategy, operations, or development plans.

In addition to the preceding factors, Allegheny's businesses are subject to a number of risks.

RISKS ASSOCIATED WITH REGULATION

Our Regulated Utility Subsidiaries have "provider-of-last-resort" obligations and our generating subsidiary provides electricity to our Regulated Utility Subsidiaries in amounts sufficient to satisfy these obligations at prices, which may be below its cost and in amounts that may exceed its supply capacity.

The provider-of-last-resort obligations under power sales agreements may have no relationship to our actual cost to supply this power.

Until the transition to full market competition is complete, West Penn, Monongahela with respect to its Ohio customers and Potomac Edison (the Regulated Utility Subsidiaries) are required to provide electricity at capped rates, which may be below current market rates, to retail customers that do not choose an alternative electricity generation supplier and those who switch back from alternate suppliers. To satisfy this "provider-of-last-resort" obligation, the Regulated Utility Subsidiaries source power from AE Supply, the generating subsidiary, under long-term power sales agreements. The power sales agreements AE Supply has with West Penn, Monongahela with respect to its Ohio customers and Potomac Edison currently require a significant portion of the normal operating capacity of AE Supply's generating assets that were previously owned by the Regulated Utility Subsidiaries. In addition, 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 pass on such costs to the Regulated Utility Subsidiaries. We expect that there will be similar risks when customer choice is implemented in West Virginia where Monongahela also has

distribution operations. Because the risk of fuel price increases and increased environmental compliance costs cannot be completely passed through to customers during the transition period absent regulatory approval, AE, on a consolidated basis, retains these risks.

Demand for power from our generation subsidiary could exceed its supply capacity.

From time to time the demand for power required to meet the provider-of-last-resort contract obligations could exceed AE Supply's available generation capacity. If this occurs, AE Supply would have to buy power on the market at prices which may exceed the traditional marginal production and delivery costs of AE Supply's owned or controlled assets. Although AE Supply may be able to charge West Penn, Monongahela with respect to its Ohio customers and Potomac Edison these higher incremental costs pursuant to the terms of long-term power sales agreements, those companies might not be able to pass the costs on to their retail customers, resulting in the possibility that AE could lose money or profit potential on a consolidated basis. Since these situations most often occur during periods of peak demand, it is possible that the market price for power at that time would be very high. Unlike the cooler weather over the summers of 2001 and 2000, the hotter-than-normal summers of 1999 and 1998 saw market prices for electricity in regions in which our Regulated Utility Subsidiaries have provider-of-last-resort obligations peak in excess of $1,000 per megawatt-hour (MWh). Utilities that did not own or purchase sufficient available capacity prior to those periods incurred significant losses in sourcing incremental power. Even if a supply shortage was brief, we could suffer substantial losses that could have an adverse effect on our results of operations. In addition, the electricity AE's Regulated Utility Subsidiaries purchase from AE Supply to meet the provider-of-last-resort obligations is not otherwise available for sale at what most likely would be more favorable wholesale prices.

Because the provider-of-last-resort obligations do not restrict customers from switching suppliers of power, we are not guaranteed any level of power sales.

While the Regulated Utility Subsidiaries are required to provide electricity to customers who do not choose an alternative supplier, customers are with few restrictions entitled at any time to obtain service from an alternative supplier. As customers elect to purchase electricity elsewhere, AE Supply's sales of power may decrease. Alternatively, customers could switch back to the Regulated Utility Subsidiaries from alternative suppliers, which may increase demand above AE Supply's facilities' available capacity, some of which it may have committed to sell to other customers. Thus, any switching by customers could have an adverse effect on AE Supply's results of operations and financial position by reducing sales and revenues or by reducing available capacity and increasing expenses.

The different regional power markets in which AE Supply competes or will compete in the future have changing regulatory structures, which could affect its performance in these regions.

AE Supply's results are likely to be affected by differences in the market and regulatory structures in various regional power markets. Problems or delays that may arise in the formation and operation of new regional transmission organizations, or RTOs, such as the proposed new RTO extending across the entire Northeastern region of the United States, may adversely affect AE Supply's ability to sell electricity produced by its owned or controlled generating capacity to markets in New York or New England. The rules governing the various regional power markets may also change from time to time, which could affect AE Supply's costs or revenues. Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will develop or what regions they will cover, we are unable to assess fully the impact that these power markets may have on AE Supply's business. AE Supply's operating results will also be affected by the addition of generation or transmission capacity serving PJM-West and any other power markets.

We may not fully recover our transmission cost of service if we elect to proceed with PJM-West.

Our plan to turn operational control of our transmission assets over to PJM Interconnection, L.L.C. in the form of PJM-West includes the risk that we may not fully recover our transmission cost of service. We have filed a proposal with FERC for a transitional surcharge to recover the costs we expect to incur as a result of participating in PJM-West. The FERC has accepted our proposal subject to possible refunds after the outcome of an evidentiary hearing inquiring into our transmission costs. Accordingly, if we decide to proceed with PJM-West in light of FERC's order, there is a risk that we will be required to pay significant refunds to our transmission customers, and that our future transmission service revenues will be materially lower than they are today.

Our business is subject to regulation under the Public Utility Holding Company Act of 1935. That Act limits our business operations, our ability to receive dividends from our subsidiaries and our ability to affiliate with public utilities.

We continue to be subject to regulation under the Public Utility Holding Company Act of 1935, or PUHCA. PUHCA limits our ability to acquire, own and operate energy assets outside of our operating region and it limits the dividends that our subsidiaries may pay from unearned surplus. In addition, we must obtain prior approval from the SEC under PUHCA in order to raise financing or to acquire the voting securities of any public utility or take any other action that would result in our affiliation with another public utility.

Changes in Federal Energy Regulatory Commission (FERC) regulation may cause us to lose the benefits of our integrated utility operations.

The success of our business depends, in part, on the economic efficiencies of integrated and coordinated utility operations between our electric transmission, distribution, wholesale marketing and retail service businesses. FERC has promulgated a rule that requires electric utilities to unbundle the services they provide so as to separate electric transmission from wholesale marketing activities. In particular, the rule requires employees with operational responsibility for transmission and reliability services to function independently from operating employees engaged in wholesale and unbundled retail marketing activities (functional unbundling). FERC currently permits senior officers and directors to have ultimate decision-making authority for both electric transmission and wholesale marketing businesses. FERC has, however, proposed to expand this functional unbundling requirement to require employees in all energy-related businesses to function independently from transmission operating employees, which include senior management employees as well. If FERC were to expand its policy in this fashion, it could result in duplicative management responsibilities, loss of efficiencies and increased operating expenses, which could have a material adverse effect on our businesses. In addition, FERC has requested comments on whether it should require full corporate unbundling (e.g., divestiture) of electric transmission businesses from other energy-related activities. If FERC were to adopt this more extreme requirement, it could have a further material adverse effect on our businesses.

Some laws and regulations governing restructuring of the wholesale generation market in Virginia and West Virginia have not yet been interpreted or adopted and could have a material negative impact on how we operate our business, our operating results and our overall financial condition.

While the electric restructuring laws in Virginia and West Virginia established the general framework governing the retail electric market, the laws required the utility commission in each state to issue rules and determinations implementing the laws. Some of the regulations governing the retail electric market have not yet been adopted by the utility commission in each state. These laws, when they are interpreted and when the regulations are developed and adopted, may have a negative impact on our business, results

of operations and financial condition.

There is uncertainty about when, if at all, the West Virginia jurisdictional generating assets of Monongahela will be transferred to AE Supply.

It is our goal to have the West Virginia jurisdictional generating assets of Monongahela, representing approximately 2,115 MW of capacity, transferred to AE Supply. We are currently exploring ways to effect the transfer of these generating assets to AE Supply, including by regulatory action or by legislation in the West Virginia Legislature. Monongahela has filed a petition seeking the West Virginia Public Service Commission's approval of the transfer of the West Virginia jurisdictional generating assets to AE Supply. The West Virginia Public Service Commission has not yet acted on this petition, and we cannot assure you that it will permit the transfer, or when this permission might be granted. No final legislative action was taken in 2001 or during the January to March 2002 session regarding implementation of the deregulation plan. The current climate regarding the restructuring makes it unlikely that the existing plan will be advanced in 2002. If the transfer is permitted, we cannot predict the conditions that may be imposed in connection with it, such as the terms under any long-term power sales agreement necessary to meet Monongahela's provider-of-last-resort retail load obligations, transfer costs or transition periods, any of which may make the transfer uneconomical.

It may be difficult for investors to evaluate the probable impact of AE Supply's transfers of generating assets and acquisitions on its financial performance.

Because of the high levels of acquisition and transfer activity since its formation in November 1999, it may be difficult for investors to evaluate the probable impact of these acquisitions and generating asset transfers on AE Supply's financial performance or make meaningful comparisons between reporting periods until it has operating results for a number of reporting periods for these facilities and assets. For instance, as of December 31, 2001, AE Supply increased its ownership or contractual control of generating capacity to 9,895 MW from 6,472 MW owned or under contractual control as of December 31, 2000. AE Supply expects this will be an issue for the next few years as AE Supply intends to add 4,807 MW of additional capacity.

Our business operates in the deregulated segments of the electric power industry created by restructuring initiatives at both state and federal levels. If the present trend towards competitive restructuring of the electric power industry is reversed, discontinued or delayed, our business prospects and financial condition could be materially adversely affected.

The regulatory environment of the power generation industry has recently been undergoing substantial changes, on both the federal and state levels. The majority of states have taken active steps towards allowing retail customers the right to choose their electricity supplier. On the federal level, the national Energy Policy Act of 1992 led to market-based regulations of the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. These changes have significantly affected the nature of the industry and the manner in which its participants conduct their business.

Moreover, existing statutes and regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulations may have an effect on our business in ways that we cannot predict. Some restructured markets, such as in California, have experienced interruptions of supply and price volatility. These interruptions of supply and price volatility have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some of these markets, including California, government

agencies and other interested parties have made proposals to re-regulate areas of these markets that have previously been deregulated, and, in California, legislation has been passed placing a moratorium on the sale of generating plants by regulated utilities. Proposals to re-regulate the wholesale power market also have been made at the federal level. Proposals of this sort, and legislative or other attention to the electric restructuring process in states in which we currently, or may in the future, operate, may cause the process of deregulation to be delayed, discontinued or reversed, which could have a material adverse effect on our results of operations or our strategies. The recent bankruptcy filing by Enron Corporation, and related matters, may affect the regulatory and legislative process in unpredictable ways.

RISKS ASSOCIATED WITH OUR ACQUISITION AND DEVELOPMENT ACTIVITIES

Our acquisition of generating facilities and development activities may not be successful, which would impair our ability to grow profitably.

Our business development strategy requires us to identify and complete development projects.

Our business strategy depends, in part, on our ability to identify and complete development and construction projects and any acquisitions at appropriate prices. If the assumptions underlying the prices we pay for future acquisition, development and construction projects prove to be inaccurate, the financial performance of the particular facility, our ability to recover our investment, and our overall results of operations and financial position could be significantly impaired. Moreover, if we are not able to access capital at competitive rates, our ability to pursue our development strategy will be adversely affected. A number of factors could affect our ability to access capital, including general economic conditions, capital market conditions, market prices for electricity and gas and the overall health of the utility industry, our capital structure and limitations imposed by PUHCA.

We will be required to spend significant sums before acquisition or construction of a facility.

Before we can commence construction or acquire a generation facility, we may be required to invest significant resources on preliminary engineering, permitting, legal and other matters in order to determine the feasibility of the project. Moreover, the process for obtaining initial environmental, sitting and other governmental and regulatory permits and approvals is complicated, expensive and lengthy, and is subject to significant uncertainties. We may also be required to obtain SEC approval for our financing arrangements. Obtaining these permits and approvals can delay acquisition and construction. If for any reason we are not able to obtain all required permits and approvals, or obtain them in a timely manner, we may be prevented from completing an acquisition, development or construction project. For the same reasons, we also may not be able to obtain and comply with all necessary licenses, permits and approvals for our existing facilities that we seek to expand.

Because plant construction is costly and subject to numerous risks, we may incur additional costs or delays and may not be able to recover our investment.

We have announced construction plans for four generating facilities totaling approximately 2,294 MW, and we intend to pursue our strategy of developing and constructing other new facilities and expanding existing facilities. Our completion of these facilities without delays or cost overruns is subject to substantial risks, including:

-  shortages and inconsistent quality of equipment, material and labor;
-  work stoppages;
-  permits, approvals and other regulatory matters;
-  adverse weather conditions;
-  unforeseen engineering problems;
-  environmental and geological conditions;
-  delays or increased costs to interconnect our facilities to transmission grids;
-  unanticipated cost increases; and
-  our attention to other projects.

If we are unable to complete the development or construction of a facility, we may not be able to recover our investment in it. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect our results of operations and financial position. Furthermore, if construction projects are not completed according to specifications, we may incur liabilities, and suffer reduced plant efficiency, higher operating costs and reduced earnings. Also, changes in market prices for electricity from these projects may make them uneconomic.

Some risks cannot be covered by insurance.

While we maintain insurance, obtain warranties from vendors and obligate contractors to meet specified performance standards, we remain substantially exposed to the risks described above. Furthermore, the proceeds of such insurance and the warranties or performance guarantees may not be adequate to cover lost revenues, increased expenses or liquidated damages payments that we may owe upon the realization of any of the risks described above.

We have made or have committed substantial investments in our recent acquisitions, development and construction projects, and our success depends on our ability to successfully integrate, operate and manage these assets.

We cannot assure you that these facilities, or others we might acquire or develop, or our construction projects, will generate cash flows or revenue that provide appropriate returns on our investments or that we will successfully:

-  integrate acquired assets with our existing operations;
-  develop our management and corporate infrastructure;
-  negotiate favorable terms for the sale of electricity generated by the facilities we have acquired or
   developed, those we plan to construct or develop, and any we acquire in the future; or
-  operate our acquired facilities on an efficient, cost-effective basis.

Our ability to successfully integrate assets will depend on, among other things, the adequacy of our implementation plans, including with respect to our systems integration and data processing capabilities, our ability to achieve desired economies of scale and operating efficiencies within and among our facilities, and our ability to negotiate favorable contracts in connection with the electricity that we generate. If we are unable to successfully integrate these assets into our operations, we could experience increased costs and losses on our investments.

We may be required to assume liabilities, including environmental and employee-related liabilities, under acquisition agreements which could reduce our cash flow and our results of operations.

Some of the acquisition agreements that we have entered into with third parties have required that we

assume specified pre-closing liabilities, primarily related to litigation or investigations with respect to environmental and employee matters. We are likely to be required to assume these types of liabilities, as well as others, in connection with future acquisitions. As a result, we may be liable for significant environmental remediation costs, litigation costs or other liabilities arising from the operation of our facilities by prior owners, which could have a significant adverse effect on our cash flow and results of operations.

RISKS RELATED TO OUR BUSINESS OPERATIONS

Changes in commodity prices may increase our cost of producing power, or decrease the amount we receive from selling power, adversely affecting our financial performance.

We are heavily exposed to changes in the price and availability of coal because most of our generating capacity is coal-fired. We have contracts of varying durations for the supply of coal for most of our existing generation capacity, but as these contracts end, we may not be able to purchase coal on terms as favorable as the current contracts.

We are diversifying our dependence on coal-fired facilities through the acquisition and construction of natural gas-fired facilities, which increases our exposure to the more volatile market prices of natural gas. Almost all of our announced construction and development plans for additional generating capacity have involved natural gas-fired facilities.

Changes in the cost of coal or natural gas and changes in the relationship between those costs and the market prices of electricity will affect our financial results. Since the price we obtain for electricity may not change at the same rate as the change in coal or natural gas costs, we may be unable to pass on the changes in costs to our customers.

In addition, actual power prices and fuel costs will differ from those assumed in financial models used to value our trading positions, and those differences may be material. As a result, our financial results may fluctuate significantly and unpredictably in the future as some of those trading positions are marked to market.

Because we may not always fully hedge against changes in commodity prices, we will bear the risk of price changes.

To manage our financial exposure to commodity price fluctuations, we routinely enter into contracts, such as electricity, coal and natural gas purchase and sale commitments, to hedge our exposure to fuel supply and demand, market effects due to weather and other energy-related commodities. However, we do not necessarily hedge the entire exposure of our operations from commodity price volatility for a variety of reasons. To the extent we fail to hedge against commodity price volatility, our results of operations and financial position will be affected either favorably or unfavorably by price changes.

If our risk management, wholesale marketing, fuel procurement, and energy trading policies do not work as planned, our results of operations may suffer.

Our risk management, wholesale marketing, fuel procurement, and energy trading procedures may not always work as planned. As a result, we cannot predict the impact that our risk management, wholesale marketing, fuel procurement and energy trading decisions may have on our business, operating results or financial position.

Our risk management, wholesale marketing, fuel procurement and energy trading activities, including our power sales agreements with counterparties, rely on models that depend heavily on management's judgments and assumptions regarding factors such as the future market prices and demand for electricity and other energy-related commodities. These factors become more difficult to predict and the models become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these models, there may nevertheless be an adverse impact on our financial position and results of operations, if the judgments and assumptions underlying those models prove to be wrong or inaccurate.

Parties with whom we have contracts may fail to perform their obligations, which could adversely affect our results of operations.

We purchase coal from a limited number of suppliers. In 2001, we purchased in excess of 63% of our coal from one supplier. Any disruption in the delivery of coal, including disruptions as a result of weather, labor relations or environmental regulations affecting our coal suppliers, could adversely affect our ability to operate our coal-fired facilities and thus our results of operations.

Delivery of natural gas to each of our natural gas-fired facilities typically depends on the natural gas pipeline or distributor for that location. As a result, we are subject to the risk that a natural gas pipeline or distributor may suffer disruptions or curtailments in its ability to deliver natural gas to us or that the amounts of natural gas we request are curtailed. These disruptions or curtailments could adversely affect our ability to operate natural gas-fired generating facilities and thus our results of operations.

In addition, we are exposed to the risk that counterparties that owe us money or energy will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. In that event, our financial results are likely to be adversely affected and we might incur losses. Although our models take into account the expected probability of default by a counterparty, our actual exposure to a default by a counterparty may be greater than the models predict.

Material changes in the fair value of our power sales agreement with the California Department of Water Resources, including as a result of its possible breach or renegotiation, may have a material impact on AE Supply's results of operations.

In March 2001, AE Supply entered into a power sales agreement with the California Department of Water Resources (CDWR), the electricity buyer for the state of California. This agreement is in force for a period through December 2011. Under this agreement, AE Supply has committed to supply California with contract volumes varying from 150 MW to 500 MW through December 2004. For the last seven years of the contract, the contract volume will be fixed at 1,000 MW. The contract contains a fixed price of $61 per MWh. As of December 31, 2001, the reported prices for comparable delivery of power in California during times of peak demand in 2004 (the last year with publicly quoted prices) was $36.25 per MWh, and the fair value of AE Supply's agreement with the CDWR was approximately 22% of AE Supply's total assets. AE Supply records changes in the fair value of this agreement in AE Supply's statement of operations in wholesale revenues.

On February 21, 2002, the California Public Utilities Commission (California PUC) issued a rate agreement with the CDWR, in order for the CDWR to issue bonds to repay the state of California's general fund and other outstanding loans. The rate agreement requires the CDWR to use its best efforts to renegotiate its long-term power agreements, including its agreement with AE Supply, and it does not

limit the ability of the California PUC or the CDWR to engage in litigation regarding those contracts.

Our February 25, 2002, the California PUC and the California Electricity Oversight Board (CAEOB) filed complaints with the FERC seeking to abrogate various contracts to which the CDWR is a counterparty, including two contracts with AE Supply to sell power to CDWR. The California PUC alleges that the contracts are unjust and unreasonable due to market dysfunction and the exercise of market power by electricity suppliers during 2001 in California. As a result, the California PUC argues that the CDWR was forced to pay prices that are too high and accept onerous terms and conditions. In the alternative, the California PUC requests that the FERC reform the challenged contracts to provide just and reasonable pricing, reduce the duration of the contracts, and eliminate certain non-price terms. AE Supply is unable to predict the outcome of this litigation or the financial impact it may have on AE Supply.

If our agreement was renegotiated or the CDWR failed for any reason to meet its obligations under this agreement, the value of the agreement as an asset might need to be reduced on AE Supply's consolidated balance sheet, with a corresponding reduction in net income.

Our facilities may perform below expectations, require costly repairs or require us to purchase replacement power.

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. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution facilities. If our facilities operate below expectations, we may lose revenues or have increased expenses, including replacement power costs. A significant portion of our facilities were originally constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures on our part to keep operating at peak efficiency and is also likely to require periodic upgrading and improvement.

We have only a limited operating history in a market-based competitive environment and may not successfully adapt to that environment.

Our power generation facilities have historically been operated within vertically-integrated, regulated utilities that sold electricity to consumers at prices based on predetermined rates set by state public utility commissions. Most of these facilities are now owned by our unregulated operating subsidiary, AE Supply which, unlike regulated utilities, does not benefit from predetermined rates that include a rate of return component. Also, AE Supply's revenues and results of operations are likely to depend, in large part, upon prevailing market prices for electricity in our regional markets and other competitive markets, the volume of demand, capacity and ancillary services. Operating successfully in this new market-based, competitive environment requires different skills and expertise than the regulated market. As the markets for power, capacity and services develop, consumers may change their behavior. We have a limited operating history for these facilities in the new environment and we may not be able to operate them successfully in that environment.

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 transmission and distribution facilities owned and operated by utilities and other 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 its products. If a region's power transmission infrastructure is inadequate, AE Supply's recovery of costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

FERC has issued power and gas transmission initiatives that require electric and gas transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions for electricity and gas, fair and equal access to transmission systems may in fact not be available. Natural gas pipelines and transmitting electric utilities have filed open access tariffs in response to these initiatives, but some utilities may not fully comply with the terms of those tariffs. We also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

Changes in technology may significantly affect our business by making our power plants less competitive.

A key element of our business model is that generating power at central power plants achieves economies of scale and produces electricity at relatively low cost. There are other technologies that produce electricity, most notably fuel cells, micro turbines, windmills and photovoltaic (solar) cells. It is possible that advances in technology will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central power station electric production. Decreasing demand for higher quality power may also improve the competitive position of these alternative sources of power. If these things were to happen and if these technologies achieved economies of scale, our market share could be eroded, and the value of our power plants could be significantly impaired. Changes in technology could also alter the channels through which retail electric customers buy electricity, thereby affecting our financial results.

Our operating results may fluctuate on a seasonal and quarterly basis.

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. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis. The pattern of this fluctuation may change depending on the geographical location of facilities we acquire and the characteristics of such facilities, such as, whether they are base-load or peaking facilities, as well as on the terms of power sale contracts we enter into.

The loss of our key executives or our failure to attract qualified management and other employees could limit our growth and negatively affect our operations.

The success of our business relies, in large part, on our ability to attract and retain talented employees who possess the experience and expertise required to manage our business and its growth successfully. Our current key executives have substantial experience in our industry. It may be difficult to find senior executives with similar background and experience. The unexpected loss of services of one or more of these individuals could adversely affect our ability to effectively manage our operations. Likewise, we rely, in a large part, on specially skilled employees to run our plants. Because the market for employees with the appropriate skills is tight in many regions, our inability to attract employees of a similar caliber in the future could limit our ability to appropriately manage facilities in certain markets, which, in turn, could hamper our efforts to successfully expand into those markets and thus limit our growth.

Because we may not be able to respond effectively to competition, we may not be able to maintain our revenues and earnings levels.

We may not be able to respond in a timely or effective manner to the many changes in the power industry resulting from regulatory initiatives to increase competition. Until quite recently, we operated as part of an integrated public utility system subject to rate regulation. We must now adapt to the new competitive environment, where we need new and different skills to succeed. If we do not manage this transition successfully, our results may suffer. In addition, we remain subject to significant regulatory constraints for example, requirements under the PUHCA that may hinder our efforts to respond to the changing competitive environment in a timely manner or at all, and thus also hurt our results of operations.

Industry deregulation may facilitate the current trend toward consolidation in the utility industry but may also encourage the disaggregation of vertically integrated utilities into separate generation, transmission and distribution businesses. As a result, additional and more formidable competitors in our industry may arise, and we may not be able to maintain our revenues and earnings levels or pursue our growth strategy.

While demand for electric energy services is generally increasing throughout the United States, the rate of construction and development of new, more efficient electric generation facilities may exceed increases in demand in some regional electric markets. The start-up of new facilities in the regional markets in which we have facilities could increase competition in the wholesale power market in those regions, which could have a material negative effect on our business, results of operations and financial condition. Also, industry restructuring in regions in which we have substantial operations could affect our operations in a manner that is difficult to predict, since the effects will depend on the form and timing of the restructuring.

Our costs of compliance 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, and in particular air emission regulations, could have a material impact on our industry, our business and our results of operations and financial condition, especially 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 anticipate that we will incur considerable capital costs for compliance.

We plan to install new emissions control equipment and may be required to upgrade existing equipment, purchase emissions allowances or reduce operations. During 2002 and 2003, we expect to spend approximately $244.7 million in connection with the installation of emission control equipment at our facilities and other compliance-related measures. This amount includes $52.4 million in expenditures relating to the remaining generating assets that we expect to transfer to AE Supply from Monongahela. Moreover, environmental laws are subject to change, which may materially increase our costs of compliance or accelerate the timing of these capital expenditures.

We may experience shutdowns if we are unable to obtain all required environmental approvals.

We may not be able 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, temporarily closed 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.

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 us or our facilities. For example, the laws governing nitrogen oxides (No_x) and sulfur dioxide (SO₂) emissions from coal-burning plants are being re-interpreted by federal and state authorities. These re-interpretations could result in limitations on these emissions 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.

In addition, the Environmental Protection Agency, or the EPA, is developing new policies concerning protection of endangered species and sediment contamination, based on a new interpretation of the Clean Water Act. The scope and extent of any resulting environmental regulations, and their effect on our operations, is unknown.

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 and fines against us and significant capital expenditures. Recent lawsuits by the EPA and various states highlight the environmental risks faced by 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 Amendments. 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. 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 lawsuits.

We could incur 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 are unlikely to be able to pass on the cost of environmental compliance to our customers.

Most of our contracts with customers do not permit us to recover additional capital and other costs incurred by us 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 profitability.

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 AE Supply facilities where suitable alternative materials are not available. Also, although AE Supply did not contractually assume any liabilities for asbestos claims or any other environmental claims when the Distribution Companies transferred generating assets to it, AE Supply may be named as a co-defendant with the Distribution Companies in pending asbestos claims involving multiple plaintiffs. AE Supply 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 AE Supply facilities, which could result in actions being brought against AE Supply, claiming exposure to asbestos or other hazardous substances.

We are negotiating a collective bargaining agreement, and we may suffer work interruptions.

Since May 2001, our largest union representing over 1,100 of our employees has been working under an expired contract. While we are in negotiations with the union covered by the expired agreement and we do not currently anticipate any problems in reaching a new agreement, there is a risk that a new agreement may not be entered into without work interruptions or other pressure tactics. Any lengthy work interruptions could reduce our ability to meet customers' needs and materially and adversely affect our revenues or increase our costs.

Risks Associated With AE Supply's Financing
And Capital AND CORPORATE Structure

If we are unable to obtain external financing at rates and on terms we determine to be attractive, we may be unable to fund our growth and to meet the cash needs for our operations
.

In the past, to meet ongoing cash needs for operating expenses, the payment of interest, retirement of debt and for our acquisition and construction programs, we have used internally generated funds (net cash provided by operating activities less dividends) and external financings, such as debt and equity offerings, bank credit and lease arrangements. Our business continues to be capital-intensive and achievement of our development targets is dependent, at least in part, upon our ability to access capital at rates and on

terms we determine to be attractive. Our ability to obtain external financing capital and our borrowing costs could be impaired if, among other things, we fail to maintain an investment grade credit rating, as well as factors that are not specific to us, such as a severe disruption on the financial markets or market views about the prospects for the energy industry generally. If we are unable to access capital at rates and on terms we determine to be attractive, it could have a significant impact on our ability to meet our cash needs.

AE Supply will have substantial indebtedness, which could restrict its activities and could affect its ability to meet its obligations.

AE Supply incurred substantial indebtedness to finance its acquisitions of the Energy Marketing and Trading division and the Midwest Assets. AE Supply anticipates incurring additional substantial indebtedness to support future acquisitions and capital expenditures and to maintain working capital. AE Supply had, as of December 31, 2001, total indebtedness of approximately $2.42 billion.

In order to accommodate the changing nature of AE Supply's business, we needed and obtained waivers and amendments of certain covenants contained in up to $1.7 billion of Supply's credit facilities and lease documents. Future indebtedness may be on terms that are more restrictive or burdensome than AE Supply's current indebtedness. This may negatively affect its ability to operate its business and have a material adverse effect on its ability to acquire, construct or develop new facilities.

AE Supply's level of indebtedness may have important consequences, including:

     -  making it more difficult to satisfy its obligations under outstanding notes;

     -  limiting its ability to borrow additional amounts for capital expenditures, future acquisitions, significant working capital requirements to conduct its risk management, wholesale marketing, fuel procurement and energy trading activities as well as for other corporate purposes;

     -  limiting its ability to use operating cash flow in other areas of its business, such as for capital expenditures and future acquisitions, because it must dedicate a substantial portion of these funds to service its debt;

     -  limiting its ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in government regulation, including increasingly stringent environmental regulations; and

     -  subjecting it to financial and other restrictive covenants with which it may fail to comply, which could result in an event of default.

AE Supply's ability to meet its payment obligations under its indebtedness, including outstanding notes, and to fund capital expenditures will depend on its future performance. AE Supply's future performance is subject to regulatory, economic, financial, competitive, legislative and other factors that are beyond its control and are discussed elsewhere in these risk factors. Its cash flow from operations may not be sufficient to meet all of its payment obligations under its debt, including the outstanding notes, or to fund its other liquidity needs.

We have adopted anti-takeover measures that could make a third-party acquisition of us difficult, even if that acquisition would be beneficial to our stockholders.

Provisions of our bylaws, our stockholder rights plan and anti-takeover provisions of Maryland law could make it difficult for a third party to acquire control of us. As permitted by Maryland law, our bylaws provide for a classified board, with board members serving staggered three-year terms. We also have

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. In addition, we have 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% or more of our outstanding common stock or an unsolicited tender offer for those shares. While the purpose of the staggered board and rights plan is to prevent abusive takeover tactics and to protect our stockholders' investment in us, they could have the effect of preventing or making more difficult an acquisition or change in control that shareholders, in their judgment, might have favored.

RISKS ASSOCIATED WITH A CHANGING ECONOMIC ENVIRONMENT

In response to the September 11, 2001 terrorists' attacks on the United States and the ongoing war against terrorism by the United States, the financial markets have been disrupted in general. Additionally, the availability and cost of capital for our business and that of our competitors could be adversely affected by the bankruptcy of Enron Corporation. These events could constrain the capital available to our industry and could adversely affect our access to funding for our operations, the demand for and pricing of our products and the financial stability of our customers and counterparties in transactions.

COMPETITION

Natural Gas Competition

Prior to 1978, the FERC, pursuant to the dictates of the Natural Gas Act (NGA), established prices for natural gas. Interstate pipelines purchased gas at the wellhead and delivered that gas at regulated rates to local distribution companies (LDCs) such as Mountaineer and West Virginia Power. The LDCs, in turn, distributed gas to industrial, commercial, and residential customers at rates regulated by the states, which permitted pass through of the interstate pipeline costs (including both the cost of the gas commodity itself as well as the pipelines' delivery costs). There was little choice for LDCs in either the market for natural gas or transportation capacity.

In Order No. 636, issued in 1993, the FERC found that the pipelines' provision of a bundled sales service had anticompetitive effects that limited the benefits of open access service and wellhead price decontrol. As a result, the FERC required pipelines to separate their sales of gas from their transportation service and to provide comparable transportation service to all shippers whether they purchased gas from the pipeline or another gas seller. The FERC further adopted initiatives to increase competition for pipeline capacity in order to reduce the prices paid for transportation and ultimately the overall price customers pay for gas. The FERC allowed firm holders of pipeline capacity to resell or release their capacity to other shippers and required pipelines to permit shippers to use flexible receipt and delivery points. Enabling firm shippers to resell their capacity created competitive alternatives to purchasing pipeline services. The ability to use flexible receipt or delivery points also expanded the alternatives available to buyers of capacity because it meant that buyers were not restricted to using the specific geographic (known as "primary") receipt or delivery points in the releasing shipper's contract.

As a result of the foregoing, as well as numerous state open access and unbundling efforts, LDCs began to contract separately for (1) gas supplies in the production areas or basins, and (2) transportation service from pipelines. Large industrial customers began to do the same. Market centers began to

develop across the nation to facilitate the buying and selling of natural gas, and in 1990, the New York Mercantile Exchange (NYMEX) established a natural gas futures market using the Henry Hub as the physical market exchange center. Shippers and marketers began to use the capacity release mechanism as an alternative to obtaining transportation service from the pipeline, particularly for short-term service.

On February 9, 2000, the FERC issued Order No. 637 that was intended to (1) provide new economic opportunities for industry participants (including providing captive customers with the opportunity to reduce their cost of holding long-term upstream interstate pipeline capacity), and (2) improve efficiency within the Order No. 636 open access gas transportation marketplace, while still protecting against the exercise of market power.

Today's natural gas market continues to change, and is substantially different operationally and economically from the market in 1993 or even 2000. Upstream and downstream wholesale markets are maturing. As part of this process, both upstream and downstream market centers and gas trading points are increasing in number, providing shippers with greater gas and capacity choices. The financial marketplace has developed a myriad of financial derivative contracts dealing with natural gas that better enable the contracting parties to hedge against price risk. Electronic commerce has grown rapidly, providing greater liquidity in commodity markets, with the promise of providing such liquidity in the transportation market as well. The natural gas industry is relying on self-regulation to develop standards for business and electronic processes that create greater efficiency in moving gas across the integrated pipeline grid. There is greater integration between the natural gas and the electric generation market, with gas usage for power generation expected to grow substantially in both the near and long-term future. Residential unbundling at the state level is well underway nationwide which may provide the opportunity for small commercial firms and residential customers to purchase their own gas supplies in a competitive market.

Electric Energy Competition

The electricity supply segment of the electric utility industry in the United States is becoming increasingly competitive. The national Energy Policy Act of 1992 deregulated the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over utilities' transmission systems. Allegheny continues to be an advocate of federal legislation to remove artificial barriers to competition in electricity markets, avoid regional dislocations, and ensure a level playing field. In addition to the wholesale electricity market becoming more competitive, certain states have taken active steps toward allowing retail customers the right to choose their electricity supplier.

Allegheny is at the forefront of state-implemented retail competition, having negotiated settlement agreements in all of the states that the Distribution Companies serve. Pennsylvania, Maryland, Virginia and Ohio have retail choice programs fully in place. In 2000, West Virginia's Legislature approved a deregulation plan pending additional legislation regarding tax revenues for state and local governments and allowing implementation. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may consider the plan in 2002, the current climate regarding restructuring makes this unlikely. The future of competitive choice in West Virginia is therefore uncertain.

The regulatory environment applicable to AE's generation and T&D businesses will continue to undergo substantial changes on both the federal and state level. These changes have significantly affected the nature of the electric industry and the manner in which its participants conduct their business. Moreover, existing statutes and regulations may be revised or reinterpreted, new laws and regulations

may be adopted or become applicable to AE or its facilities, and future changes in laws and regulations may have an effect on AE in ways that cannot be predicted and could have a material effect on AE and its subsidiaries' operations and strategies. Some markets, like California, have experienced interruptions of supply and price volatility, which have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some markets, including California, government agencies and other interested parties have made proposals to re-regulate areas of these markets that have been deregulated, and, in California, legislation has been passed placing a moratorium on the sale of generating plants by regulated utilities. Proposals to re-regulate the wholesale power market have been made at the federal level. Proposals of this sort, and legislative or other attention to the electric power restructuring process in the states in which AE and its subsidiaries currently operate, or may in the future operate, may cause deregulation to be delayed, discontinued, or reversed, which could have a material effect on AE and its subsidiaries' operations and strategies.

In response to the occurrence of several recent events, including the bankruptcy of Enron corporation, the September 11, 2001, terrorists' attacks on the United States, and the ongoing war against terrorism by the United States, the financial markets have been disrupted in general, and the availability and cost of capital for Allegheny's business and that of competitors could be adversely affected. These events could constrain the capital available to the industry and could adversely affect Allegheny's access to funding for its operations, the demand for and pricing of its products, and the financial stability of its customers and counterparties in transactions.

Activities at the Federal Level

The terrorists' attacks of September 11, 2001 have altered the agenda of the 107^th Congress. In fact, some legislative initiatives have been delayed or postponed since that date because the Congress and the Bush Administration have been focused on responding to these attacks. However, part of that response may well be the consideration of energy security legislation currently in development. Allegheny is lobbying for the inclusion of important electricity restructuring provisions in this legislation, including the repeal or significant revision of PUHCA, as well as for critical infrastructure protection legislation. Prior to the attacks, two primary bills had been introduced in the U.S. Senate: S. 388, for former Energy and Natural Resources Committee Chairman Senator Frank Murkowski of Alaska, and S. 597, by the committee's new chairman, Senator Jeff Bingaman of New Mexico. Provisions from these bills could be included in the new energy legislation. The House Energy and Commerce Committee initially passed the President's national energy security proposal and is only now considering accompanying electricity-restructuring legislation. Among issues that are being addressed in this legislation are the repeal or significant revision of PUHCA and Section 210 (Mandatory Purchase Provisions) of the Public Utility Regulatory Policies Act, or PURPA. Allegheny continues to advocate the repeal of PUHCA and Section 210 of PURPA on the grounds that they are obsolete and anticompetitive and that PURPA results in utility customers paying above-market prices for power. Separately, the Senate Banking Committee in April 2001 approved S. 206, legislation to repeal PUHCA.

The bankruptcy of Enron has further altered the agenda of Congress. This has led to additional debate over PUHCA and other regulatory mechanisms affecting the electric and gas industries, including proposals introduced in 2002 for regulating electric and gas commodity trading and certain energy-related derivatives transactions.

Other legislative initiatives considered in Congress in 2001 with the potential to significantly affect Allegheny's business included:

Proposals relating to FERC jurisdiction over mergers and acquisitions and

transfers of assets of public utilities under the Federal Power Act.

Proposals relating to FERC authority to authorize market-based wholesale generation rates.

Proposals relating to FERC authority to address market power, order refunds, and impose penalties on public utilities under the Federal Power Act.

Proposals relating to FERC oversight of electric transmission and distribution service, including mandatory uniform standards for interconnection to facilities.

Proposals relating to FERC jurisdiction to mandate the formation and joining of Regional Transmission Organizations.

Proposals relating to the further regulation of air emissions, including mercury and carbon dioxide.

Although consideration of these proposals, as well as PUHCA and PURPA reform, is expected to continue in the second session of the 107^th Congress in 2002, it is unknown whether any of these proposals will be enacted. Thus, the effect on Allegheny's business is uncertain.

Federal regulatory initiatives undertaken by FERC and the Environmental Protection Agency having the potential to significantly affect Allegheny's business are discussed in ITEM 1 Part 1 BUSINESS "Regulatory Framework Affecting Electric Power Sales" and "Environmental Matters."

Activities at the State Level

Maryland

In 1999, Maryland adopted electric industry restructuring legislation that brought competition to Maryland's electric supply market. As of July 1, 2000, Potomac Edison's retail electric customers in Maryland had the right to choose their generation supplier. Pursuant to the legislation, Potomac Edison transferred its Maryland jurisdictional generation assets at book value to AE Supply in 2000 (except for 3 MW of Virginia hydroelectric facilities which were transferred in 2001 to a subsidiary of Potomac Edison that was dividended to AE). The T&D assets remain with Potomac Edison under regulated ratemaking. Potomac Edison has responsibility as the provider-of-last-resort (for those customers of Potomac Edison who choose not to select an alternate supplier or whose alternate supplier does not deliver). Pursuant to long-term power sales agreements, AE Supply provides Potomac Edison with the amount of electricity, up to its provider-of-last-resort retail load (and for certain wholesale contracts), that it may demand during the Maryland transition period. These agreements (and those that AE Supply has with West Penn and Monongahela) 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.

Until January 1, 2004, AE Supply may market the deregulated generation within Maryland with the restrictions that a) it may not market to retail customers within Potomac Edison's Maryland distribution service territory and b) if selling to retail customers outside of Potomac Edison's distribution service territory but within Maryland, it must offer to sell energy of at least 75 MW annually to non-affiliated

licensed suppliers. On January 1, 2004, AE Supply may begin marketing deregulated generation within Maryland without these restrictions. AE Supply is licensed as a competitive retail electric service provider in Maryland.

On July 1, 2000, the Maryland Public Service Commission (Maryland PSC) issued a restrictive order imposing standards of conduct for transactions between Maryland utilities and their affiliates. Among other things, the order: restricts sharing of utility employees with affiliates; announces the Maryland PSC's intent to impose 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"; and requires asymmetric pricing for asset transfers between utilities and their affiliates. Asymmetric pricing requires that transfers of assets from the regulated utility to an affiliate be recorded at the greater of book cost or market value while transfers of assets from the affiliate to the regulated utility be recorded at the lesser of book cost or market. This order did not apply to the transfer of Potomac Edison's generation assets to AE Supply. Asymmetric pricing also does not apply to the power sales agreement between Potomac Edison and AE Supply.

Potomac Edison, along with substantially all of Maryland's gas and electric utilities, filed a Circuit Court petition for judicial review and a motion for stay of the restrictive order. In November 2000, the Circuit Court granted a partial stay of the Maryland PSC's code of conduct/affiliated transactions order on the issues of employee sharing, royalties for the use of the name and logo and for certain intangibles, and on the requirement to use a disclaimer on advertising for non-core services. In April 2001, the Circuit Court issued its decision affirming in part and reversing and remanding in part the Maryland PSC's decision. The Court found that the Maryland PSC's decision adopting asymmetric pricing for Potomac Edison was contrary to federal law. Potomac Edison, along with substantially all of Maryland's gas and electric utilities, appealed the Circuit Court's decision to the Maryland Court of Special Appeals. The Court of Appeals, Maryland's highest court, asserted its jurisdiction over the appeal and has heard arguments. A decision is expected in 2002.

Ohio

The Ohio General Assembly passed legislation in 1999 to restructure its electric utility industry. As of January 1, 2001, retail electric customers in Ohio have the right to choose their electric generation supplier, starting a five-year transition to market rates. Two utilities, including Monongahela, have a shorter transition period for larger customers. Ohio's residential customers were guaranteed a 5% reduction in the generation portion of rates by the legislation.

The Ohio Public Utilities Commission (PUCO) approved in 2000 a transition plan to bring electric choice to Monongahela's 29,000 Ohio customers. The restructuring plan allowed Monongahela to transfer its Ohio jurisdictional generating assets to AE Supply at net book value, which was completed on June 1, 2001. Monongahela has responsibility as the provider-of-last-resort (for those customers of Monongahela who choose not to select an alternate supplier or whose alternate supplier does not deliver). Pursuant to a long-term power sales agreement, AE Supply will provide Monongahela with the amount of electricity, up to its provider-of-last-resort retail load, that it may demand during the Ohio transition period. This agreement (and those that AE Supply has with Potomac Edison and West Penn) 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 is licensed as a competitive retail electric service supplier in Ohio.

Pennsylvania

The Customer Choice Act in Pennsylvania provides for customer choice of electric supplier and deregulation of generation in a competitive electric supply market. As of January 2, 2000, retail electric customers in Pennsylvania had the right to choose their electric generation supplier. Pursuant to the Customer Choice Act in 1999, West Penn transferred its generation assets to AE Supply. The T&D assets remain with West Penn under regulated ratemaking.

West Penn has responsibility as the provider-of-last-resort (for those customers of West Penn who choose not to select 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 its provider-of-last-resort retail load (and for certain wholesale contracts), that it may demand during the Pennsylvania transition period. These agreements (and those that AE Supply has with Monongahela and Potomac Edison) 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 is licensed as a competitive retail electric service supplier in Pennsylvania.

Virginia

The Virginia Electric Utility Restructuring Act (the Act) was enacted in 1999, and provides for a transition to customer choice of electric suppliers for Virginia customers beginning January 1, 2002. As of January 1, 2002, Potomac Edison retail electric customers in Virginia have the right to choose their electric generation supplier.

Pursuant to the Act, Potomac Edison transferred its Virginia jurisdictional generating assets to AE Supply, including the transfer of four small Virginia hydroelectric facilities to a subsidiary of Potomac Edison in 2001, which was dividended by Potomac Edison to AE. The T&D assets remain with Potomac Edison under regulated ratemaking. Potomac Edison has responsibility as the provider-of-last-resort (for those customers of Potomac Edison who choose not to select 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 its provider-of-last-resort retail load (and for a certain wholesale contract), that it may demand during the transition period. This agreement (and those that AE Supply has with Monongahela and West Penn) 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.

On December 21, 2001, the Virginia State Corporation Commission (Virginia SCC) approved phase 2 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 the PJM Interconnection, LLC under an arrangement known as "PJM West." The transfer was initially to be effective January 1, 2002, but because of lack of FERC approvals, operation of PJM West has been delayed until April 1, 2002. See ITEM 1. REGULATORY FRAMEWORK AFFECTING ELECTRIC POWER SALES for more information regarding PJM West.

AE Supply is licensed in Virginia as a competitive retail electric service provider.

West Virginia

In March 1998, the West Virginia Legislature passed legislation directing the Public Service Commission of West Virginia (West Virginia PSC) to determine whether retail electric competition was in the best interests of West Virginia and its citizens. The West Virginia PSC submitted an electric restructuring plan to the legislature for approval. The plan would have opened full retail competition on January 1, 2001. On March 11, 2000, the West Virginia Legislature approved the West Virginia PSC's plan, but withheld authority to implement the plan until the legislature addressed certain tax issues and authorized implementation. A report was submitted to the legislature on the tax issues, but no action was taken by the legislature in 2001. Given the national climate regarding electric restructuring, it remains uncertain whether the West Virginia Legislature will address the issue in the 2002 session.

Monongahela has filed a petition seeking the West Virginia PSC's approval of the transfer of its West Virginia jurisdictional generating assets to AE Supply. However, the West Virginia PSC has not yet acted on this petition, and Monongahela cannot be sure whether it will be permitted to transfer those generation assets, or when permission might be granted. If the transfer is permitted, Monongahela cannot predict the conditions that may be imposed in connection with the transfer, such as provider-of-last-resort agreement obligations, transfer costs or transition periods that may make the transfer uneconomical.

In 2000, the West Virginia PSC approved Potomac Edison's request to transfer Potomac Edison's West Virginia jurisdictional generating assets to AE Supply. Potomac Edison's West Virginia assets were transferred in August 2001. Assets are being leased back to Potomac Edison. The lease, in combination with a power supply agreement, between AE Supply and Potomac Edison, provides electricity consumed by all of Potomac Edison's West Virginia customers since they are not yet able to shop for alternate suppliers in West Virginia. By agreement, Potomac Edison and Monongahela implemented a commercial and industrial rate reduction program on July 1, 2000. A stipulated agreement reached on September 14, 2000, on the unbundled tariffs filed by Monongahela and Potomac Edison is awaiting a final order from the West Virginia PSC.

The West Virginia PSC has convened a Gas Codes of Conduct Working Group to develop a generic code of conduct governing the provision of open access to the gas supply market and gas utilities' conduct toward their affiliates and competitive suppliers, as well as rules for licensing gas suppliers and for consumer protection.

Competitive Actions

Over the past several years Allegheny has taken action to deal with deregulation and better position itself to participate in the new competitive generation supply markets.

AE SUPPLY

AE Supply is a national energy company. AE Supply was formed in November 1999 to take advantage of the opportunity to transfer to AE Supply at net book value some of the generation assets of

the Distribution Companies as a result of economic factors and federal and state legislative and regulatory changes related to the development of competitive markets.

As of December 31, 2001, AE Supply owned or contractually controlled 8,895 MW in the Eastern and Midwestern regions of the United States and had the contractual right to call up to 1,000 MW in California. AE Supply is expanding its generation fleet through the announced construction and development of new facilities, acquisition of contractual rights to control generating capacity and planned expansions to existing facilities. AE Supply manages all of its generation assets as an integrated portfolio with its risk management, wholesale marketing, fuel procurement and energy trading activities.

AE Supply has taken significant steps to develop a national business with the acquisition of the Energy Marketing and Trading division from Merrill Lynch and acquisition and construction and development activities in the Eastern, Midwestern and Southwestern regions of the United States. AE Supply has construction and development projects under way in Arizona, Indiana, Pennsylvania, Virginia and New York.

Pursuant to long-term power sales agreements, AE Supply supplies Monongahela, West Penn and Potomac Edison with generation service during the Pennsylvania, Maryland, Ohio, and Virginia transition periods. Under these agreements, AE Supply provides the Distribution Companies with the amount of electricity, up to their provider-of-last-resort retail load and in certain instances, wholesale load obligations, that they may demand during the transition periods in their states. These agreements 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, 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 generating capacity AE Supply must deliver under these agreements 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.

Development, Acquisitions and Transfers of Generating Assets and Generating Capacity

Eastern Region.

Acquisitions. On December 31, 2001, the FERC and the SEC granted approval for AE Supply to own an additional 46 MW of capacity within the PJM market once the capacity from the Hunlock Creek facility in Pennsylvania is transferred by AE to AE Supply. AE Supply expects the transfer will occur in the first half of 2002. This additional capacity may be characterized as a combination of intermediate and peaking generation. All units other than the peaking generation unit are coal-fired generation facilities. The peaking generation unit is a natural gas-fired facility. Currently, Allegheny Energy Supply Hunlock Creek, LLC, a subsidiary of AE, is entitled to 50% of both the intermediate and peaking generation capacity from this facility pursuant to the terms of a joint-venture with UGI Corporation. Allegheny Energy Supply Hunlock Creek, LLC's 50% entitlement in the joint venture provides it with 46 MW of generating capacity in the PJM market.

Developments. AE Supply is constructing a 540 MW combined-cycle generating plant in Springdale, Pennsylvania. This facility will include two gas-fired combustion turbines and one steam turbine. AE Supply expects to complete this construction in 2003. AE Supply is initially leasing this facility.

During 2001, AGC's share of generating capacity at the Bath County facility increased by 120 MW, from 840 MW to 960 MW. After reviewing engineering tests with the equipment manufacturer, it was

determined that the operating limits had been more conservative than necessary.

During 2001, AE Supply announced plans for a joint development project through which it will obtain 44 MW of new simple-cycle combustion turbine capacity located in Buchanan County, Virginia, and for the development of a 79 MW barge-mounted, natural gas fired combustion turbine generating facility to be located in the Brooklyn Navy Yard, New York.

Transfers. In June 2001, AE Supply completed the transfer from Monongahela of approximately 352 MW of its Ohio and FERC jurisdictional generating assets, including part of Monongahela's ownership interest in AGC.

In June 2001, AE Supply completed the transfer from AE of two 44-MW simple-cycle natural gas combustion turbines in Springdale, Pennsylvania by merging AE's subsidiary, Allegheny Energy Unit No. 1 & Unit No. 2, LLC, into AE Supply.

In June 2001, AE Supply completed the transfer from AE of 83 MW of generating capacity, representing an approximate 5% ownership interest, in the 1,711-MW Conemaugh generating station. AE purchased this capacity from Potomac Electric Power Company in January 2001 at a cost of approximately $78 million.

Midwest Region

Acquisitions. In May 2001, AE Supply acquired three recently constructed natural gas-fired generating facilities totaling 1,710 MW of peaking capacity. These generating facilities include the 656-MW Lincoln plant in Illinois, the 508-MW Wheatland plant in Indiana and the 546-MW Gleason plant in Tennessee (collectively, the Midwest Assets). The value of these assets is enhanced by their location, which allows AE Supply to charge fees for ancillary services to the transmission systems in these regions, in addition to providing energy in periods of peak demand.

Developments.
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. A combined cycle facility with 542 MW will be completed in 2005. Two 44-MW simple-cycle combustion turbines will be constructed as market conditions warrant. Upon completion in 2005, the facility will enhance AE Supply's ability to sell generation in Midwest markets. To finance the construction and the purchase of turbines and transformers for this facility, AE Supply entered into a leasing arrangement in November 2001.

Southwest Region

Acquisitions (Including Contractual Rights and Long-Term Purchases). AE Supply's acquisition of the Energy Marketing and Trading division provides it with the long-term contractual right to call up to 1,000 MW of natural gas-fired generating capacity of 14 units at three generating stations through May 2018.

In May 2001, AE Supply entered into an agreement with Las Vegas Cogeneration II, L.L.C. for a period of 15 years. Under this agreement AE Supply will have the contractual right to control 222 MW of generation capacity from a natural gas-fired, combined-cycle generating facility, currently under construction by a third party, in Las Vegas, Nevada beginning in the third quarter of 2002.

Developments. In October 2000, AE Supply announced plans to construct a 1,080 MW natural gas-fired generating facility in La Paz County, Arizona, approximately 75 miles west of Phoenix. AE Supply

expects to begin construction of the $540 million combined-cycle facility in 2002. When completed in 2005, the facility will allow AE Supply to sell generation power into Arizona, California and other states served by the Western Systems Coordinating Council.

AE Supply has long-term agreements with El Paso Natural Gas Company for the transportation of natural gas starting June 1, 2001 under tariffs approved by the FERC. These agreements, in part, provide for firm transportation of 7,222 thousand cubic feet (Mcf) of natural gas per day through September 30, 2006 from western Texas and northern New Mexico to the southern California border. The remainder of the agreements provide for firm transportation of 22,322 Mcf per day through September 30, 2009 from western Texas to the southern California border.

Energy Marketing and Trading Business Acquisition

In March 2001, AE Supply acquired Global Energy Markets, the energy marketing and trading business of Merrill Lynch, which now operates as AE Supply's Energy Marketing and Trading division. This division helps AE Supply optimize its portfolio of generating assets by significantly enhancing its risk management, wholesale marketing, fuel procurement and energy trading activities on a nationwide basis. It has also expanded AE Supply's expertise in risk management, market analysis, fuel procurement and nationwide trading. This division therefore provides AE Supply with valuable market intelligence to help AE Supply better identify opportunities to expand its acquisition and development activities and to compete outside its traditional regions. The acquisition included a long-term contractual right through May 2018 to call up to 1,000 MW of generating capacity in Southern California, which represents 25% of the total available capacity of three generating facilities. As part of the energy trading portfolio AE Supply acquired, the 1,000 MW contract was recorded at its fair value in its accounting for the purchase of this business. See Note E to AE Supply's consolidated financial statements for additional information regarding this acquisition.

Power Sales Agreements

AE Supply's acquisition of Merrill Lynch's energy marketing and trading business included the long-term contractual right to call up to 1,000 MW of natural gas-fired generating capacity in southern California and related hedges. In connection with this business acquisition, AE Supply evaluated the long-term and short-term risks associated with this portfolio in order to construct a prudent risk mitigation strategy. AE Supply concluded that the most significant risk was the changing relationship between the electricity and natural gas prices over time and the resulting effects on the value of AE Supply's contractual right to call up to 1,000 MW of generating capacity. In the short-term, unusually high prices and volatility in the electricity and natural gas markets were expected to continue. Given the prevailing levels of volatility in the electricity and natural gas markets and AE Supply's contractual right to call up to 1,000 MW of generating capacity, AE Supply implemented a hedging strategy. Accordingly, in March 2001, AE Supply closed a substantial part of its long position by entering into a power sales agreement with the CDWR, the electricity buyer for the state of California.

The agreement is for a period through December 2011. Under this agreement, AE Supply has committed to supply California with contract volumes varying from 150 MW to 500 MW through December 2004. For the last seven years of the contract, the contract volume will be fixed at 1,000 MW. AE Supply began delivering power under this agreement in late March 2001. The contract contains a fixed price of $61 per MWh.

AE Supply remained concerned about the forward cost of natural gas and electricity in California and the net position of the contractual right to call up to 1,000 MW of generating capacity. Consequently, AE Supply entered into a series of forward purchases through 2002 designed to hedge these risks. While

these forward purchases were made at then market prices, the price paid for these forward purchases exceeded the contractual price of the CDWR agreement. As a result, the CDWR agreement and related forward purchase hedges have negatively affected AE Supply's cash flows since March 2001. While this hedging strategy will result in short-term cash outflows through 2002, the total projected cash flows remain significantly positive. This hedging strategy is performing as designed.

In August 2001, AE Supply was the successful bidder to supply Baltimore Gas and Electric Company (BGE) with electricity from July 2003 through June 2006. AE Supply has committed to supply BGE with an amount needed to fulfill 10 percent of its provider-of-last-resort obligations. This amount is estimated to range from 200 MW to 530 MW.

In July 2001, AE Supply was named the electric generation supplier for eight boroughs in New Jersey that own and operate electric utilities as departments of municipal governments. The multi-year contracts will begin in June 2002. The contracts, which will supply 150 MW of electricity to the boroughs, will run through 2004.

ALLEGHENY VENTURES

Allegheny Ventures was formed in 1994 to engage in unregulated activities. Allegheny Communications Connect, Inc., (ACC) a Delaware corporation, and Allegheny Energy Solutions, Inc., (Allegheny Energy Solutions) a Delaware corporation, are both wholly owned subsidiaries of Allegheny Ventures.

Acquisitions

In November 2001, Allegheny Ventures completed the acquisition of Fellon-McCord Associates, Inc. (Fellon-McCord), an energy consulting and management services company, Alliance Gas Services, Inc., and Alliance Energy Services Partnership, a provider of natural gas and other energy-related services to large commercial and industrial customers. The purchase of these businesses has added gas procurement and energy management services to Allegheny Ventures' service offerings. Alliance Energy Services Partnership is owned 50% by Allegheny Ventures and 50% by Alliance Gas Services, Inc. Allegheny Ventures completed these acquisitions for $30.5 million in cash plus a maximum of $18.7 million in contingent consideration to be paid over a three-year period, starting from the November 1, 2001, acquisition date. On March 1, 2002, Alliance Gas Services, Inc. merged with Alliance Gas Services Holdings, LLC, a Maryland limited liability company and wholly owned subsidiary of Allegheny Ventures. Alliance Gas Services Holdings, LLC survived the merger. On March 1, 2002, Allegheny Ventures sold a 40% interest in Alliance Gas Services Holdings, LLC to Energy Corporation of America for $2.734 million.

On December 29, 2000, Allegheny Ventures signed an agreement to acquire Leasing Technologies International, Inc. (LTI), a financial services firm that specializes in equipment financing solutions for emerging growth companies for $26 million. During the second quarter of 2001, Allegheny Ventures notified LTI that it was terminating the purchase transaction as permitted by the agreement. LTI has reserved the right to pursue legal actions.

On February 13, 2001, Allegheny Ventures acquired a 10% equity interest in Utility Associates, Inc., a software development company that creates integrated mobile computing solutions for the utility industry. Allegheny Ventures is also a founding member and 3% owner of Enporion, Inc., a global procurement

exchange for the energy industry. Enporion simplifies the buying process through supply chain improvement.

In September 2000, ACC purchased a 40% membership interest in Odyssey Communications, LLC, a Pennsylvania limited liability company that is in the business of constructing fiber optic cable.

ACC also has five wholly owned subsidiaries: Allegheny Communications Connect of Virginia, Inc. (ACCVA), a Virginia corporation; Allegheny Communications Connect of Ohio, LLC (ACCOH), an Ohio limited liability company; Allegheny Communications Connect of Pennsylvania, LLC (ACCPA), a Pennsylvania limited liability company; Allegheny Communications Connect of West Virginia, LLC (ACCWV), a West Virginia limited liability company; and AFN Finance Company No. 2, LLC (AFN), a Delaware limited liability company.

AFN, LLC

In March 2000, ACC, along with five other energy and telecommunications companies and a consulting partner, created AFN, LLC (AFN), a super-regional, high-speed fiber and data services company. ACC received a 17 percent interest in AFN as a result of contributing 339 miles of lit fiber, including revenue from capacity contracts related to these routes, and 845 miles of committed dark fiber. AFN offers more than 7,700 route miles or 140,000 fiber miles, connecting major markets in the eastern United States to secondary markets. The initial footprint of fiber in AFN positioned it to reach areas responsible for roughly 35 percent of the national wholesale communications capacity market. AFN provides high-capacity telecommunications transport services to internet service providers, competitive local exchange providers, long-distance providers, and wireless communications companies.

AFN expects to expand its network from the current 7,700 route miles to 10,000 route miles or 200,000 fiber miles by the end of 2002. AFN will reach this capacity by adding partners with existing fiber, installing fiber in areas of opportunity, and acquiring existing fiber from others or contracting long-term lease agreements for existing fiber.

ACC continues to expand its own fiber optic network. In 2000, there were 1,300 route miles in its network. It was expanded to more than 1,900 route miles in 2001 and ACC plans to build nearly 800 additional route miles in 2002. ACC also provides value-added services to customers of the network and has recently started a pilot program in Greensburg, Pennsylvania to offer retail customers high-speed data services.

Allegheny Energy Solutions

In December 2001, Allegheny Energy Solutions executed an agreement to provide seven natural gas-fired turbine generators for the South Mississippi Electric Power Association (SMEPA). The seven units, with a combined output of approximately 450 MW, will be located at three sites in southern Mississippi near the towns of Sylvarena, Silver Creek and Moselle. The units will be owned by SMEPA. Construction is scheduled to begin in March 2002, with installation to be completed in May 2003 through May 2006. Allegheny Energy Solutions will provide design, construction, and installation services for the units.

Other Activities

During 2001, Allegheny Ventures did not make any new investments in funds that were established in 1995. Allegheny Ventures previously invested in EnviroTech Investment Fund I, Limited Partnership (EnviroTech), a limited partnership formed to invest in emerging electrotechnologies that promote the efficient use of electricity and improve the environment. Allegheny Ventures committed to invest up to $5 million in EnviroTech over 10 years, beginning in 1995. Allegheny Ventures also participates in The Latin American Energy and Electricity Fund I, L.P. (FondElec), a limited partnership formed to invest in and develop electric energy opportunities in Latin America. Allegheny Ventures committed to invest up to $5 million in FondElec over eight years, beginning in 1995. Through FondElec, Allegheny Ventures has invested in electric distribution companies in Peru, Brazil and Argentina. Both EnviroTech and FondElec may offer Allegheny Ventures opportunities to identify investments in which Allegheny Ventures may invest in excess of its capital commitment in each limited partnership.

Allegheny Ventures is also involved in marketing and developing the unused real estate holdings of the Distribution Companies.

SALES Regulated Electric Sales
	2001	2000	Increase/ (Decrease)
Regulated Utility Customers Kilowatt-hour Sales
Residential	14,454	14,062	2.8%
Commercial	9,616	9,510	1.1%
Industrial	19,884	20,320	(2.1)%
Wholesale	1,502	1,531	(1.9)%
Total Regulated Utility Customers Kilowatt-hour Sales	45,456	45,423	.1%

Regulated Revenue (Millions)
Residential	$1,002.1	$967.2	3.6%
Commercial	554.0	529.2	4.7%
Industrial	772.3	751.2	2.8%
Wholesale	66.6	55.8	19.4%
Total Regulated Revenue	$2,395.0	$2,303.4	4.0%

In 2001, consolidated regulated kilowatt-hour (kWh) sales delivered to customers of retail and wholesale power increased .1% from those of 2000 as a result of increases of 2.8% and 1.1%, in residential and commercial sales, respectively, and decreases of 2.1% and 1.9 % in industrial and wholesale sales, respectively. Consolidated regulated revenues increased 4.0% due to increases of 3.6%, 4.7%, 2.8%, and 19.4% in residential, commercial, industrial and wholesale sales, respectively. (See ITEM 1. RATE MATTERS and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.)

Allegheny's all-time Control Area Peak Load was 8,265 MW on August 9, 2001. (Control Area Load refers to the electricity sales to customers within the Distribution Companies' delivery territory without

regard to electric generation supplier.) The Control Area Load includes Regulated Load.

Consolidated regulated electric operating revenues for 2001 were derived as follows: Pennsylvania, 41.6%; West Virginia, 29.7%; Maryland, 20.9%; Virginia, 5.5%; and Ohio, 2.3% (residential, 37.4%; commercial, 20.7%; industrial, 28.8%; bulk power transactions, 3.8%; and other, 9.3%).

During 2001, Monongahela's kWh sales to retail customers decreased .7%. Residential and commercial sales increased 1.3% and .4%, respectively, and industrial sales decreased 2.2%. Revenues from residential customers increased .8% and commercial and industrial revenues decreased .2% and 2.5%, respectively. Electric revenues from residential customers increased due to an increase in customer usage coupled with an increase in the number of customers. Electric revenues from commercial and industrial customers decreased, primarily due to a decrease in customer usage. Revenues from bulk power transactions and sales to affiliates decreased 15.3% as a result of a decrease in sales to affiliates as affiliates are now securing their power requirements from Allegheny Energy Supply. Monongahela's regulated electric revenues represented 25.1% of Allegheny's total regulated electric sales revenues to customers. Monongahela's all-time Control Area Peak Load of 1,966 MW occurred on August 8, 2001.

Monongahela's electric operating revenues were derived as follows: West Virginia, 90.7%, and Ohio, 9.3% (residential, 33.1%; commercial, 20.5%; industrial, 30.6%; bulk power transactions, 1.8%; and other, 14.0%).

During 2001, Potomac Edison's kWh sales to retail customers increased 2.5%. Residential, commercial, and industrial sales increased 2.3%, 1.7% and 3.1%, respectively. Revenues from residential, commercial, and industrial sales increased 4.2%, 1.0%, and 6.1%, respectively. The increase in residential revenues was due to growth in the number of residential customers. The increase in revenue for commercial customers was due to an increase in the number of commercial customers served partially offset by a decrease in customer usage. The increase in industrial revenues was due to an increase in customer usage. Revenues from bulk power transactions and sales to affiliates decreased .5% as a result of an increase in bulk power sales due to the Company selling the AES Warrior Run output into the wholesale energy market partially offset by a decrease in sales to affiliates as a result of the transfer of the Company's generating capacity to Allegheny Energy Supply in August 2000. Potomac Edison's regulated electric revenues represented 31.6% of Allegheny's total regulated sales revenues to customers. Potomac Edison's all-time Control Area Peak Load of 2,732 MW occurred on August 6, 2001.

Potomac Edison's electric operating revenues were derived as follows: Maryland, 64.6%; West Virginia 18.3%, and Virginia, 17.1%; (residential, 40.2%; commercial, 19.2%; industrial, 25.6%; bulk power transactions, 7.5%; and other, 7.9%). Revenues from one industrial customer, the Eastalco aluminum reduction plant near Frederick, Maryland, amounted to $75.4 million (8.7% of total electric operating revenues). Minimum annual charges to Eastalco under an electric service agreement, which continues through April 1, 2003, with automatic extensions thereafter unless terminated on notice by either party, were $14.4 million in 2001.

During 2001, West Penn's regulated kWh sales and deliveries to retail customers decreased 1.3%. Residential and commercial sales deliveries increased 3.9% and 1.1%, respectively. Industrial sales deliveries decreased 5.8%. Regulated revenues from residential, commercial and industrial customers increased 4.7%, 10.6% and 4.3%.

The increases in revenues for residential, commercial and industrial customers were due primarily to the return of choice customers in the commercial and industrial classes to full service. Also contributing to higher revenues was an increase in the average number of customers in all retail customer classes. Revenues from bulk power transactions and sales to affiliates increased 3.2%. West Penn's regulated electric revenues represented 43.3% of Allegheny's total regulated electric sales to customers. West Penn's all-time Control

Area Peak Load of 3,677 MW occurred on August 6, 2001.

West Penn's regulated electric operating revenues were derived as follows: Pennsylvania, 100% (residential, 38.0%; commercial, 21.9%; industrial, 30.3%; bulk power transactions, 2.19%; and other, 7.7%).

In 2001, the Distribution Companies provided approximately 1.4 billion kWh of energy to nonaffiliated companies and marketers from generation facilities operated by the Distribution Companies. Revenues from those sales of generation from the Distribution Companies were approximately $47.1 million.

The Distribution Companies transmitted approximately 10.6 billion kWh to others located outside their service territories under various forms of transmission service agreements. Revenues from those sales were about $53.6 million.

Regulated Gas Sales
	2001	2000	Increase/ (Decrease)
Regulated Gas Customers-Bcf Sales
Residential	18.8	9.1	106.6%
Commercial	12.3	5.1	141.2%
Industrial	.7	.2	250.0%
Wholesale	.8	.2	300.0%
Transportation and other	31.3	10.9	187.2%
Total Regulated Customers-Bcf Sales	63.9	25.5	150.6%

Regulated Revenue (Millions)
Residential	$139.1	$67.4	106.4%
Commercial	79.8	32.7	144.0%
Industrial	4.1	.9	355.6%
Wholesale	4.1	1.6	156.3%
Transportation and other	8.0	1.0	700.0%
Total Regulated Revenue	$235.1	$103.6	126.9%

In 2001, a total of approximately 63.9 Bcf of gas was delivered to retail and wholesale natural gas customers served by West Virginia Power (approximately 3.0 Bcf) and Mountaineer Gas (approximately 60.9 Bcf). Of this total, approximately 32.6 Bcf consisted of regulated tariff sales volumes (3.0 Bcf of West Virginia Power and 29.6 Bcf of Mountaineer Gas), with the balance consisting of transportation volumes (approximately 31.3 Bcf, all of which was transported by Mountaineer Gas). Consolidated regulated gas revenues totaled $235.1 million for 2001, of which $227.1 million represented regulated revenues from tariff sales and $8.0 million represented revenues from regulated transportation services.

Unregulated Sales
	2001	2000**	Increase / (Decrease)
Kilowatt-hour Sales*
Unregulated Generation	114,507	41,707	174.6%
Total Kilowatt-hour Sales	114,507	41,707	174.6%

Unregulated Revenue (Millions)*
Unregulated Generation	$7,486.2	$1,482.3	405.0%
Other	139.6	22.6	517.7%
Total Revenue	$7,625.8	$1,504.9	406.7%
Unregulated generation sales include amounts for recording AE Supply's energy trading contracts at their fair value as of the balance sheet date. *Certain amounts have been reclassified for comparative purposes. Unregulated sales revenues were $7,625.8 million, which represented 73.5% of AE's total operating revenues in 2001.

Regulatory Framework Affecting Electric Power Sales

The national Energy Policy Act of 1992 (EPACT) initiated the restructuring of the electric utility industry by permitting competition in the wholesale generation market. In order to facilitate the efficient use of generation facilities, on April 24, 1996, the FERC issued Orders 888 and 889. Subsequent Orders 888A&B and 889A&B reaffirmed and clarified the legal and policy determinations originally adopted in Orders 888 and 889, and provided explanations and minor revisions to specific sections of the orders.

The FERC orders require all transmission providers to offer service to entities selling generation services in a manner that is comparable to their own use of the transmission system. The orders required each transmission provider to file standardized open access transmission service tariffs; therefore, the Distribution Companies have on file a pro forma open access tariff under which they sell transmission services to all eligible customers. Monongahela and AE Supply also arrange for transmission services for their own sales pursuant to the rates, terms, and conditions of the open access tariff.

To meet the objective of providing comparable or nondiscriminatory transmission services, the FERC orders further require that utilities functionally unbundle transmission operations and reliability functions from wholesale merchant functions within the utility. The Distribution Companies conduct their business in a manner that is consistent with FERC's Standards of Conduct.

The FERC established its jurisdiction over unbundled retail, as well as wholesale transmission services, in Order 888. Although states retain the authority to determine if retail wheeling should be adopted, retail transmission service under the jurisdiction of the FERC is available once these historically franchised customers have access to alternate generation sources. As the states in their service territory enacted retail choice, the Distribution Companies revised their Open Access Tariff to authorize sale of open access transmission services to unbundled retail customers.

The Distribution Companies also have on file with the FERC a Standard Generation Service Rate Schedule for the sale of wholesale power at cost-based rates. The Distribution Companies are also authorized to sell power at market-based rates and began selling power at market-based rates upon acceptance of the filing by the FERC in August 1998. Separately, a market-based rate tariff for AE Supply was filed and became effective August 15, 1999. AE Supply began serving customers under that tariff on November 19, 1999.

AE Supply also manages its generating assets and the electric generation owned by Monongahela as an integral part of its wholesale marketing, energy trading, fuel procurement and risk management activities. AE Supply, as part of its generating asset and energy commodity portfolio, interfaces the electric generating capacity represented by AE Supply's generating assets and the electric generation operation owned by Monongahela, and various customers or markets. In early 2000, an arrangement was put in place between Monongahela and AE Supply to create this interface. Under this arrangement, Monongahela sells the amount of its real time, available bulk power generation that exceeds its regulated load to AE Supply and conversely Monongahela buys generation from AE Supply when regulated load at times exceeds that amount of real time, available bulk power generation. Monongahela (for its Ohio service territory), Potomac Edison and West Penn also purchase generation from AE Supply under long-term power sales agreements to meet their default service obligations. These transactions take place under the terms of tariffs filed with the FERC.

On December 20, 1999, the FERC issued Order No. 2000, which requires each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce to make certain filings with respect to forming and participating in a regional transmission organization (RTO). FERC stated in that order that transmission owners are expected to join RTOs on a voluntary basis and that RTOs will be operational by December 15, 2001. The Distribution Companies and other transmission-owning entities were required to file with the FERC their plans for joining an RTO by October 16, 2000. On October 5, 2000, the Distribution Companies and PJM Interconnection, LLC (PJM) announced that they had signed a Memorandum of Agreement to develop a new affiliation - PJM West. The affiliation was outlined in a compliance filing submitted to FERC on October 16, 2000.

On March 15, 2001, the Distribution Companies and PJM filed documents with the FERC to expand the PJM transmission system and energy market through the creation of PJM West. The filing represents a collaboration between the Distribution Companies, PJM, and numerous stakeholders. The Distribution Companies and PJM have asked FERC to confirm that PJM West satisfies FERC's requirements for an RTO as set forth in Order No. 2000. The Distribution Companies also asked FERC to accept certain transmission rate surcharges so that the Distribution Companies will not suffer a loss in revenues when PJM West becomes operational, and to recover certain PJM West start-up costs.

Under the PJM West proposal, the Distribution Companies will transfer operational control over its transmission system to PJM. The Distribution Companies will adopt PJM's transmission pricing methodology, including PJM's congestion management system. In addition, PJM will expand its day-ahead and real-time energy markets to include PJM West. As a result, energy suppliers will be able to reach consumers anywhere within the expanded PJM/PJM West market at a single transmission rate, instead of paying multiple transmission rates as they do today.

On January 30, 2002, the FERC authorized the Distribution Companies and PJM to proceed with PJM West effective March 1, 2002. In doing so, however, the FERC stated that it will make a final determination of whether to approve PJM/PJM West as an RTO in a later order. The FERC also set for hearing on July 22, 2002, the reasonableness of the Distribution Companies' proposed transmission rate surcharges. The Distribution Companies have estimated that without these surcharges, they will lose approximately $28.3

million a year over the next three years due to lost transmission revenues and incremental PJM West start-up costs.

In light of the FERC's order, the Distribution Companies asked the FERC to delay the effective date of PJM West pending clarification on the scope of issues set for hearing. By order dated March 1, 2002, the FERC provided the requested clarification of the issues set for hearing, and authorized the Distribution Companies to go forward with PJM West when it is practical to do so. The Distribution Companies anticipate going forward with PJM West on April 1, 2002. The transmission surcharges will go into effect, subject to potential refund, pending the final outcome of the hearing process.

The Distribution Companies are unable to predict the financial impact of changes to FERC's RTO policies.

Under PURPA, certain municipalities, businesses and private developers have installed generating facilities at various locations in or near the Distribution Companies' service areas, and sell electric capacity and energy to the Distribution Companies at rates consistent with PURPA and ordered by appropriate state commissions. The Distribution Companies are committed to purchasing 479 MW of on-line PURPA capacity. Payments for PURPA capacity and energy in 2001 totaled approximately $202 million, before amortization of West Penn's adverse power purchase commitment, resulting in an average cost to the Distribution Companies of 5.4 cents/kWh.

ELECTRIC FACILITIES

The following table shows Allegheny's operational generating capacity as of December 31, 2001, based on the maximum operating capacity of each unit. Monongahela's owned capacity totaled 2,115 MW, of which 1,894 MW (89.6%) are coal-fired and 221 MW (10.4%) 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, using the most economic available electricity, 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 or contracted capacity as of December 31, 2001, totaled 9,895 MW (including 1,000 MW of gas-fired contractual capacity) of which 5,973 MW (60.4%) are coal-fired, 154 MW (1.6%) are oil-fired, 739 MW (7.5%) are pumped-storage, 2,974 MW (30.0%) are gas-fired, and 55 MW (.5%) are hydroelectric. See Item 1. BUSINESS Allegheny's Competitive Actions for a description of generating assets and generating capacity that AE Supply acquired in 2001.

ALLEGHENY STATIONS
Maximum Generating Capacity (Megawatts) (a)

Regulated
Unregulated

Station
Monongahela
Hunlock
Creek
Energy
Ventures
Green Valley Hydro
AE Supply
Service
Commencement
Dates (b)
Station
Units
Total

Coal-Fired (Steam):

Albright

292

184

108

1952-4

Armstrong

356

1958-9

Conemaugh

83 (c)

2001

Fort Martin

1,107

212

895

1967-8

Harrison

1,950

415

1,535

1972-4

Hatfield's Ferry

1,710

400

1,310

1969-71

Hunlock (d)

24 (d)

2000

Mitchell

288

1963 (h)

Ohio Valley Electric Corp.

280

78 (e)

202 (e)

Pleasants

1,300

277

1,023

1979-80

Rivesville

142

121

1943-51

R. Paul Smith

116

1947-58

Willow Island

243

207

1949-60

Gas-Fired

AE Nos. 1 & 2

1999

AE Nos. 8 & 9

2000

AE Nos. 12 & 13

2001

Gleason

546

2001

Hunlock CT (d)

22 (d)

2000

Lincoln

656

2001

Wheatland

508

2001

Oil-Fired Steam

Mitchell

154

1948-49

Pumped-Storage and Hydro

Bath County (f)

960 (f)

221 (f)

739 (f)

1985; 2001

Lake Lynn (g)

1926

Potomac Edison

Various

Total Allegheny-Owned Capacity

11,059

2,115

8,895

PURPA GENERATION

Maximum Generating Capacity (Megawatts) (i)

Project
Total
Monongahela
Potomac
Edison
West Penn
Hunlock
Creek
Energy
Ventures
Green Valley Hydro
AE Supply
Service
Commencement
Dates (b)
Project

Coal-Fired: Steam

AES Beaver Valley

125

1987

Grant Town

1993

West Virginia University

1992

AES Warrior Run

180

180 (j)

2000

Hydro:

Allegheny Lock and Dam 5

1988

Allegheny Lock and Dam 6

1989

Hannibal Lock and Dam

1988

Total Other Capacity

479

161

180

138

Total Allegheny-owned and PURPA Committed Generating Capacity (a)

11,538

2,276

180

138

46

3

8,895

(a) Accredited capacity.

(b) Where 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. The Hunlock coal unit date refers to the year in which part ownership was acquired by AE.

(c) This figure represents capacity entitlement through ownership of Allegheny Energy Supply Conemaugh, LLC, which owns a 4.86% interest in the Conemaugh Generating Station.

(d) This figure represents Allegheny Energy Supply Hunlock Creek's capacity entitlement through its 50% ownership in Hunlock Creek Energy Ventures. Allegheny Energy Supply Hunlock Creek's access to output at maximum generating capacity is indicated on the table for the steam and gas-fired facilities. Allegheny Energy Supply Hunlock Creek's output is sold exclusively to AE Supply. AE expects to contribute its ownership interest in Allegheny Energy Supply Hunlock Creek to AE Supply in 2002.

(e) This figure represents capacity entitlement through AE's ownership of OVEC shares.

(f) This figure represents capacity entitlement through ownership of AGC, 22.97% by Monongahela and 77.03% by AE Supply. During 2001, the instantaneous generating capacity at the Bath County facility was increased by 120 MW, from 840 MW to 960 MW.

(g) 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 will expire in 2003. Potomac Edison has received 30-year licenses, effective January 1994, for the Shenandoah, Warren, Luray and Newport projects. The FERC accepted Potomac Edison's surrender of the license for the Harper's Ferry Dam No. 3 and issued an order effective October 1994.

(h) On December 31, 1994, 82 MW, and on July 1, 1998, 50 MW of the total MW at Mitchell Power Station were reactivated.

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

(j) The 180-MW AES Warrior Run project commenced commercial operation on February 10, 2000. Potomac Edison, as required under the terms of a Maryland Restructuring Settlement, began to offer the 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.

AE SUPPLY MAP

42 The following table sets forth the existing miles of tower and pole transmission and distribution lines and the number of substations of the Distribution Companies and AGC as of December 31, 2001:
Miles of Above-Ground Transmission and Distribution Lines (a) and Number of Substations
	Total Miles	Portion of Total Miles Representing 500-Kilovolt (kV) Lines	Number of Transmission and Distribution Substations
Monongahela	22,493	283	318
Potomac Edison	17,743	202	285
West Penn	23,804	273	697
AGC (b)	85	85	1
Total	64,125	843	1,301

(a) The Distribution Companies also have a total of 6,444 miles of underground distribution lines.

(b) Total Bath County transmission lines, of which AGC owns an undivided 40% interest and Virginia Power 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 interregional EHV transmission system, which includes the Distribution Companies' network, continued in 2001 to operate near reliability limits during periods of heavy power flows that in the past have had a predominantly west-to-east orientation. In early 1997, North American Electric Reliability Council undertook the development of a national transmission security process. A representative from the Distribution Companies serves as one of 22 regional Security Coordinators. This security process includes a Transmission Loading Relief (TLR) procedure that identifies actual flow path consequences of all power transactions, and can be used to reduce loading on congested facilities. The new security process has provided a better exchange of operation planning information and has allowed more accurate evaluation of the transmission system. The TLR procedure has addressed congestion caused by parallel path flows, resulting in fewer congestion events on the Distribution Companies' transmission facilities.

As previously discussed, wholesale generators and other wholesale customers may seek from owners of bulk power transmission facilities a commitment to supply transmission services. (See discussion under ITEM 1. SALES. Regulatory Framework Affecting Power Sales.) Such demand on the Distribution Companies' transmission facilities may add to heavy power flows on the Distribution Companies' facilities and may eventually require construction of additional transmission facilities.

The Distribution Companies have, since the early 1980s, provided managed contractual access to their transmission facilities under various tariffs. For new agreements starting in 1996, the provisions of the Distribution Companies' Open Access Transmission Tariff mandated by and filed with the FERC also govern managed access.

RESEARCH AND DEVELOPMENT

The Distribution Companies and AE Supply collectively spent $7.1 million and $6.4 million, in 2001 and 2000, respectively, for research programs. Of these amounts, $4.5 million and $4.8 million were for Electric Power Research Institute (EPRI) dues in 2001 and 2000, respectively. EPRI is an industry-sponsored research and development institution. The Distribution Companies and AE Supply plan to spend approximately $8.6 million for research in 2002 with EPRI dues representing $5.1 million of that total. In addition to EPRI support, in-house research conducted by Allegheny concentrates on technology-based issues that are important developments for each of Allegheny's lines of business. These technology drivers include products and services for environmental control, generating unit performance, alternative fuels, sustainable and clean coal technology developments, combustion turbine training, environmental effects and performance issues, future generation technologies, use of coal combustion products, transmission system performance, customer-related research, 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 help address major issues for Allegheny and the entire electric industry. These include electric and magnetic field assessment of employee exposure within the work environment, global warming from greenhouse gas emissions, waste disposal and discharges to land, water and air resources, renewable resources, fuel cells, new combustion turbines, cogeneration technologies, transmission loading mitigation using Flexible AC Transmission System (FACTS) devices and new product development venture opportunities. The use of biomass for co-firing and gasification are being developed with two Allegheny stations directly firing sawdust. The use of biomass lowers production cost, and results in lower emissions of nitrogen oxides, sulfur oxides, particulate matter and carbon dioxide. It also reduces operation, maintenance and compliance costs. A new communication technology, patented by employees of AESC and employees of Shenandoah Electronics Intelligence, Inc., is expected to be purchased and marketed. This technology is designed to read meters and provide control to customer premises using distribution feeder lines and using digital and power electronic technology. The baud rate is low but very acceptable for metering and control services. Three AESC employees applied for and received patents in 2001 from the US Patent and Trademark Office for wastewater handling and plant optimization technology.

CAPITAL REQUIREMENTS AND FINANCING

Construction Expenditures

AE Supply, including AGC

Construction expenditures of AE Supply , including AGC, were $214.0 million and $177.1 million for 2001 and 2000, respectively. Total capital expenditures in 2001 were $1,769.5 million, including $214.0 million of construction expenditures and $6.9 million of unregulated investments, for all generating assets operated or to be acquired by AE Supply (excluding generating assets currently owned by Monongahela), $495.6 million, including direct acquisition costs, for acquisition of the energy marketing and trading business of Merrill Lynch, and $1,053.0 million for the purchase of the three Midwest generating stations. In 2001, AE Supply's capital expenditures included $133.8 for environmental control technology. Capital expenditures for 2002 and 2003 are estimated at $384.2 million and $435.7 million, respectively. The

2002 and 2003 estimated expenditures include $174.0 million and $159.1 million, respectively, for environmental control technology. Outages for construction, Clean Air Act Amendments of 1990 (CAAA) compliance and other environmental work are, and will continue to be, coordinated with other planned outages, where possible. Future construction expenditures will reflect additions of generating capacity to sell into deregulated markets. AE Supply could potentially face significant mandated increases in capital expenditures and operating costs related to environmental issues. AE Supply also has additional capital requirements for debt maturities.

Included in the above figures are AGC's construction expenditures, which in 2001 amounted to $2.2 million, and which are expected to be $3.4 million and $9.2 million in 2002 and 2003, respectively.

Distribution Companies

Construction expenditures by the Distribution Companies, including Mountaineer, in 2001 amounted to $230.8 million. Construction expenditures for 2002 and 2003 are expected to aggregate $214.3 million and $200.3 million, respectively. In 2001, the Distribution Companies capital expenditures included $35.4 for environmental control technology. The 2002 and 2003 estimated regulated expenditures include $45.5 million and $32.6 million, respectively, for environmental control technology. Expenditures to cover the costs of compliance with the CAAA and other environmental requirements have been and are likely to continue to be significant. Additionally, new environmental initiatives may substantially increase regulated construction requirements as early as 2002.

Regulated generation-related expenditures by Monongahela for 2001, 2002 and 2003 include $35.4 million, $45.5 million and $32.6 million, respectively, for construction of environmental control technology. Outages for construction, CAAA compliance and other environmental work is, and will continue to be, coordinated with other planned outages, where possible.

Allegheny continues to study ways to reduce and meet existing regulated customer generation service demand and future increases in that demand, including new and efficient electric technologies; construction of various types and sizes of generating units that may be dedicated to regulated service (if any); increasing the efficiency and availability of Allegheny's regulated service generating facilities (if any); reducing internal electrical use and transmission and distribution losses; and acquisition of energy and capacity from third-party suppliers whenever market prices are favorable versus native production or demand exceeds native production capability. The advent of retail choice of generation service supplier has introduced the potential for significant volatility within Allegheny's regulated generation service load growth profile. Since customers with choice can be expected to attempt to arbitrage any differentials between generation market prices and those set by regulators, the Distribution Companies' obligation to meet such load growth will increasingly become an exercise in trying to predict both the variable of general economic conditions in their service territories, as well as relative competitiveness of their regulated generation service pricing, versus the inherently more flexible pricing of unregulated generation suppliers. Monongahela, Potomac Edison and West Penn have contracts with AE Supply to supply them with generation service during the Ohio, Pennsylvania, Maryland and Virginia transition periods. Under these contracts, AE Supply provides these regulated electricity distribution affiliates with full requirements generation service for their retail load obligations, and, in certain instances, their wholesale load obligations. These contracts represent a significant portion of the normal operating capacity of AE Supply's generating assets that were previously owned by Monongahela, West Penn and Potomac Edison.

Current forecasts, which assume normal weather conditions, project winter and summer peaks within the Distribution Companies' control area to grow at an average rate of 0.9% and 1.0% per year,

respectively, during the period 2001-2011. However, default service peak loads, which are the Distribution Companies' control area loads reduced to account for customers who choose alternate generation suppliers, are presently expected to decline at an annual rate of -0.3% and -0.6%, respectively. The level of competition actually realized for existing loads from the aforementioned unregulated suppliers could obviously have a substantial effect on those default service projections and the degree to which they fail to track with the control area load. It is anticipated that Allegheny's existing resources that are still state-regulated, and existing or purchased power of various types, will be sufficient to serve the Distribution Companies' default service loads over the next few years.

Construction of new T&D assets is expected to continue at its historic rate, with no major divergent expenditures planned. Additionally, while meeting FERC and certain state regulatory requirements to join a Regional Transmission Organization does reassign the responsibility for planning major transmission systems from the incumbent transmission owner to a new independent authority, the Distribution Companies do not expect their affiliation with and formation of PJM West to result in near-term system expansion. Finally, retail choice will not greatly affect the projected need for new T&D plants since provision of delivery service remains within the authority of each Distribution Company.

In connection with its construction programs, Allegheny must make estimates of the availability and cost of capital as well as the future demands of its customers that are necessarily subject to regional, national and international developments, changing business conditions and other factors. The construction of facilities and their cost are affected by laws and regulations; lead times in manufacturing; availability of labor, materials and supplies; inflation; interest rates; and licensing, rate, environmental and other proceedings before regulatory authorities. Decisions regarding construction of facilities must now also take into account retail competition. As a result, future plans of Allegheny are subject to continuing review and substantial change.

Allegheny Ventures

Construction expenditures by Allegheny Ventures in 2001 amounted to $17.6 million and for 2002 and 2003 are expected to be $38.0 million, and $24.0 million, respectively.

Construction Expenditures
	2001	2002	2003
	Millions of Dollars
	(Actual)	(Estimated)
Monongahela
Generation	$44.1	$ 52.6	$ 42.4
Transmission & Distribution	60.8	52.5	48.3
Total*	$104.9	$105.1	$ 90.7

Potomac Edison
Generation	$ 0.0	$ 0.0	$ 0.0
Transmission & Distribution	54.8	50.8	64.9
Total*	$54.8	$ 50.8	$ 64.9

West Penn
Generation	$ 0.0	$ 0.0	$ 0.0
Transmission & Distribution	71.1	54.1	40.9
Total*	$ 71.1	$ 54.1	$ 40.9

AESC	$ 0.0	$ 4.3	$ 3.8

Total Construction Expenditures,
Regulated	$230.8	$214.3	$200.3

AE Supply*	$211.8	$380.8	$426.5

AGC	$ 2.2	$ 3.4	$ 9.2

Allegheny Ventures	$17.6	$ 38.0	$ 24.0

Other*	$ 1.7	$ 0.0	$ 0.0

Total Construction Expenditures
Unregulated	$233.3	$422.2	$459.7

Total Construction Expenditures	$464.1	$636.5	$660.0

*
Includes allowance for funds used during construction (AFUDC) 2001, 2002 and 2003 of: Monongahela $.5, $0.1 and $1.1; Potomac Edison $(0.1), $0.6 and $0.7; and West Penn $.0.5, $0.1 and $0.0.

These construction expenditures include projects at generating stations, upgrading distribution lines and substations and the strengthening of the transmission and subtransmission systems.

Financing Programs

AE Supply

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

During 2001, AE Supply issued $776.6 million of long-term debt and $520.1 million of short-term debt, and issued notes payable to AE and affiliates of $334.6 million, primarily to finance its acquisitions of Merrill Lynch's energy trading business and the Midwest Assets. AE Supply anticipates further financings and member contributions from AE to support future acquisitions and capital expenditures while maintaining working capital. In addition, AE Supply's risk management, wholesale marketing, fuel procurement, and energy trading activities require trade credit support commitments. As of December 31, 2001, AE Supply had total indebtedness of $2.42 billion.

Members' Equity
. On March 16, 2001, AE Supply acquired Merrill Lynch's energy trading business. AE Supply acquired this business for $489.2 million in cash plus the issuance of a 1.967% equity membership interest in AE Supply. By order dated May 30, 2001, the SEC authorized the issuance of an equity membership interest in AE Supply to Merrill Lynch. Effective June 29, 2001, the transaction was completed, and Merrill Lynch now has a 1.967% equity membership. Members' equity includes capital contributions related to West Penn, Potomac Edison, AYP Energy, Inc. and Monongahela generating asset transfers as described in Note C to AE Supply's consolidated financial statements. Members' equity also includes capital contributions from AE of $272.5 million and $26.9 million in 2001 and 2000, respectively. The return of members' capital contribution for 2000 relates primarily to a note receivable assigned to AE.

Long-term Debt
AE Supply's long-term debt increased by $785.7 million to $1.3 billion on December 31, 2001. AE Supply issued the following long-term debt during 2001:

- in November 2001, AE Supply borrowed $380 million at 8.13% under a loan due to mature on November 15, 2007, as described below under "Operating Lease Transactions", and

- in March 2001, AE Supply issued $400 million of unsecured 7.8% notes due 2011.

In June 2001, Monongahela transferred generating assets to AE Supply. As part of that transfer, AE Supply assumed long-term debt of $15.9 million. Monongahela continues to be a co-obligor with respect to the transferred debt.

In 2001, AE Supply made repayments on long-term debt of $7.2 million. See Note L to AE Supply's consolidated financial statements for additional details regarding long-term debt issued and redeemed during 2001 and 2000.

The long-term debt due within one year at December 31, 2001, of $219.1 million represents $3.5 million of unsecured notes and $215.6 million of medium-term debt. Of the $215.6 million medium-term

debt due within one year, $135.6 million related to AE Supply's loan with a nonaffiliated special purpose entity as part of the St. Joseph lease transaction. The classification of this debt as due within one year is based upon project cost funding requirements, which are subject to change, as discussed under "- Operating Lease Transactions" below.

Short-term Debt
Short-term debt and notes payable to AE and affiliates increased by $854.7 million during 2001. As of December 31, 2001, short-term debt and notes payable to AE and affiliates consisted of commercial paper borrowings of $74.3 million, lines of credit of $61.6 million, a $550 million bridge loan used to purchase the Midwest Assets on May 3, 2001, and notes payable to AE and affiliates of $387.8 million at rates comparable to short-term rates. AE Supply intends to refinance a portion of these obligations with long-term financing during 2002.

At December 31, 2001, AE Supply had used $61.6 million of its lines of credit.

Operating Lease Transactions
. In November 2001, AE Supply entered into an operating lease transaction, known as the St. Joseph lease transaction, in connection with a 630-MW intermediate-load and peaking natural gas-fired facility located in St. Joseph County, Indiana. The St. Joseph lease transaction was structured to finance the construction of both the peaking and intermediate facility with a maximum commitment amount of $460 million. AE Supply will lease the plant from a nonaffiliated special purpose entity when the construction has been completed.

Lease payments, to be recorded as rent expense, are estimated at $2.8 million per month, commencing on final completion of the entire facility in 2005 and continuing through November 2007. If AE Supply is unable to renew the lease in November 2007, AE Supply must either purchase the facility for the lessor's investment, or terminate the lease, abandon, and release its interest in the facility, or sell the facility and pay the amount, if any, by which the lessor's investment exceeds the sale proceeds, up to a maximum recourse amount of approximately $392 million. Based on costs incurred on the project through December 31, 2001, AE Supply's maximum recourse obligation was $22.2 million, reflecting a lessor investment of $29.2 million.

In April 2001, AE Supply entered into an operating equipment lease transaction structured to finance the purchase of turbines and transformers with a maximum commitment amount of $150 million. The St. Joseph lease transaction included a transfer between lessors of some of the equipment previously financed in this lease. As a result, the commitment in the equipment lease has been reduced to approximately $42 million. The remainder of the equipment financed in the lease will be used for another project. During 2002, AE Supply plans to purchase this equipment for the amount of the lessor's investment, which was $29.6 million on December 31, 2001.

Included in the St. Joseph lease transaction is a loan to AE Supply of $380 million from the nonaffiliated special purpose entity. AE Supply is required to repay the loan during the construction period of the leased facility based on project cost funding requirements. Loan repayments were $7.2 million in 2001 and are estimated to be $135.6 million in 2002, $175.9 million in 2003, and $61.3 million in 2004. On the closing date of the St. Joseph lease transaction, AE Supply repaid approximately $4.0 million of the loan and used approximately $376.0 million of the net proceeds to refinance existing short-term debt. At December 31, 2001, AE Supply recorded $135.6 million and $237.2 million as short-term and long-term debt, respectively, based on the project cost funding requirements, which are subject to change. The loan is required to be repaid if the lease balance or maximum recourse amount becomes payable under the lease.

In November 2000, AE Supply entered into an operating lease transaction relating to the construction of a 540-MW combined-cycle generating facility located in Springdale, Pennsylvania. This transaction was structured to finance the construction of the facility with a maximum commitment amount of $318.4 million. Upon completion of the facility, a special purpose entity will lease the facility to AE Supply. Lease payments, to be recorded as rent expense, are estimated at $1.9 million per month, commencing during the second half of 2003 through November 2005. Subsequently, AE Supply has the right to negotiate a renewal of the lease. If AE Supply is unable to renew the lease in November 2005, it must either purchase the facility for the lessor's investment, or sell the facility and pay the difference between the proceeds and the lessor's investment up to a maximum recourse amount of approximately $275 million. Based on costs incurred on the project through December 31, 2001, AE Supply's maximum recourse obligation was approximately $120 million, reflecting a lessor investment of $133.7 million.

These operating lease transactions contain covenants, including maximum debt-to-capitalization ratios, which require compliance in order to avoid defaults and acceleration of payments. An event of default could require AE Supply to pay 100% of the lessor's investment.

The lease transactions for the St. Joseph and Springdale facilities are classified as operating leases, which are off balance sheet, as of December 31, 2001, in accordance with generally accepted accounting principles. However, a change in the accounting standards applicable to leases could result in the consolidation of the related special purpose entities, with debt issued by the special purpose entities included in AE Supply's long-term debt. As of December 31, 2001, the effect of consolidating these special purpose entities would be to increase AE Supply's debt by $167.3 million.

Credit. AE Supply has established a letter of credit facility for $410 million to provide for the issuance of letters of credit to support its energy trading activities and for general corporate purposes. Letters of credit are purchased guarantees that ensure AE Supply's performance or payment to third parties, in accordance with certain terms and conditions. In particular, AE Supply regularly posts cash deposits or letters of credit to collateralize a portion of its energy trading activities. This facility also requires the maintenance of a certain fixed-charge coverage ratio and a maximum debt to capitalization ratio, as well as the maintenance of an investment grade credit rating. At December 31, 2001, there was $207.7 million outstanding under the banks' letters of credit.

Allegheny Ventures

In June 2001, AFN Finance Company No. 2, LLC, a subsidiary of ACC, borrowed $10.5 million under a variable rate credit facility guaranteed by AE, with a maturity date of June 30, 2006.

Distribution Companies

In September 2001, Monongahela redeemed $40 million, of its 8% Quarterly Income Debt Securities (QUIDS^SM) (Junior Subordinated Deferrable Debentures Series A) due June 30, 2025, at a redemption price of 100% of their principal amount plus accrued interest to the date of redemption.

In October 2001, Monongahela issued $300 million, 5% Series Due 2006 of its First Mortgage Bonds under an Indenture with Citibank, N.A., dated August 1, 1945.

In October 2001, Monongahela paid off a credit facility maturing on October 18, 2001 in the principal amount of $100 million plus accrued interest.

In November 2001, Monongahela redeemed $50 million of its 8-5/8% Series Due 2021 First Mortgage Bonds at their optional redemption price of 104.19% of their principal amount plus accrued interest to the date of redemption.

In November 2001, Potomac Edison issued $100 million of Unsecured Medium-Term Notes at 5%, due 2006.

In December 2001, Potomac Edison redeemed $50 million of its 8% Series Due 2006 First Mortgage Bonds at their optional redemption price of 100% of their principal amount plus accrued interest to the date of redemption.

In December 2001, Potomac Edison redeemed $45.5 million of its 8% Quarterly Income Debt Securities (QUIDS^SM) (Junior Subordinated Deferrable Debentures Series A) due September 30, 2025, at a redemption price of 100% of their principal amount plus accrued interest to the date of redemption.

In May 2001, AE issued and sold 14,260,000 shares of its Common Stock at $48.25 per share.

On December 31, 2001, Allegheny had short-term debt of $1,238.7 million outstanding. The borrowing positions of the individual companies were: AE $514.3 million, Monongahela $14.3 million, Potomac Edison $24.2 million, and AE Supply $685.9 million.

AE's consolidated capitalization ratios as of December 31, 2001 were: common equity, 45.3%; preferred stock, 1.2%; and long-term debt, 53.5%, including 2.2% of Quarterly Income Debt Securities.

On December 31, 2001, the SEC approved Allegheny's June 12, 2001 financing application filed under PUHCA, granting, among other things, authorization through July 31, 2005 for AE to issue up to $1 billion in equity securities; AE and/or AE Supply to issue short-term debt and long-term debt in an aggregate amount up to $4 billion for the purpose of investing in exempt wholesale generators, foreign utility companies, companies engaged in activities permitted by Rule 58, for general corporate purposes, and for other permitted activities; and for AE and AE Supply to issue up to $3 billion of guarantees.

     On March 28, 2002, Moody's Investors Service notified AE that it downgraded to Baa2 from Baa1 the senior unsecured debt ratings of AE and two of its subsidiaries, AE Supply and AGC, ending a review process that began February 27, 2002. None of the ratings of the Distribution Companies were on review. The commercial paper ratings of P-2 for AE and AE Supply were confirmed.

FUEL SUPPLY

Electric Generation

     In 2001, generating stations owned by AE Supply and Monongahela burned approximately 18.4 million tons of local mid to high sulfur coal. Of that amount, 49% was used in stations equipped with scrubbers (9.1 million tons). The use of desulfurization equipment and the cleaning and blending of coal make burning local coal practical. In 2001, almost 100% of the coal received at these stations came from mines in West Virginia, Pennsylvania, Maryland 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 2001, AE Supply and Monongahela had long-term arrangements (i.e., terms of 12 months or longer) in place to purchase approximately 17.9 million tons of coal. AE Supply purchases coal from a limited number of suppliers. In 2001, AE Supply and Monongahela purchased approximately 12 million tons of coal (60% of fuel 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 19 million tons of coal in 2002. Monongahela and AE Supply will depend on short-term arrangements and spot purchases for their remaining requirements.

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     For each of the years 1997 through 2000, the average cost per ton of coal burned was $32.66, $32.26, $30.18 and $26.73, respectively. For the year 2001, the cost per ton was $30.32.

     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 economic conditions now prevailing in the coal market, the Distribution Companies plan to hold the reserves as a long-term resource.

     The addition of natural gas-fired generation, both through acquisitions and construction, will diversify AE Supply's fuel mix from the current predominantly coal-fired generation facilities. This change in fuel mix and diversification is expected to assist AE Supply in reducing business risks.

     Long-term arrangements, subject to price change, are in effect and will provide for the lime requirements of scrubbers at Allegheny's scrubbed stations.

Distribution Gas Supply

     On September 30, 1998, Mountaineer entered into a Natural Gas Supply Management Agreement (Coral Agreement) with Coral Energy Resources, L.P. (Coral) an affiliate of Shell Oil Company, pursuant to which Coral became the principal gas supplier for Mountaineer for a three-year period commencing as of November 1, 1998. The term of the Coral Agreement coincided with the three-year West Virginia Rate Moratorium. The Rate Moratorium froze Mountaineer's resale rates (fuel and base) until October 31, 2001. Mountaineer was subsequently granted authority to increase its rates beginning November 1, 2001. For additional information, see "Rate Matters" below.

     The Coral Agreement provided that Coral would be responsible for supplying in excess of 90% of Mountaineer's total annual gas requirements for the three-year term which ended November 1, 2001. The balance of Mountaineer's gas supply requirements during the term of the Coral Agreement were purchased from local producers, including MGS-owned/operated production, adding up to approximately 2.7 Bcf/year. Coral supplied the gas at a fixed price per decatherm (Dth) at the city gate up to approximately 24.4 Bcf annually. Currently, Mountaineer fulfills its gas requirements via purchases from various producers located in Appalachia and the Gulf of Mexico.

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     The following table indicates the volume of natural gas purchased and percentage of total volume of natural gas purchased, with respect to Mountaineer's largest suppliers for the twelve months ended December 31, 2001:

Twelve Months Ended December 31, 2001

Volume
(Mmcf)

% of
Total

MGS-Owned/Controlled Production

1,610

5.38%

Coral Energy Resources, L.P.

24,470

81.72%

Other Gulf Coast Producing Region Producers/Suppliers

3,228

10.77%

Other Appalachian Basin Producers/Suppliers

637

2.13%

     The West Virginia PSC regulates MGS sales to Mountaineer, which accounts for the majority of MGS sales. The contract term is November 1, 2001 through October 31, 2002. The price for these sales is calculated by adding (1) the "Inside FERC's Gas Market Report" Columbia Gas-Appalachia Index (Index) and (2) the Columbia Gas FTS commodity rate (approximately 2.00-2.50 cents per Dth), and a fuel factor that is approximately 2.50-2.75% of the Index that is paid in kind. MGS production makes up in excess of 80% of the total local production purchased by Mountaineer.

     In December 1999, Monongahela purchased the assets of West Virginia Power from UtiliCorp United Inc. The following table sets forth the volume of Monongahela/UtiliCorp United's natural gas purchases and percentage of total volume of natural gas purchased, excluding Mountaineer's own purchases and production, for the twelve months ended December 31, 2001, and December 31, 2000:

Twelve Months Ended
12/31/2001

Twelve Months Ended
12/31/2000

Volume
(Mmcf)

% of
Total

Volume
(Mmcf)

% of
Total

WV Production Contracts

1,509

49.41%

1,635

50.42%

Cabot Oil and Gas Marketing

685

22.43%

1,225

37.77%

Other Supply Volumes

860

28.16%

383

11.81%

          Annual Totals

3,054

100.00%

3,243

100.00%

GAS TRANSPORTATION AND STORAGE CAPACITY

     Gas purchased from producer/suppliers in the Gulf Coast producing basin/region is transported through the interstate pipeline systems of Columbia Gulf Transmission Company (Columbia Gulf) and Columbia Gas Transmission Corporation (Columbia Gas) to Mountaineer's and West Virginia Power'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-
53
notice service and storage with such contracts expiring on October 31, 2004. Under both MGC's and West Virginia Power's Purchased Gas Adjustment (PGA), these costs, if prudently incurred, are recovered from the respective companies' customers.

     Typically, the gas industry uses gas sales and/or transportation contracts for load management purposes. Under such contracts, the users purchase and/or transport gas with the understanding that they may be forced to shut down or switch to alternate sources of energy at times when the gas is needed for higher priority customers or interruptible transportation on the transporting pipeline is curtailed. In addition, during times of extraordinary supply problems, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal and state regulatory agencies.

     Since July 1999, Mountaineer has served a number of interruptible sales customers some of whom are capable of utilizing alternate fuels as an energy source at their respective business facilities. In 2001, Mountaineer did not have to interrupt these customers because of supply or transportation capacity scarcity or curtailments.

RATE MATTERS

Monongahela

     In March 2000, the West Virginia legislature passed House Resolution 27 approving an electric deregulation plan submitted by the West Virginia PSC with certain modifications. Under the resolution, the implementation of the West Virginia deregulation plan cannot occur until the legislature enacts certain tax changes regarding the preservation of tax revenues for state and local government and other changes conforming to the plan and authorizing implementation. The plan provides for all customers to have choice of a generation supplier and allows Monongahela to transfer the West Virginia portion (approximately 2,037 MW of owned capacity and 78 MW of capacity in generating units at which Monongahela does not exercise control over 100 percent of the facility) of its generating assets to AE Supply. The 2001 legislative session ended April 14, 2001, with no final legislative action regarding implementation of the deregulation plan. It is unlikely that the legislative action needed to implement the West Virginia plan will occur in 2002.

     On June 23, 2000, the West Virginia PSC issued an order regarding the transfer of the generating assets of Monongahela. In part, the order requires that, after implementation of the deregulation plan, Monongahela file a petition seeking a West Virginia PSC finding that the proposed transfer of generating assets complies with the conditions of the deregulation plan. The June 23, 2000 order also permits Monongahela to submit a petition to the West Virginia PSC seeking approval to transfer its West Virginia generating assets prior to the implementation of the deregulation plan. A filing before implementation of the deregulation plan is required to include commitments to the consumer and other protections contained in the deregulation plan. On August 15, 2000, with a supplemental filing on October 31, 2000, Monongahela filed a petition seeking West Virginia PSC approval to transfer its West Virginia generating assets to AE Supply. Settlement discussions regarding the generating asset transfer continue with various parties.

     On October 11, 2000, the West Virginia PSC approved an interim increase of the commodity rate for gas customers of Monongahela (formerly West Virginia Power customers) for gas service bills rendered on and after December 1, 2000. On December 11, 2000, the West Virginia PSC approved additional increases for bills rendered on and after January 1, 2001 through November 30, 2001 (total revenue
54
increase for the twelve-month period of $5.7 million or 25.1%). The commodity rate, or PGA rate, is the portion of the bill that reflects the cost of gas, which increased significantly during 2000. The West Virginia PSC approved a tiered rate structure with rates established for the winter heating season, effective January 1, 2001 through April 30, 2001 and further increased rates effective May 1, 2001 through November 30, 2001, dependent upon the level of cost recovery after the winter heating season. This approach allowed Monongahela full recovery of these costs but eased the increase on the average customer. On October 10, 2001, the West Virginia PSC approved an interim decrease in the PGA rate effective with bills rendered on and after December 4, 2001 through November 30, 2002 (total revenue decrease for the twelve-month period of $5 million or 15.3%). 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. With this adjustment, customers will benefit from recent decreases in national market prices. These increases and decreases in gas cost recovery revenues have no effect on earnings because they were implemented via the PGA mechanism. Under the PGA procedure, differences between revenues received for energy costs and actual energy costs are deferred until the next proceeding when energy rates are adjusted to return or recover previous over-recoveries or under-recoveries, respectively.

     On January 4, 2001, Mountaineer filed for a rate increase with the West Virginia PSC in response to, among other things, the significant increases in the market price for natural gas since July 1998 when Mountaineer and the Commission, among others, agreed to the three-year rate moratorium that ended on October 31, 2001. As a result of extensive discussions among the parties, a settlement was reached and on July 25, 2001, a Joint Stipulation and Agreement for Settlement was filed with the Commission. In October 2001, the Commission approved the settlement agreement which provides for a base revenue increase of $5 million per year and an increase in gas cost recovery revenues of approximately $23 million per year (a total increase of approximately 16.5 percent over existing rates) effective November 1, 2001. Also, Mountaineer returned to standard PGA treatment of purchased gas costs at the conclusion of the rate moratorium, beginning November 1, 2001. With the PGA, increases and decreases in gas costs prudently incurred have no effect on earnings.

     In October 2000, the PUCO approved a settlement that implemented a restructuring plan for Monongahela. This restructuring plan allowed Ohio customers of Monongahela to choose their generation supplier starting January 1, 2001. Also, Monongahela was permitted to transfer the Ohio portion (approximately 352 MW) of its generating assets to AE Supply at book value. Monongahela transferred these generating assets on June 1, 2001. Additionally, the plan provides for the following: residential customers will receive a five percent reduction in the generation portion of their electric bills during a five-year market development period which began on January 1, 2001 and these rates will be frozen for the five years; for commercial and industrial customers, existing generation rates will be frozen at the current rates for the market development period, which began on January 1, 2001 (The market development period is three years for large commercial and industrial customers and five years for small commercial customers); Monongahela will collect from shopping customers a regulatory transition charge of $0.0008 per kilowatt-hour (kWh) for the market development period; and, AE Supply is permitted to offer competitive generation service throughout Ohio.

Potomac Edison

     In December 1999, the Maryland PSC approved a settlement agreement, which allowed customer choice of generation suppliers effective July 1, 2000, for nearly all Maryland customers of Potomac Edison. In June 2000, the Maryland PSC authorized Potomac Edison to transfer the Maryland portion of its generating assets to AE Supply. Potomac Edison also obtained the necessary approvals from the Virginia SCC and the West Virginia PSC to transfer the Virginia and West Virginia portions of Potomac Edison's generating assets to AE Supply in conjunction with the transfer of the Maryland portion of those
55
assets. In August 2000, Potomac Edison transferred approximately 2,100 MW of its Maryland, Virginia, and West Virginia generating assets to AE Supply.

     On July 11, 2000, the Virginia SCC issued an order, approving Phase I of Potomac Edison's Functional Separation Plan that provided for the transfer of its Virginia jurisdictional generating assets at book value to AE Supply. In conjunction with the separation plan, the Virginia SCC approved a Memorandum of Understanding (MOU). The MOU provided that, effective with bills rendered on or after August 7, 2000, base rates were reduced by $1 million; Potomac Edison would not file for a base rate increase prior to January 1, 2001; and the fuel rate would be rolled into base rates effective with bills rendered on or after August 7, 2000. Potomac Edison was not required to refund to customers the over-recovered fuel balance of $230,055. A fuel rate adjustment credit was also implemented on August 7, 2000, reducing annual fuel revenues by $750,000. Effective August 2001, the fuel rate adjustment credit dropped to $250,000. Effective August 2002, the fuel rate adjustment credit will be eliminated. In addition, Potomac Edison has agreed to operate and maintain its distribution system in Virginia at or above historic levels of service quality and reliability, and, during the default service period, to contract for generation service to be provided to customers at rates set in accordance with the Virginia Electric Utility Restructuring Act.

     On August 10, 2000, Potomac Edison filed an application with the Virginia SCC to transfer the hydroelectric assets located within the state of Virginia to a subsidiary--Green Valley Hydro, LLC. On December 14, 2000, the Virginia SCC approved the transfer. On June 1, 2001, Potomac Edison transferred these assets to Green Valley Hydro, LLC and distributed its ownership of Green Valley Hydro, LLC to AE. Green Valley Hydro, LLC will become a subsidiary of the yet to be formed parent holding company of AE Supply.

     All Virginia utilities were required to submit a restructuring plan by January 1, 2001, to be effective on January 1, 2002. Accordingly, Potomac Edison filed Phase II of its Functional Separation Plan with the Virginia SCC on December 19, 2000. On December 21, 2001, the Virginia SCC approved the Plan. Customer choice was implemented for all Virginia customers in Potomac Edison's service territory beginning on January 1, 2002.

     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 Potomac Edison pays to the AES Warrior Run cogeneration project before determining amounts to be recovered from Maryland customers.

     An increase in Maryland base rates became effective with bills rendered on or after January 8, 2001. This increase is a result of the phase-in of the rate increase included in a settlement agreement approved by the Maryland PSC in October 1998. The settlement agreement includes recognition and dollar-for-dollar recovery of costs to be incurred from the AES Warrior Run PURPA project. Under the terms of this settlement agreement, Potomac Edison increased its rates about 4% in each of the years 1999, 2000, and 2001 (a $79 million total revenue increase during 1999 through 2001). The increases were designed to recover additional costs of about $131 million, over the period 1999-2001, for capacity purchases from the AES Warrior Run project net of alleged overearnings of $52 million for the same period. The 1998 settlement agreement also required that Potomac Edison share with customers 50 percent of earnings above an 11.4 percent return on equity for 1999 and 2000. As a result, 50 percent of the amount above the threshold earnings amount, or $9.7 million attributable to 1999, was distributed to customers in the
56
form of an Earnings Sharing Credit effective June 7, 2000 through April 30, 2001. An Earnings Sharing Credit of $1.9 million attributable to 2000 was distributed to customers effective September 6, 2001 through January 8, 2002.

     Effective with bills rendered on or after January 8, 2002, there was a decrease in Maryland distribution rates. 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. Under the terms of this settlement agreement (covering stranded cost quantification mechanism, price protection mechanism and unbundled rates), Potomac Edison decreased its rates 7 percent for residential customers and .5 percent for the majority of commercial and industrial customers. 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 consistent with the 1999 settlement agreement. Accordingly, distribution rates have been further reduced by $3 million from the previously approved rates in the 1999 settlement agreement. The distribution rate cap for all customers is effective 2002 through 2004.

West Penn

      In November 1998, the Pennsylvania PUC approved a settlement agreement between West Penn and parties to West Penn's restructuring proceeding. Under the terms of the settlement, two-thirds of West Penn's customers were permitted to choose an alternate generation supplier as of January 2, 1999. The remaining one-third of West Penn's customers were permitted to do so starting January 2, 2000. The settlement agreement provided for a rate refund from 1998 revenue (about $25 million) via a 2.5% rate decrease throughout 1999, capped rate provisions and recovery of $670 million of transition costs during the transition period (1999 through 2008). In 1999, West Penn issued $600 million of transition bonds to securitize most of the transition costs. As a result of the securitization of transition costs, West Penn is authorized by the Pennsylvania PUC to collect an intangible transition charge (ITC) to provide revenues to service the transition bonds and the competitive transition charge (CTC) was correspondingly reduced. Actual CTC revenues billed to customers in 2001, 2000 and 1999 totaled $0.5 million, $7.6 million and $92.7 million, respectively, net of gross receipts tax and a separate agreement with one customer to accelerate the recovery of CTC. On November 30, 2001, the Pennsylvania PUC issued an order authorizing West Penn to add the under-recovery of its CTC for the year ending July 31, 2001 to the existing under-recovery from the previous period. Through July 31, 2001 the Company has recorded a regulatory asset of $32 million for the difference in the authorized CTC revenues, adjusted for securitization savings to be shared with customers and the actual transition revenues billed to customers. The PUC also authorized future CTC under-recoveries, if any, shall be deferred as a regulatory asset for full and complete recovery. The November 1998 settlement also allowed West Penn to transfer its 3,778 MW of generating assets at book value to AE Supply, which was completed in 1999.

     The Pennsylvania Department of Revenue has 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 is effective for calendar year 2002. State law directs West Penn to recover these increased tax charges by means of a State Tax Adjustment Surcharge (STAS) added to customer bills. On October 29, 2001, West Penn filed a request with the Pennsylvania PUC to recover the increased tax liability of approximately $16.8 million from ratepayers. By order entered December 21, 2001, the Pennsylvania PUC directed West Penn to include the STAS on customer bills rendered between January 1, 2002 and December 31, 2002. On January 8, 2002, the Office of Consumer Advocate (OCA) filed an appeal of the Commission order to the
57
Commonwealth Court of Pennsylvania. West Penn is collecting the tax charges during the pendency of the appeal. Any further Commission action on this matter is held in abeyance pending the resolution of the OCA Petition for Review in the Commonwealth Court. West Penn has intervened at Commonwealth Court in support of the Commission's decision. On March 21, 2002, the Commonwealth Court granted the Pennsylvania PUC's motion to dismiss the OCA's appeal of the Pennsylvania PUC's decisions in this matter. The PUC will likely reschedule hearings.

AGC

     AGC's rates are set by a formula filed with and previously accepted by the FERC. 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% for 1996 and will continue at that rate until the time any affected party requests and the Commission grants a change. No party has requested any change.

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 generating units now owned by AE Supply are subject to the same environmental regulations as they were when owned by the Distribution Companies.

     The cost of meeting known environmental standards is provided in the "Capital Requirements and Financing" section of this report. 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, normal to fossil fuel operations, are experienced and are accommodated by the regulatory process.

     Allegheny meets current emission standards as to sulfur dioxide (SO₂) by 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 Clean Air Act Amendments of 1990 (CAAA), among other things, require an annual reduction in total utility emissions within the United States of 10 million tons of SO₂ and two million tons of nitrogen oxides (NO_x) from 1980 emission levels, to be completed in two phases, Phase I and Phase II. Five coal-fired Allegheny plants were affected in Phase I, and the remaining plants were affected in Phase II.

     In an effort to introduce market forces into pollution control, the CAAA created SO₂ emission allowances. An allowance is defined as an authorization to emit one ton of SO₂ into the atmosphere.
58
Subject to regulatory limitations, allowances may be sold or banked for future use or sale. Allegheny received, through an industry allowance pooling agreement, a total of approximately 554,000 bonus and extension allowances during Phase I. These allowances were in addition to the CAAA Table A allowances that the Allegheny subsidiaries received of approximately 356,000 per year during the Phase I years. Beginning in 2000, for Phase II, Allegheny has received and will continue to receive approximately 220,000 allowances per year. 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 certain derivative or hedging allowance transactions.

     Installation of scrubbers at the Harrison Power Station was the strategy undertaken by Allegheny to meet the required SO₂ emission reductions for Phase I (1995-1999). Allegheny estimates that its banked allowances will allow it to economically comply with Phase II SO₂ limits through 2005, and possibly beyond. Studies are ongoing to evaluate cost-effective options to comply with Phase II 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 will require some Selective Catalytic Reduction (SCR) or other post-combustion control technologies, are being mandated in Maryland, Pennsylvania, and West Virginia for ozone nonattainment (Title I) reasons. Continuous emission monitoring equipment has been installed on all Phase I and Phase II units.

     Title I of the CAAA established an Ozone Transport Commission (OTC), which determined that utilities within the Northeast Ozone Transport Region (OTR), including Maryland and Pennsylvania, would be required to make additional NO_x reductions in order for the OTR to meet the ozone National Ambient Air Quality Standards (NAAQS). Under terms of a Memorandum of Understanding (MOU) among the OTR states, Allegheny-operated stations located in Maryland and Pennsylvania were required to reduce NO_x emissions by approximately 55% from the 1990 baseline emissions, with a compliance date of May 1999. Previously installed NO_x controls on Allegheny's Maryland and Pennsylvania generating plants allowed Allegheny to meet this compliance goal, and are expected to maintain the 55% reduction requirement through the year 2002.

     In October 1998, the EPA issued a NO_x State Implementation Plan (SIP) call rule that required the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Maryland, Pennsylvania, and West Virginia, beginning May 2003. The EPA's NO_x SIP call regulation has been under litigation, but on March 3, 2000, the DC Circuit Court of Appeals issued a decision that upheld the regulation. However, the court did issue a subsequent order on August 30, 2000, that postponed the initial compliance date of the NO_x SIP call from May 2003 to May 2004. An appeal of the March 3, 2000 court decision before the U.S. Supreme Court was denied in March 2001. During 2000, Pennsylvania and Maryland promulgated final rules to implement the EPA's No_x SIP call requirements beginning May 2003. Maryland and Pennsylvania are not expected to delay this implementation date, nor are they legally required to do so. During 2001, the West Virginia Department of Environmental Protection issued a final rule to implement the EPA's No_x SIP call requirements beginning May 2004. The WV No_x SIP call rule requires approval by the State legislature, which is anticipated during the 2002 session. Allegheny's compliance with such stringent regulations will require the installation of expensive post-combustion control technologies on most of its power stations.

     In August 1997, eight northeastern states filed petitions in connection with Section 126 of the CAAA with the EPA requesting the immediate imposition of up to an 85% NO_x reduction from utilities located in the Midwest and Southeast (West Virginia included). The petitions claim NO_x emissions from these upwind sources are preventing their attainment of the ozone standard. In May 1999, the EPA issued a technical approval of the petitions and in December 1999, granted final approval of four of the petitions. The Section 126 petition rulemaking was also under litigation, but a court decision in May 2001, basically
59
upheld the rule. However, the original May 2003 compliance date for the Section 126 rule is likely to be postponed to May 2004, as a result of a court order issued in August 2001. Allegheny's compliance plan for the Section 126 petition rulemaking would be the same as the NO_x SIP call compliance plan discussed above.

     The EPA is required by law to regularly review the NAAQS for criteria pollutants including ozone, particulate, SO₂, and No_x. Previous court orders in litigation by the American Lung Association have expedited these reviews. The EPA in 1996 decided not to revise the SO₂ and NO_x standards. Revisions to particulate matter (PM) and ozone standards were promulgated by the EPA 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. Also, in May 1999, the EPA promulgated final regional haze regulations to improve visibility in Class I federal areas (national parks and wilderness areas). The EPA regional haze regulation is under litigation. The effect on Allegheny of these standards or regulations is unknown at this time, but could be substantial.

     In 1989, the West Virginia Air Pollution Control Commission approved the construction of a third-party cogeneration facility in the vicinity of Rivesville, West Virginia. Emissions impact modeling for that facility raised concerns about the compliance of Monongahela's Rivesville Station with ambient standards for SO₂. Pursuant to a consent order, Monongahela agreed to collect on-site meteorological data and conduct additional dispersion modeling in order to demonstrate compliance. The modeling study and a compliance strategy recommending construction of a new "good engineering practices" (GEP) stack were submitted to the West Virginia Department of Environmental Protection (WVDEP) in June 1993. Costs associated with the GEP stack are approximately $25 million. Monongahela is awaiting action by the WVDEP.

     Under an EPA-approved consent order with Pennsylvania, West Penn completed construction of a GEP stack at the Armstrong Power Station in 1982 at a cost of more than $13 million with the expectation that the EPA's reclassification of Armstrong County to "attainment status" under NAAQS for SO₂ would follow. As a result of the 1985 revision of its stack height rules, the EPA refused to reclassify the area to attainment status. Subsequently, West Penn filed an appeal with the U.S. Court of Appeals for the Third Circuit for review of that decision as well as a petition for reconsideration with the EPA. In 1988, the Court dismissed West Penn's appeal, stating it could not decide the case while West Penn's request for reconsideration before the EPA was pending. West Penn cannot predict the outcome of this proceeding.

     In March 1998, the EPA released its Utility Air Toxics Report to Congress. The report itself did not recommend regulatory controls. However, in December 2000, the EPA did make 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 issue a proposed rule by December 2003, and a final rule by December 2004. Based on this schedule, it is unlikely implementation of mercury controls would be required before 2007-08.

     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 threat of "global warming". If ratified and implemented, this treaty likely would require extensive mitigation efforts on the part of Allegheny to reduce greenhouse gas emissions at electric generation plants and would raise considerable uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation 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 pressure on the US to join the rest of the world in reducing greenhouse gas emissions is expected to continue and increase both internationally and domestically.

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     Allegheny has taken numerous voluntary, precautionary steps to address the issue of global climate change. Many uncertainties remain in the global climate change debate, including the relative contributions of human activities and natural processes, the extremely high potential costs of extensive mitigation efforts, and the significant economic and social disruptions, which may result from a large-scale reduction in the use of fossil fuels. Still, Allegheny has taken the initiative to move forward by undertaking its own voluntary program and will continue to explore cost-effective opportunities to improve efficiency and performance. Allegheny signed a Memorandum of Understanding with the DOE in 1995 to participate in the Climate Challenge. As part of this agreement, Allegheny supports the Climate Challenge Initiatives in cooperation with other companies through EEI. 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 the national Energy Policy Act of 1992, under Section 1605(b) directed toward reducing, controlling, avoiding and sequestering greenhouse gases. 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.

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 compliant with all permit terms, conditions and effluent limitations. However, as permits are renewed, more stringent permit limitations are often applied. Thus far 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 Clean Water Act (CWA) issues. 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, and mixing zones and CWA Section 316(b) Cooling Water Intake Structure. In addition, the EPA is developing new policies concerning protection of endangered species under the CWA and imposition of new CWA requirements to address sediment and biological water quality criteria contamination. The outcome of these rulemakings will fundamentally change the traditional water quality management program from a chemical specific control of point sources to comprehensive and integrated watershed management. This regulatory shift will result in more restrictions on facility discharges as well as nonpoint source runoff resulting from land use practices such as agriculture and forestry and will ultimately address water quality impairment caused by atmospheric deposition.

     Over the past several years TMDLs have become a significant issue because of successful legal challenges to the EPA's treatment of TMDLs under the CWA in various states. Resulting 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 water bodies not currently meeting water quality standards within a relatively short time frame (twelve years). Because of the scientific complexity of the issue, paucity of water quality data, the resource limitations of the state agencies as well as 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
61
quality impaired rivers. Indirectly, TMDL's can adversely affect Allegheny by prohibiting new or increased discharges and curtailing the wastewater discharges of its industrial customers.

     On July 13, 2000, the EPA finalized a rule that modifies the way states are required to develop and implement the TMDL provisions of the CWA. The rule drew widespread criticism from the regulated community, environmental organizations, governors, and state regulators, primarily because it usurps state authority, lacks a sound scientific basis and requires states to develop and implement a complex program in a short time frame with inadequate federal support. Congress responded to the criticism by placing a provision in a supplemental appropriations bill prohibiting the EPA from implementing the rule until October 2001.

     In January 2001 the Bush Administration remanded the rule to EPA for reconsideration. On June 15, 2001 the National Academy of Sciences released a report requested by Congress that recommended a number of changes to EPA's TMDL program. As a result, the EPA has proposed to delay by 18 months the effective date of the rule (April 2003) and to revise the date on which the states are required to submit their next list of impaired waters from April 1, 2002 to October 1, 2002. In the interim, the EPA has undertaken an open and active solicitation of stakeholder input and plans to re-propose the TMDL rule in October, 2002. It is likely that water quality trading provisions will be incorporated into the rule as an innovative means to assist states in more cost-effectively implementing 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. In the meantime the states continue to develop TMDLs under the existing rule and in response Allegheny is proactively working with a number of watershed TMDL stakeholder groups, state agencies and the EPA to ensure development of sound and equitable TMDLs.

     In January 1993, The Hudson Riverkeeper and other environmental groups filed suit against the EPA to force the agency to promulgate rules that would minimize environmental impact from cooling water intake structures. Section 316(b) of the CWA requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. After several amendments, the resulting consent decree divides the rulemaking into three phases:


1.  Phase 1 applies to new facilities that employ a cooling water intake structure. The proposal was promulgated in June 2000 and the final rule was published December 18, 2001.

       2.  Phase 2 pertains to existing utilities and non-utility power producers that currently employ a cooling water intake structure, and whose flow exceeds a minimum threshold to be determined by the EPA. The rule is expected to be published in the Federal Register in March 2002 with final action taken by August 2003.

       3.  Phase 3 will govern existing facilities that employ a cooling water intake structure not covered by the Phase 2 rule (pulp and paper, chemical plants, etc.) and whose intake flow exceeds a minimum threshold that will be determined by the EPA. The proposal is due by June 2003 with final action in December 2004.

     The Phase 1 new facility rule applies to all new generation that begins 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 largely unspecified but probably including 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 impact the new facility rule would
62
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 impact." Additionally, 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 on 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. As expected, 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 by means of random selection.

     After significant political debate the EPA lowered the maximum contaminant level (MCL) drinking water standard for arsenic from 50 to 10 ug/l to become effective February 2002. 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 MCL's are used in other regulatory programs (such as groundwater protection, hazardous waste classification and brownfield cleanup programs) there is potential that 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.

Hazardous and Solid Wastes

     Pursuant to the Resource Conservation and Recovery Act of 1976 (RCRA) 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 re-permitting 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 (the only Distribution Company still owning generation), continues to expand its efforts to market CCBs for beneficial applications and thereby reduce landfill requirements. In 2001, AE Supply and Monongahela received approximately $1,150,000 from the external sale and utilization of approximately 650,000 tons of fly ash, 260,000 tons of bottom ash and 23,000 tons of boiler slag, and 510,000 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, synthetic gypsum for wallboard production, and grouting of mines and oil wells.


AE Supply and Monongahela completed the construction of a processing plant that converts the flue-gas desulfurization by-product from the Pleasants Power Station into a commercial grade synthetic gypsum material to be used in the manufacture of wallboard. This process has significantly reduced the amount of the by-product going to an impoundment. The processing plant went into commercial production in 2000. Production problems have limited the quantity of gypsum produced to well below
63
expected production in 2000 and 2001. New equipment installed in late 2001 is expected to bring production closer to originally expected production, but still below the contractually required production. Because the gypsum customer contracted for a minimum annual quantity, penalties have been incurred for these two years totaling approximately $3.54 million. The customer has agreed to carry this charge, accepting payment in material through at least 2002, and has indicated a desire to renegotiate the required minimum annual quantity to avoid future production shortfall penalties. Approximately $0.71 million of this penalty has been offset through 2001 via material exchange, leaving $2.83 million in unpaid penalties as of December 31, 2001.

     Potomac Edison received a notice from the Maryland Department of the Environment (MDE) in 1990 regarding a remediation ordered under Maryland law at a facility previously owned by Potomac Edison. The MDE has identified Potomac Edison as a potentially responsible party under Maryland law. Remediation is being implemented by the current owner of the facility which is located in Frederick. It is not anticipated that Potomac Edison's share of remediation costs, if any, will be substantial.

     The Distribution Companies are also among a group of potentially responsible parties under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), for the Jack's Creek/Sitkin Smelting Superfund Site and the Butler Tunnel Superfund Site in Pennsylvania. (See ITEM 3. LEGAL PROCEEDINGS for a description of these Superfund cases.)

REGULATION

     Allegheny is 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. These companies and AE Supply's unregulated generation are also regulated as to various aspects of their business by the FERC. In addition, they are subject to numerous other local, state, and federal laws, regulations, and rules.

     In June 1995, the SEC published its report, which recommended changes to PUHCA, including a recommendation to Congress to repeal the entire act. Bills have been introduced in the Congress to repeal PUHCA, but have not passed. Allegheny cannot predict what changes, if any, will be made to PUHCA as a result of these activities.

     In 2001, the Distribution Companies continued to take part in and fund various programs to assist low-income customers, customers with special needs, and customers experiencing temporary financial hardship.

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. 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. Some of the properties are also subject to a second lien securing certain solid waste disposal and pollution control notes. The indenture under which AGC's unsecured debentures and medium-term notes 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 and medium-term notes are contemporaneously secured equally and ratably with all other
64
indebtedness secured by such lien. Transmission and distribution 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 transmission and distribution lines and substations are located. Each of the Distribution Companies possesses the power of eminent domain with respect to its public utility operations. (See also ITEM 1. BUSINESS, ALLEGHENY MAP, and AE SUPPLY MAP.)

     MGS owns more than 375 natural gas wells located throughout West Virginia and has active leaseholds that cover more than 86,000 acres. In addition to its production assets, MGS owns (1) 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 (2) approximately 400 miles of gathering lines located in the same general vicinity.

ITEM 3
.          LEGAL PROCEEDINGS

     As of February 15, 2002, Monongahela has been named as a defendant along with multiple other defendants in a total of 8,266 pending asbestos cases involving one or more plaintiffs. 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 wherein multiple plaintiffs file claims against multiple defendants in the same case, it is presently impossible to determine the actual number of cases in which plaintiffs make claims against the Distribution Companies. However, 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. Three plaintiffs are known to be either present or former employees of Monongahela. 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. A total of 1,475 cases have been previously settled and/or dismissed against Monongahela for an amount substantially 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 determine whether additional cases will be filed.

     On January 27, 1995, Allegheny filed a declaratory judgment action in the Court of Common Pleas of Westmoreland County, Pa., against its historic comprehensive general liability (CGL) insurers. This suit sought a declaration that the CGL insurers have a duty to defend and indemnify the Distribution Companies in the asbestos cases, as well as in certain environmental actions. Four insurers have settled since the filing of this action. Another Defendant was dismissed as a party. The declaratory judgment action may be re-filed against that party in a different venue. Settlements from other insurance carriers are also being actively pursued. The final outcome of such proceedings, however, cannot be predicted.

     On March 4, 1994, the Distribution Companies received notice that the EPA had identified them as
65
potentially responsible parties (PRPs) under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, with respect to the Jack's Creek/Sitkin Smelting Superfund Site (Site). There are approximately 175 other PRPs involved. A Remedial Investigation/Feasibility Study (RI/FS) prepared by the EPA originally indicated remedial alternatives, which ranged as high as $113 million, to be shared by all responsible parties. A PRP Group consisting of approximately 40 members, and to which the Distribution Companies belong, has been formed and has submitted an addendum to the RI/FS, which proposes a substantially less expensive cleanup remedy. In 1999, the PRP Group entered into a consent order with the EPA to remediate the site. 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 October 1, 1996, Potomac Edison received a questionnaire from the EPA concerning a release or threat of release of hazardous substances, pollutants, or contaminants into the environment at the Butler Tunnel Site located in Luzerne County, Pa. Potomac Edison notified the EPA that it has no records or recollection of any business relations with the site or any of the companies identified in the questionnaire. It is not possible to determine at this time what effect, if any, this matter may have on Potomac Edison.

     In 1979, National Steel Corporation (National Steel) filed suit against AE and certain subsidiaries in the Circuit Court of Hancock County, W.Va., alleging damages of approximately $7.9 million as a result of an order issued by the West Virginia PSC requiring curtailment of National Steel's use of electric power during the United Mine Workers' strike of 1977-78. A jury verdict in favor of AE and the subsidiaries was rendered in June 1991. National Steel has filed a motion for a new trial, which is still pending before the Circuit Court of Hancock County. AE and the subsidiaries believe the motion is without merit; however, they cannot predict the outcome of this case.

     The Attorney General of the State of New York and the Attorney General of the State of Connecticut, in letters dated September 15, 1999, and November 3, 1999, respectively, notified AE of their intent to commence civil actions against AE and/or its subsidiaries alleging violations at the Fort Martin Power Station under the federal Clean Air Act, which requires power plants that make major modifications to comply with the same emission standards applicable to new power plants. Other governmental agencies may commence similar actions in the future. Fort Martin 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.

     On August 2, 2000, AE received a letter from the EPA requiring it to provide certain information on the following ten electric generating stations: 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 federal Clean Air Act to determine compliance with federal Clean Air Act and state implementation plan requirements, including potential application of the new source performance standards, which can require the installation of additional air pollution control equipment upon the major modification of an existing facility. Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in some cases. AE believes its subsidiaries' generating facilities have been operated in accordance with the Clean Air Act and the rules implementing that Act. The experience of other utilities, however, suggests that in recent years, the EPA may have revised its interpretation of the rules regarding the determination of whether an action at a facility constitutes routine maintenance, which would not trigger the requirements of the new source performance standards, or a major modification of
66
the facility, which would require compliance with the new source performance standards. Section 114 information requests concerning facility modifications are often followed by enforcement actions. At this time, AE is not able to determine what effect, if any, the EPA's inquiry may have on its operations. If new source performance standards are applied to Allegheny generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures.

     In June 2000, Monongahela was contacted by the U.S. Environmental Protection Agency (EPA) and the Environmental Enforcement Section of the Department of Justice (DOJ) concerning the release of approximately 19,000 gallons of non-PCB oil to the environment, following the catastrophic failure of a 500 MVA, 265 kV transformer on April 11, 1998, at Monongahela's Belmont substation. Monongahela informed the EPA and the DOJ that it responded to this release immediately, thereby preventing any of the oil from reaching major waterways. Monongahela also informed the federal agencies that it has been working in conjunction with 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 of 2001, and the United States 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, automatic valves and pumps at the substation to prevent any oil which may leak from the equipment from leaving the property. In addition, Monongahela agreed to pay a civil penalty in the amount of $252,000.

     On December 7, 2001, Nevada Power Company filed a Complaint with the Federal Energy Regulatory Commission against AE Supply, alleging that the prices in three power sale contracts negotiated between December, 2000 and February, 2001, all of which were for power sales during 2002, were the product of markets found by the Commission to be dysfunctional and not competitive, and therefore unjust and unreasonable. Nevada Power Company asked the Commission to determine and fix the just and reasonable prices consistent with the mitigated prices already established by the Commission for the Western market. Nevada Power Company filed substantially identical Complaints against a number of other suppliers. On December 27, 2001, AE Supply filed an Answer to the Complaint, requesting summary denial of the Complaint because: (1) Nevada Power Company had no contract with AE Supply, because it had negotiated the power sale contracts at issue with Merrill Lynch Capital Services, Inc. before AE Supply acquired Merrill Lynch's wholesale power trading business, and the contracts had not yet been assigned to AE Supply; and (2) Nevada Power Company's claim for relief was fatally flawed in a number of respects. While AE Supply believes the Complaint is without merit, it cannot predict the outcome of this litigation. On February 15, Nevada Power Company filed an answer and AE Supply responded on March 1, 2002.

     On February 25, 2002, the California PUC and the CAEOB filed a complaint with the FERC against AE Supply and a number of other suppliers. The CAPUC's complaint requested that each of the contracts challenged in the complaint be abrogated, as containing both unreasonable pricing and unjust and unreasonable non-price terms and conditions, or, in the alternative, that the challenged contracts be reformed to provide for just and reasonable pricing, reduce their duration, and strike from the contracts the specific non-price contract terms and conditions found to be unjust and unreasonable. The CAEOB's complaint requested that the contracts be voidable at the State's option, abrogated, or reformed. On March 18, 2002, AE Supply filed its answer to the CAPUC and CAEOB complaints, in which it requested that the complaints be expeditiously denied. While AE Supply believes the complaints are without merit, it cannot predict the outcome of this litigation.

     On March 19, 2002, the Attorney General of the State of California filed a complaint with the FERC alleging that various named and unnamed sellers of electric energy in California violated the Federal Power Act by failing properly to file with the FERC the terms of their short-term power sales to the California Independent System Operator, the California Power Exchange and the CDWR. The complaint
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asks the FERC, among other things, to require the sellers under these transactions to pay refunds with interest for their short-term power sales during 2000 and 2001. The complaint does not specifically name AE Supply, although AE Supply did make short-term power sales in California during 2001. At this time, it is not possible to determine what effect, if any, this action may have on AE Supply.

ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     AE, Monongahela, Potomac Edison, West Penn, AGC and AE Supply did not submit any matters to a vote of shareholders during the fourth quarter of 2001.

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The names of the executive officers of each company, their ages as of December 31, 2001, the positions they hold, or held during 2001, and their business experience during the past five years appears below:

Executive Officers of the Registrants

Position (a) and Period of Service
Name
Age
AE
MP
PE
WP
AGC
AE
SUPPLY

Paul M. Barbas (b)

45

Vice President
(1999 - )

Executive VP
(12/01 - )

Executive VP
(12/01 - )

Executive VP
(12/01 - )

Director
(2/02-    )

David C. Benson (c)

48

Vice President
(2000 - )

Vice President
(11/99-    )

Regis F. Binder (d)

49

Vice President &
Treasurer
(1998 -    )

Treasurer
(1998 -    )

Treasurer
(1998 -    )

Treasurer
(1998 -    )

V.P.
(2000- )
and
Treasurer
(1998 - )

Treasurer
(11/99-    )

Marleen L. Brooks (e)

50

Secretary
(7/00 -    )
Previously,
Asst. Secretary
(4/00-7/00)

Secretary
(7/00 -    )
Previously,
Asst. Secretary
(4/00-7/00)

Secretary
(7/00 -    )
Previously,
Asst. Secretary
(4/00-7/00)

Secretary
(7/00 -    )
Previously,
Asst. Secretary
(4/00-7/00)

Secretary
(7/00 - )
Previously,
Asst. Secretary
(4/00-7/00)

Secretary
(7/00-    )

Richard J. Gagliardi

51

Vice President
(1991 -    )

Asst. Secretary
(1990-96)
Vice President

(2/02-    )

Vice President

(2/02-    )

Vice President

(2/02-    )

Vice President
(2000 -    )
Previously,
Asst. Treasurer
(1982-96)

Vice President

(2/02-    )

James P. Garlick (f)

41

Vice President
(1/01 -     )

Vice President
(1/01-    )

James R. Haney (g)

45

Vice President
(1998-    )

Vice President
(1998-    )

Vice President
(1998-    )

Thomas K. Henderson

61

Vice President
(1997-    ) &
General Counsel
(1999- )

Vice President
(1995-    )

Vice President
(1995-    )

Vice President
(1985-    )

Director & V.P.
(1996-    )

Vice President
(11/99-    )

Thomas J. Kloc

49

Vice President &
Controller
(1998-    )

Controller
(1996-    )

Controller
(1988-    )

Controller
(1995-    )

Vice President
(1999-    ) &
Controller
(1988- );
Previously,
Director

(1999-2000)

Controller
(5/00-    )

Ronald A. Magnuson (h)

44

Vice President
(1999-    )

Vice President
(1999-    )

Vice President
(1999-    )

69

The names of the executive officers of each company, their ages as of December 31, 2001, the positions they hold, or held during 2001, and their business experience during the past five years appears below:

Executive Officers of the Registrants
(cont'd.)
Position (a) and Period of Service
Name
Age
AE
MP
PE
WP
AGC
AE
SUPPLY

Michael P. Morrell (i)

53

Senior Vice President
(1996-    )

V.P. & Dir.
(1996-    )

V.P.& Dir.

(1996-    )

V.P. & Dir.
(1996-    )

President
(2/01 -    ) & Dir.

(1996 -    )
Previously,
Vice President
(1996-2/01)

President & COO
(2/01-    )

Alan J. Noia

54

Chairman & CEO
(1996-    )
President & Director
(1994-    )
Previously,
COO
(1994-96)

Chairman & CEO
(1996-    )
Director
(1994-    )

Chairman & CEO
(1996-    )
Director
(1990-    )
Previously,
President
(1990-1994)

Chairman & CEO
(1996-    )
Director
(1994-    )

Chairman & CEO
(1996-    )
Previously,
President
(1996-2000)
Director & V.P.
(1994-96)

Chairman & CEO
(1999-    )

Karl V. Pfirrmann (j)

53

Vice President
(2000-    )

Vice President
(2000-    )

Vice President
(2000-    )

Jay S. Pifer

64

Senior Vice President
(1996-    )

President & Director
(1995- )

President &
Director
(1995- )

President
(1990- )
& Director
(1992- )

Director
(2/02-    )

Victoria V. Schaff (k)

57

Vice President
(1997-2002)

Vice President
(2000-2002)
& Director
(2/01 -2002)

Vice President
(2000-2002)
& Director
(2/01 -2002)

Vice President
(2000-2002)
& Director
(2/01 -2002)

Director
(2/01 -2002)

Peter J. Skrgic (l)

60

Senior Vice President
(1994-2001)
Previously,
Vice President
(1989-1994)

Vice President
(1996-2001)
& Director
(1990 - 2001)

Vice President &
Director
(1990-2001)

Vice President
(1996-2001)
& Director
(1990 - 2001)

President &
Director
(2000 - 2001)
Previously,
Vice President &
Director
(1989-2000)

President, COO &
Director
(1999-2001)

Bruce E. Walenczyk (m)

49

Senior Vice President &
CFO
(5/01 -    )

Vice President &
Director
(5/01 -    )

Vice President &
Director
(5/01 -    )

Vice President &
Director
(5/01 -    )

Vice President
(5/01 -    )
& Director
(2/02-    )

Vice President
(5/01-    )

Robert R. Winter

58

Vice President
(1987-    )

Vice President
(1995-    )

Vice President
(1995-    )

70

(a)

All officers and directors are elected annually, except the Board of AE, which is a staggered Board.

(b)

Prior to his appointment as Vice President of AE, Mr. Barbas was President, GE Capital Rental Services (3/97-2/99) and President, GE Capital Computer Rental Services (10/93-3/97).

(c)

Prior to his appointment as Vice President of AGC, Mr. Benson was Vice President, AESC (7/98); Vice President & Assistant Treasurer AESC (5/96-7/98); and Vice President AESC (6/95-5/96).

(d)

Prior to his appointment as Vice President and Treasurer of AE and Treasurer of Monongahela, Potomac Edison, West Penn and AGC, Mr. Binder was Executive Director, Regulation and Rates for AESC (1997-1998); General Manager, Industrial Marketing for AESC (1996-1997); and Director, Rates for AESC (1995-1996).

(e)

Prior to her appointment as Assistant Secretary, Ms. Brooks was Senior Attorney for AESC (2/99 - 4/00); and Attorney for AESC and Potomac Edison (7/81 - 2/99).

(f)

Prior to his appointment as Vice President of AGC, Mr. Garlick was Regional Manager of Potomac Edison, R. Paul Smith/Hydro Region (11/95 - 6/98); Regional Manager of West Penn, Armstrong/Springdale Region (6/98 - 10/98); and Director, Human Resources AE Supply (10/98 - 12/00).

(g)

Prior to his appointment as Vice President Customer Operations, Mr. Haney was Executive Director, Operating Business Unit (8/98-10/98); Director, Operations Services (5/96-8/98); Director, Transmission Projects (12/95-5/96); Manager, Construction (2/95-12/95).

(h)

Prior to his appointment as Vice President of Monongahela, Potomac Edison and West Penn, for AESC, Mr. Magnuson was Executive Director, Customer Affairs (4/99-7/99); Executive Director, Human Resources (10/98-4/99); and Director Human Resources (1/95-10/98).

(i)

Prior to his appointment as Senior Vice President of AE and Vice President of Monongahela, Potomac Edison, West Penn and AGC, Mr. Morrell was Vice.President. - Regulatory and Public Affairs, Jersey Central Power & Light Company (JCPP&L) (8/94-4/96).

(j)

Prior to his appointment as Vice President of Monongahela, Potomac Edison and West Penn, Mr. Pfirrmann was Vice President AESC (9/95-5/96); Vice President Monongahela, Potomac Edison and West Penn (5/96-8/98); and Vice President AESC (8/98-5/00).

(k)

Prior to her appointment as Vice President of AE, Ms.Schaff was a Vice President of AESC (1/96-1/97) and a Federal Affairs Representative with The Union Electric Company (4/88-12/95). Ms. Schaff died on March 8, 2002.

(l)

Mr. Skrgic resigned as an officer effective February 1, 2001.

(m)

Prior to his appointment as Senior Vice President and Chief Financial Officer of AE, Director and Vice President of Monongahela, Potomac Edison and West Penn, and Vice President of AGC, Mr. Walenczyk was Managing Director, Investment Banking Division, PaineWebber, Inc. (1996-1998); Vice President-Finance, PSEG Energy Holdings, Inc. (3/98-4/01).

71

PART II

ITEM 5.    MARKET FOR THE REGISTRANTS' COMMON EQUITY AND

                  RELATED STOCKHOLDER MATTERS

AE

     AYE is the trading symbol of the common stock of AE on the New York, Chicago, and Pacific Stock Exchanges. The stock is also traded on the Amsterdam (Netherlands) and other stock exchanges. As of December 31, 2001, there were 37,644 holders of record of AE's common stock.

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

2001

2000

Dividend

High

Low

Dividend

High

Low

1^st Quarter

43 cents

$49.00

$39.50

43 cents

$29.5625

$23.625

2^nd Quarter

43 cents

$55.90

$44.70

43 cents

$31.75

$26.6875

3^rd Quarter

43 cents

$49.25

$35.20

43 cents

$39.875

$27.75

4^th Quarter

43 cents

$40.01

$32.99

43 cents

$48.75

$36.6875

     The high and low prices through March 11, 2002 were $38.23 and $37.80. The last reported sale on that date was at $38.00.

     Monongahela, Potomac Edison, and West Penn
. The information required by this Item is not applicable as all the common stock of those companies is held by AE.

     AGC
. The information required by this Item is not applicable as all the common stock of AGC is held by Monongahela and Allegheny Energy Supply Company, LLC.
     AE Supply.
The information required by this Item is not applicable as there is no established public trading market for AE Supply's equity securities. Allegheny Energy, Inc. owns approximately 98% of the interest in Allegheny Energy Supply Company, LLC. and ML IBK Positions, Inc. owns 1.967.
72

ITEM 6.
     SELECTED FINANCIAL DATA

Page No.

AE

Monongahela

Potomac Edison

West Penn

AGC

AE Supply

D- 1

D- 8

D-11

D-14

D-17

D-18

The information required by this Item was furnished in the copy of the Form 10-K filed with the Securities and Exchange Commission. You may obtain a complete copy of Form 10-K upon making a written or an oral request directed to: Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740, Attention: Marleen L. Brooks, Secretary (tel. 301-790-3400).

ALLEGHENY ENERGY, INC.

D-1

Condensed Financial Statements

Year ended December 31, 2001

Monongahela
Power
Company
and Subsidiaries

The Potomac
Edison
Company
and Subsidiaries

West Penn
Power Company
and Subsidiaries

Allegheny
Ventures,
Inc.
and Subsidiaries

Allegheny
Energy Supply
Company, LLC
and Subsidiaries

(Thousands of dollars)

Balance Sheets

Assets

Property, plant, and equipment*

$2,490,741

$1,447,027

$1,713,390

$ 43,800

$5,351,590

Accumulated depreciation

(1,139,904)

(538,301)

(585,417)

(2,624)

(1,958,613)

1,350,837

908,726

1,127,973

41,176

3,392,977

Excess of cost over net assets acquired

195,033

26,218

367,287

Cash and temporary cash investments

4,439

1,608

6,257

4,364

20,909

Other current assets

318,825

130,356

201,123

102,953

681,243

Regulatory assets

100,750

54,081

429,502

9,849

Other

55,463

17,017

12,231

104,201

1,503,877

Total

$2,025,347

$1,111,788

$1,777,086

$278,912

$5,976,142

*Includes construction work in progress

Capitalization and liabilities

Common stock, other paid-in capital,

retained earnings, and accumulated other

comprehensive income

$   629,594

$   383,257

$  423,313

$104,523

$1,524,686

Preferred stock

74,000

Long-term debt and QUIDS

784,261

415,797

574,647

10,500

1,130,041

Minority interest

30,476

Short-term debt

14,350

57,597

700

1,073,745

Other current liabilities

180,736

98,021

222,817

141,930

1,216,565

Unamortized investment credit

9,034

9,570

19,951

64,035

Deferred income taxes

238,751

109,748

243,456

412,707

Regulatory liabilities

49,509

20,377

15,255

22,914

Adverse power purchase commitments

253,499

Other

45,112

17,421

24,148

21,259

500,973

Total

$2,025,347

$1,111,788

$1,777,086

$278,912

$5,976,142

Statements of operations

Operating revenues

$  937,723

$  864,534

$1,114,504

$139,644

$8,611,555

Operating expenses

803,973

779,000

955,720

138,996

8,273,639

Operating income

133,750

85,534

158,784

648

337,916

Other income and deductions

8,224

(2,371)

2,034

(410)

5,453

Income before interest charges, preferred

dividends, minority interest, and

cumulative effect of accounting change

141,974

83,163

160,818

238

343,369

Interest charges and preferred dividends

52,517

35,128

50,973

440

103,485

Balance for common stock before minority

interest and cumulative effect of

accounting change

89,457

48,035

109,845

(202)

239,884

Minority interest

(5,049)

Cumulative effect of accounting change

(31,147)

Balance for common stock

$    89,457

$    48,035

$  109,845

$     (202)

$  203,688

ALLEGHENY ENERGY, INC.

D-2

Consolidated Statistics

Year ended December 31

2001

2000

1999

1998

1997

1996

1991

Summary of operations
(Millions of dollars)

Operating revenues

$10,378.9

$4,011.9

$2,808.4

$2,576.4

$2,369.5

$2,327.6

$1,948.6

Operation expense

8,613.1

2,602.4

1,498.1

1,286.0

1,065.9

1,013.0

918.6

Maintenance

287.9

230.3

223.5

217.5

230.6

243.3

204.2

Restructuring charges and asset write-offs

103.9

Depreciation

301.5

247.9

257.5

270.4

265.7

263.2

189.7

Taxes other than income

216.3

210.2

190.3

194.6

187.0

185.4

167.5

Taxes on income

245.1

184.8

164.4

168.4

168.1

128.0

119.1

Allowance for funds used during construction

(11.5)

(7.2)

(6.9)

(5.0)

(8.3)

(5.9)

(7.9)

Other income and deductions

(13.0)

(4.5)

(1.6)

(8.2)

(18.0)

(4.4)

(1.6)

Interest charges, preferred dividends, and preferred

  redemption premiums

288.3

234.4

197.7

189.7

197.2

191.1

165.0

Minority interest

2.3

Consolidated income before extraordinary charge

  and cumulative effect of accounting change

448.9

313.6

285.4

263.0

281.3

210.0

194.0

Extraordinary charge, net (a)

(77.0)

(27.0)

(275.4)

Cumulative effect of accounting change, net (b)

(31.1)

Consolidated net income (loss)

$    417.8

$236.6

$258.4

$(12.4)

$281.3

$210.0

$  194.0

Common stock data
(c)

Shares issued (thousands)

125,276

122,436

122,436

122,436

122,436

121,840

108,452

Treasury shares (thousands)

(12,000)

(12,000)

Shares outstanding (thousands)

125,276

110,436

110,436

122,436

122,436

121,840

108,452

Average shares outstanding (thousands)

120,104

110,436

116,237

122,436

122,208

121,141

107,548

Earnings per average share: (d)

  Consolidated income before extraordinary charge

    and cumulative effect of accounting change

$      3.74

$     2.84

$    2.45

$     2.15

$    2.30

$     1.73

$     1.80

  Extraordinary charge, net (a)

(.70)

(.23)

(2.25)

  Cumulative effect of accounting change, net (b)

(.26)

  Consolidated net income (loss)

$      3.48

$     2.14

$    2.22

$     (.10)

$    2.30

$     1.73

$     1.80

Dividends paid per share

$      1.72

$     1.72

$    1.72

$     1.72

$    1.72

$     1.69

$     1.58

Dividend payout ratio (e)

46.5%

60.6%

64.6%

73.5%

74.7%

97.5%

87.8%

Shareholders

37,644

40,589

44,873

48,869

53,389

58,677

62,095

Market price per share:

  High

$  55.900

$ 48.750

$ 35.188

$  34.938

$ 32.594

$  31.125

$  23.250

  Low

$  32.990

$ 23.625

$ 26.188

$  26.625

$ 25.500

$  28.000

$  17.440

  Close

$  36.220

$ 48.188

$ 26.938

$  34.500

$ 32.500

$  30.375

$  22.250

Book value per share

$  21.630

$ 15.760

$ 15.350

$  16.610

$ 18.430

$  17.800

$  15.540

Return on average common equity (e)

19.40%

18.28%

16.16%

13.26%

12.63%

9.69%

11.70%

Capitalization data
(Millions of dollars)

Common stock

$ 2,710.0

$1,740.7

$1,695.3

$2,033.9

$2,256.9

$2,169.1

$1,685.6

Preferred stock:

  Not subject to mandatory redemption

74.0

74.0

74.0

170.1

170.1

170.1

235.1

  Subject to mandatory redemption

29.3

Long-term debt and QUIDS

3,200.4

2,559.5

2,254.5

2,179.3

2,193.1

2,397.1

1,747.6

Total capitalization

$ 5,984.4

$4,374.2

$4,023.8

$4,383.3

$4,620.1

$4,736.3

$3,697.6

Capitalization ratios:

  Common stock

45.3%

39.8%

42.1%

46.4%

48.8%

45.8%

45.6%

  Preferred stock:

    Not subject to mandatory redemption

1.2

1.7

1.9

3.9

3.7

3.6

6.3

    Subject to mandatory redemption

.8

  Long-term debt and QUIDS

53.5

58.5

56.0

49.7

47.5

50.6

47.3

Total assets
(Millions of dollars)
$11,167.6

$7,697.0

$6,852.4

$6,535.2

$6,654.1

$6,618.5

$4,855.0

ALLEGHENY ENERGY, INC.

D-3

Consolidated Statistics (continued)

Year ended December 31

2001

2000

1999

1998

1997

1996

1991

Property data
(Millions of dollars)

Gross property

$11,086.9

$9,507.0

$8,839.7

$8,395.3

$8,451.4

$8,206.2

$6,255.7

Accumulated depreciation

(4,233.9)

(3,967.6)

(3,632.6)

(3,395.6)

(3,155.2)

(2,910.0)

(2,093.7)

Net property

$ 6,853.0

$5,539.4

$5,207.1

$4,999.7

$5,296.2

$5,296.2

$4,162.0

Gross additions during year:

  Regulated

$    230.8

$   207.6

$   266.2

$   229.4

$   284.7

$   289.5

$   337.7

  Unregulated and other

$    233.3

$   195.6

$   141.3

$       1.8

$       1.4

$   178.5

Ratio of provisions for depreciation to

  depreciable property

2.62%

2.85%

3.23%

3.28%

3.34%

3.47%

3.28%

Revenues
(Millions of dollars) (f)

Residential

$ 1,141.3

$1,018.6

$   930.3

$   880.6

$   892.9

$   932.2

$  708.3

Commercial

633.7

536.5

500.3

501.4

490.5

492.7

375.4

Industrial

776.4

772.8

720.5

753.5

748.1

752.9

600.2

Wholesale and street lighting

70.7

57.4

42.4

69.0

65.1

66.6

50.0

  Revenues from regular utility customers

2,622.1

2,385.3

2,193.5

2,204.5

2,196.6

2,244.4

1,733.9

Other non-gWh

35.8

40.7

9.8

9.9

6.4

7.7

8.7

Bulk power

160.5

135.8

45.7

69.8

39.6

22.4

158.5

Transmission and other energy services

70.8

73.2

61.0

45.2

41.1

52.4

47.5

  Total regulated revenues

$ 2,889.2

$2,635.0

$2,310.0

$2,329.4

$2,283.7

$2,326.9

$1,948.6

Total unregulated revenues

$ 8,644.4

$2,281.6

$   879.4

$   247.0

$     85.8

$         .7

Other

$    139.6

$     22.6

$       8.9

Sales volumes -
gWh

Residential

14,454

14,062

13,562

12,939

12,832

13,328

11,755

Commercial

9,616

9,510

8,955

8,626

8,176

8,132

7,003

Industrial

19,884

20,320

19,846

19,675

19,040

18,568

16,430

Wholesale and street lighting

1,502

1,531

1,478

1,409

1,422

1,456

1,146

  Regular utility transactions

45,456

45,423

43,841

42,649

41,470

41,484

36,334

Bulk power

1,421

750

571

3,037

1,667

966

5,800

Transmission and other energy services

10,630

10,851

8,450

7,345g

12,367

17,402

13,962

  Total regulated transactions

57,507

57,024

52,862

53,031

55,504

59,852

56,096

Total unregulated transactions

114,507

41,707

15,854

8,278

3,734

109

Output and delivery -
gWh

Steam generation

46,101

46,773

44,776

44,323

43,463

40,067

42,307

Hydro and pumped-storage generation

2,158

1,969

1,648

1,326

1,171

1,348

1,654

Pumped-storage input

(2,600)

(2,327)

(1,963)

(1,498)

(1,298)

(1,405)

(1,907)

Purchased power

118,345

43,917

17,365

11,505

6,485

5,518

2,910

Transmission and other energy services

10,630

10,851

8,450

7,777

12,367

17,402

13,962

Combustion turbines

493

56

7

Losses and system uses

(3,189)

(3,075)

(3,066)

(2,124)

(2,950)

(2,969)

(2,830)

Total transactions as above

171,938h

98,164h

67,217h

61,309

59,238

59,961

56,096

Consolidated Statistics (continued)

D-4

Energy Supply

Generating capability - MW

  Regulated - owned

2,115

2,356

4,451

8,121

8,071

8,070

7,992

  Unregulated - owned

9,944

6,407

4,142

276

276

  Unregulated contracts(i)

479

479

299

299

299

299

162

Maximum hour peak - MW

8,265j

7,791j

7,788j

7,314j

7,423

7,500

6,238

Load factor regulated

66.3%k

70.2%k

70.5%k

69.1%k

68.3%

67.5%

71.7%

Heat rate - Btus per kWh

9,945l

9,919l

9,963

9,939

9,936

9,910

9,956

Fuel costs - cents per million Btus

125.59m

118.57m

119.61

128.92

130.05

129.22

143.19

a  Write-off in connection with deregulation proceedings in West Virginia, Virginia, Ohio, Maryland, and Pennsylvania and costs
    associated with the reacquisition of first mortgage bonds.
b  Reflects the adoption of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and
    Hedging Activities" on January 1, 2001.
c  Reflects a two-for-one common stock split, effective November 4, 1993.
d  Basic earnings per average share.
e  Excludes the extraordinary charge, net, and Pennsylvania restructuring activities in 1998; the extraordinary charge and other
     charges for merger-related costs; a long dormant pumped-storage generation project in 1999; the extraordinary charge in
     2000; and the cumulative effect of the accounting change in 2001. Includes the effect of internal restructuring in 1995 and
     1996.
f  Eliminations between regulated and unregulated are shown on page M-12.
g  Excludes 432 gWh delivered to customers participating in the Pennsylvania pilot program that are included in regulated utility
     transactions sales volumes.
h  Net of 76, 566, and 1,499 gWh eliminated between regulated and unregulated in 2001, 2000, and 1999, respectively.
i  Capability available through contractual arrangements with unregulated generators.
j  Peak coincident load of all customers provided delivery service within the Company's service territory irrespective of the
     generation service chosen by the customers therein.
k  Based on peak coincident load.
l  Includes the combustion turbines' heat rate.
m  Includes the combustion turbines' fuel costs.

Regulated Statistics

D-5

Year ended December 31

2001

2000

1999

1998

1997

1996

1991

Customers (thousands)(a)

Residential

1,507.1

1,495.1

1,250.6

1,236.9

1,224.9

1,213.7

1,146.6

Commercial

190.8

187.9

158.1

154.7

151.5

148.5

134.7

Industrial

26.5

26.3

25.9

25.5

25.2

25.0

23.1

Other

1.3

1.3

1.3

1.3

1.3

1.3

1.3

  Total customers

1,725.7

1,710.6

1,435.9

1,418.4

1,402.9

1,388.5

1,305.7

Average annual use (kWh per customer)(b)

Residential

11,200

10,993

10,913

10,486

10,521

11,042

10,316

All retail service

29,521

28,847

28,285

28,174

28,647

29,085

27,205

Average rate (cents per kWh)(b)

Residential

6.94

6.89

7.03

6.90

6.96

6.99

6.03

All retail service

5.34

5.30

5.45

5.32

5.36

5.46

4.80

a   Electric and gas customers in the Company's regulated franchised service territory receiving delivery service.

b   Use and rate statistics are calculated based on full-service customers (customers receiving both generation and delivery from the Company).

Dividends Paid - Range of Common Stock Prices Per Share

2001

2000

NYSE Composite Transactions

Dividend

High

Low

Close

Dividend

High

Low

Close

1^st Quarter

.43

$49.000

$39.500

$46.260

.43

$29.563

$23.625

$27.750

2^nd Quarter

43

55.900

44.700

48.250

43

31.750

26.688

27.563

3^rd Quarter

43

49.250

35.200

36.700

43

39.875

27.750

38.000

4^th Quarter

43

40.010

32.990

36.220

43

48.750

36.688

48.188

The high and low prices in 2002 were $36.190 and $31.890 through February 7, 2002. The last reported sale on that date was $33.370.

ALLEGHENY ENERGY, INC.

D-6

Quarterly Financial Information (Unaudited)

(Millions of dollars)

December
2001

September
2001

June
2001

March
2001*

December
2000**

September
2000

June
2000

March
2000***

Operating revenues

$2,055.1

$3,690.0

$2,940.4

$1,693.4

$1,221.3

$1,058.5

$865.3

$866.8

Operating Income

124.7

241.3

185.8

163.2

149.2

128.0

118.9

140.1

Consolidated income before extraordinary
  charge and cumulative effect of accounting
  change

64.6

165.7

115.8

102.8

79.7

76.1

71.5

86.4

Extraordinary charge, net

(6.5)

(70.5)

Cumulative effect of accounting change, net

(31.1)

Consolidated net income

64.6

165.7

115.8

71.7

73.2

76.1

71.5

15.9

Basic earnings per average share:****

Consolidated income before extraordinary
  charge and cumulative effect of accounting
  change

.50

1.33

.97

.93

.72

.69

.65

.78

Extraordinary charge, net

(.06)

(.64)

Cumulative effect of accounting change, net

(.27)

Consolidated net income

.50

1.33

.97

.66

.66

.69

.65

.14

*      Results for the first quarter of 2001 reflect charges for the adoption of Statement of Financial Accounting Standards No. 133,
         "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001.
**     Results for the fourth quarter of 2000 reflect charges for Ohio and Virginia restructuring.
***   Results for the first quarter of 2000 reflect charges for West Virginia restructuring.
****  Basic earnings per average share was calculated using the average common shares outstanding at the end of each respective quarter.

D-7

Allegheny Energy, Inc.

Investor Information

Dividend Declarations

Dividends are normally declared on the first Thursday of March, June, September, and December. Record dates are normally the second Monday after the dividend is declared, with payment dates the last business day of March, June, September, and December.

Dividend Reinvestment and Stock Purchase Plan

Our Dividend Reinvestment and Stock Purchase Plan provides shareholders with a convenient way to purchase additional shares of the Company's stock. Participants may at the time of each cash dividend payment on the stock have all or part of their dividends automatically invested in additional shares or invest any additional amount they wish between $50 and $10,000 in such shares or do both. The offering of shares under the Plan is made only by Prospectus. To get the Prospectus and an Authorization Form to enroll in the Plan, contact Mellon Investor Services, L.L.C., at 1-800-648-8389 or write to Gregory L. Fries, General Manager, Investor Relations, Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740-1766, or e-mail: investorinfo@alleghenyenergy.com.

Annual Meeting

The Annual Meeting of Shareholders will be held in the Basildon Room on the third floor of The Waldorf-Astoria, 301 Park Ave., New York, NY, on Thursday, May 9, 2002, at 9:30 a.m.

Form 10-K

The Company will provide without charge to each beneficial holder of its common stock, on the written request of
such person, a copy of Allegheny Energy's combined Annual Report to the Securities and Exchange Commission on
Form 10-K for 2001. Any such request should be directed to Cynthia A. Shoop, Vice President, Corporate
Communications, Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740-1766, or
investorinfo@alleghenyenergy.com.

Duplicate Mailings/Direct Deposit of Dividends

If you receive duplicate mailings of the Annual Report or wish to have your dividends deposited directly to your banking institution, please notify Mellon Investor Services, L.L.C., P.O. Box 3316, South Hackensack, NJ 07606. To speak to a representative responsible for Allegheny Energy shareholder accounts, call 1-800-648-8389.

Stock Transfer Agent and Registrar

Mellon Investor Services, L.L.C., Overpeck Centre, 85 Challenger Road, Ridgefield Park, NJ 07660. The internet address is www.mellon-investor.com.investor information

D-8

Monongahela Power Company
and Subsidiaries

QUARTERLY FINANCIAL INFORMATION

(Thousands of Dollars)

Quarter Ended

2001

2000

Mar

June

Sept

Dec

Mar

June

Sept

Dec


Operating revenues

$297,409

$207,955

$202,426

$229,933

$193,477

$176,734

$194,942

$262,894

Operating income

  41,556

  29,226

  30,050

  32,918

  32,718

  25,543

  37,633

  39,473

Consolidated net
  income (loss)

  30,089

  19,337

  18,032

  21,999

(33,809)

  17,275

  28,390

  19,599

SUMMARY OF OPERATIONS

Year ended December 31

(Thousands of Dollars)

2001

2000
*
1999

1998

1997

1996


Revenues

Electric retail revenues

  Residential

$232,807

$230,924

$210,757

$200,896

$199,931

$206,033

  Commercial

  144,035

  144,345

  130,052

  126,464

  118,825

  121,631

  Industrial

  214,979

  220,593

  217,792

  208,613

  196,716

  200,970

   Electric retail revenues

  591,821

  595,862

  558,601

  535,973

  515,472

  528,634

Other electric revenues

  Affiliated

   85,624

  101,975

   84,747

   77,314

   83,600

   74,825

  Wholesale and street lighting

    7,324

    7,468

    7,138

    7,656

    7,600

    7,513

  Other non-kWh

    4,982

    4,832

    4,299

    4,426

    4,379

    4,136

  Bulk power and

   Transmission services

   12,902

   14,330

   18,550

   19,753

   17,260

   17,363

    Total electric revenues

  702,653

  724,467

  673,335

  645,122

  628,311

  632,471

Gas retail revenues

  Residential

  139,109

   67,431

  Commercial

   79,748

   32,693

  Industrial

    4,083

      856

   Gas retail revenues

  222,940

  100,980

Other gas revenues

  Wholesale

    4,113

    1,601

  Gas transportation and other

    8,017

      999

    Total gas revenues

  235,070

  103,580









      Total revenues

  937,723

  828,047

  673,335

  645,122

  628,311

  632,471

Operation expense

  541,094

  444,696

  345,565

  313,795

  305,487

  310,480

Maintenance

   83,075

   70,850

   63,993

   67,033

   70,561

   74,735

Internal restructuring charges and

   Asset write-off

   24,299

Depreciation and amortization

   79,011

   72,704

   60,905

   58,610

   56,593

   55,490

Taxes other than income taxes

   63,815

   55,987

   43,395

   44,742

   38,776

   40,418

Federal and state income taxes

   36,978

   50,639

   40,440

   49,456

   47,519

   34,496

Allowance for funds used during

Construction

   (2,794)

     (902)

   (1,774)

   (1,043)

   (1,386)

     (672)

Interest charges

   54,830

   45,738

   34,603

   36,153

   38,730

   38,604

Other income, net

   (7,743)

   (6,244
)
   (6,119)

   (6,049)

   (8,498)

   (6,831
)

Consolidated income before

Extraordinary charge

   89,457

   94,579

   92,327

   82,425

   80,529

   61,452

Extraordinary charge, net (a)



  (63,124
)








Consolidated net income

$ 89,457

$ 31,455

$ 92,327

$ 82,425

$ 80,529

$ 61,452

Return on average common equity (b)

   12.13%

   14.43%

   15.29%

   13.62%

   13.99%

   11.00%

(a)Write-off in connection with Ohio and West Virginia deregulation proceedings.

(b)Excludes a charge for a long dormant pumped-storage generation project in 1999. Includes the effect of internal restructuring in 1996.

*Certain amounts have been reclassified for comparative purposes.

D-9

Monongahela Power Company
and Subsidiaries

CONSOLIDATED FINANCIAL AND OPERATING STATISTICS

2001

2000

1999

1998

1997

1996


PROPERTY, PLANT, AND EQUIPMENT

at Dec. 31 (Thousands):

  Gross

$2,490,741

$2,545,764

$2,173,603

$2,007,876

$1,950,478

$1,879,622

  Accumulated depreciation

(1,139,904
)
(1,152,953
)
(958,867
)
(883,915
)
(840,525
)
(790,649
)

   Net

$1,350,837

$1,392,811

$1,214,736

$1,123,961

$1,109,953

$1,088,973

GROSS ADDITIONS TO PROPERTY

  (Thousands):

$  104,931

$   82,243

$   82,483

$   72,795

$   78,139

$   72,577

TOTAL ASSETS
at Dec. 31

  (Thousands):

$2,025,347

$2,005,668

$1,626,406

$1,519,764

$1,497,756

$1,486,742

CAPITALIZATION
at Dec. 31

  (Thousands)

   Common stock

$  629,594

$ 707,899

$ 578,951

$ 570,188

$ 540,930

$  512,212

   Preferred stock

    74,000

    74,000

    74,000

    74,000

    74,000

    74,000

   Long-term debt and QUIDS

   784,261

606,734

503,741

453,917

455,088

474,841

$1,487,855

$1,388,633

$1,156,692

$1,098,105

$1,070,018

$1,061,053

  Ratios:

   Common stock

     42.3%

     51.0%

     50.0%

     51.9%

      50.6%

      48.3%

   Preferred stock

      5.0

      5.3

      6.4

      6.8

       6.9

       7.0

   Long-term debt and QUIDS

     52.7

43.7

43.6

41.3

42.5

44.7

    100.0%

    100.0%

    100.0%

    100.0%

     100.0%

     100.0%

GENERATING CAPABILITY-

  kw at Dec. 31:

   Company-owned

2,115,000

2,356,000

2,352,250

2,326,300

2,326,300

2,326,300

   Nonutility contracts (a)

   161,000

   161,000

   161,000

   161,000

   161,000

   161,000

KILOWATT-HOURS
(Thousands):

  Sales Volumes:

   Residential

3,190,702

3,148,565

2,884,144

2,757,067

2,764,630

2,815,414

   Commercial

2,449,275

2,439,764

2,148,361

2,102,604

1,987,147

2,007,116

   Industrial

5,846,404

5,975,983

5,736,718

5,510,925

5,224,364

5,024,257

   Wholesale and street

    Lighting

   155,834

   158,303

   152,476

   142,797

   142,827

   142,198

     Sales to retail

      Customers

11,642,215

11,722,615

10,921,699

10,513,393

10,118,968

9,988,985

   Affiliated

3,112,483

3,489,689

2,746,111

1,950,803

2,080,542

1,694,722

   Bulk power

     1,827

    29,966

   191,784

   301,656

   249,505

   196,843

   Transmission and other

    Energy services

2,611,737

2,698,380

2,138,247

1,932,160

3,007,439

4,218,150

     Total sales volumes

17,368,262

17,940,650

15,997,841

14,698,012

15,456,454

16,098,700

  Output and Delivery:

   Steam generation

11,249,555

12,723,425

12,146,537

11,251,721

10,936,469

10,678,491

   Pumped-storage generation

   492,339

   479,128

   372,658

   288,266

   241,958

   263,640

   Pumped-storage input

  (634,179)

  (612,800)

  (481,872)

  (370,822)

  (310,565)

  (337,451)

   Purchased power

4,316,258

3,358,567

2,562,752

2,283,055

2,294,059

2,040,136

   Transmission and other

    Energy services

2,611,737

2,698,380

2,138,247

1,932,160

3,007,439

4,218,150

   Losses and system uses

  (667,448
)
  (706,050
)
  (740,481
)
  (686,368
)
  (712,906
)
  (764,266
)

     Total transactions as

      Above

17,368,262

17,940,650

15,997,841

14,698,012

15,456,454

16,098,700

D-10

Monongahela Power Company
and Subsidiaries

CONSOLIDATED FINANCIAL AND OPERATING STATISTICS (continued)

CUSTOMERS
at Dec. 31:

  Residential

   548,416

   312,180

   309,760

   307,920

   305,579

   303,568

  Commercial

    66,049

    38,654

    37,929

    37,168

    36,323

    35,793

  Industrial

     8,045

     8,014

     7,992

     7,996

     8,019

     8,085

  Other

       182

       176

       218

       199

       182

       170

   Total customers

   622,692

   359,024

   355,899

   353,283

   350,103

   347,616

RESIDENTIAL SERVICE:

  Average use-kWh per

   customer

     9,447

     9,283

     8,938

     9,023

     9,256

     9,306

  Average revenue-dollars

   per customer

    689.32

    678.38

    651.29

    652.53

    677.37

    693.11

  Average rate-cents per

   kWh

      7.30

      7.31

      7.29

      7.23

      7.32

      7.45

(a) Capability available through contractual arrangements with nontuility generator

D-11

The Potomac Edison Company
and Subsidiaries

QUARTERLY FINANCIAL INFORMATION

(Thousands of Dollars)

Quarter Ended

2001

2000

Mar

June

Sept

Dec

Mar*

June

Sept

Dec*


Operating revenues

$235,621

$197,458

$221,682

$209,773

$214,734

$188,604

$206,699

$217,782

  Operating income

  28,085

  17,963

  24,121

   15,365

  40,231

  30,273

  24,465

  25,821

Income before extra-

  ordinary charge, net

  19,195

   9,105

  14,619

    5,116

  31,111

  20,047

  16,014

  17,213

Extraordinary charge,

  net

(12,278)

  (1,621)

Consolidated net income

  19,195

   9,105

  14,619

    5,116

  18,833

  20,047

  16,014

  15,592

*Results for the first and fourth quarters of 2000 reflect charges for West Virginia and Virginia restructuring.

SUMMARY OF OPERATIONS

Year ended December 31

(Thousands of Dollars)

2001

2000

1999

1998

1997

1996


Operating revenues

  Residential

  $346,128

$332,065

$330,299

$309,058

$299,876

$324,120

  Commercial

   165,480

  163,800

  168,469

  156,973

  148,287

  146,432

  Industrial

   220,039

  207,369

  212,205

  206,638

  198,174

  196,813

  Wholesale and street lighting

    31,496

   28,450

    5,821(a)

   27,667

   30,443

   32,907

    Revenues from regular customers

   763,143

  731,684

  716,794

  700,336

  676,780

  700,272

  Affiliated

    26,910

   45,190

   11,352

    9,401

    9,687

    2,399

  Other non-kWh

    10,105

    4,382

      539

    1,358

   (1,273)

     (405)

  Bulk power

    46,879

   28,851

    8,410

   11,690

   10,035

    7,577

  Transmission services

    17,497

   17,712

   16,162

   14,709

   13,552

   16,917

    Total

   864,534

  827,819

  753,257

  737,494

  708,781

  726,760

Operating expense

   658,673

  524,098

  396,153

  369,998

  359,350

  373,133

Maintenance

    29,762

   41,423

   57,257

   52,186

   56,815

   62,248

Internal restructuring charges and asset

  write-off

   26,094

Depreciation

    33,876

   61,394

   75,917

   74,344

   71,763

   71,254

Taxes other than income

    30,005

   46,892

   50,924

   49,567

   47,585

   45,809

Taxes on income

    26,684

   33,222

   37,284

   52,603

   44,496

   34,132

Allowance for funds used during

  construction

      (177)

   (1,300)

   (1,993)

   (1,576)

   (2,830)

   (2,491)

Interest charges

    35,372

   43,271

   44,902

   48,187

   49,823

   50,197

Other income, net

     2,304

   (5,566)

   (7,770)

   (9,297)

  (13,976)

  (11,791)

Income before extraordinary charge

    48,035

   84,385

  100,583

  101,482

   95,755

   78,175

Extraordinary, net(b)



  (13,899)

  (16,949)

________

________

________

Consolidated net income

  $ 48,035

$ 70,486

$ 83,634

$101,482

$ 95,755

$ 78,175

Return on average common equity (c)

    11.69%

   15.28%

   13.20%

   13.90%

   13.44%

   11.42%

(a) Includes reduction of $19,949 related to Maryland settlement.

(b) Write-off in connection with deregulation proceedings in Maryland in 1999, and deregulation proceedings in

    West Virginia and Virginia in 2000.

(c) Excludes the extraordinary charge, net and a charge for a long dormant pumped-storage generation project in

    1999.  Includes the effect of internal restructuring in 1996.

D-12

The Potomac Edison Company
and Subsidiaries

CONSOLIDATED FINANCIAL AND OPERATING STATISTICS

2001

2000

1999

1998

1997

1996


PROPERTY, PLANT, AND EQUIPMENT

At Dec. 31 (Thousands):

  Gross

$1,447,027

$1,410,381

$2,322,104

$2,249,716

$2,196,262

$2,124,956

  Accumulated depreciation

  (538,301
)
   (514,167)

   (998,710)

   (926,840)

   (859,076)

   (791,257)

    Net

$  908,726

$  896,214

$1,323,394

$1,322,876

$1,337,186

$1,333,699

GROSS ADDITIONS TO PROPERTY

(Thousands):

$   54,828

$   72,265

$   91,622

$   60,525

$   78,298

$   86,256

TOTAL ASSETS
at Dec. 31

(Thousands):

$1,111,788

$1,098,963

$1,613,595

$1,728,619

$1,688,482

$1,696,904

CAPITALIZATION
at Dec. 31

(Thousands)

  Common stock

$  383,257

$  412,754

$  700,422

$  762,912

$  689,781

$  678,116

  Preferred stock

     16,378

     16,378

     16,378

  Long-term debt and QUIDS

   415,797

    410,010

    510,344

    578,817

    627,012

    628,431

$  799,054

$  822,764

$1,210,766

$1,358,107

$1,333,171

$1,322,925

Ratios:

Common stock

     48.0%

      50.2%

      57.8%

      56.2%

      51.8%

      51.3%

Preferred stock

       1.2

       1.2

       1.2

Long-term debt and QUIDS

     52.0

      49.8

      42.2

      42.6

       47.0

      47.5

    100.0

     100.0%

     100.0%

     100.0%

      100.0%

     100.0%

GENERATING CAPABILITY-

kw at Dec. 31:

   Company owned

      3,000

  2,099,120

  2,073,292

  2,073,292

  2,072,292

   Non utility contract (a)

   180,000

    180,000

KILOWATT-HOURS
(Thousands):

Sales Volumes:

   Residential

4,962,838

  4,851,357

  4,643,621

  4,401,238

  4,290,117

  4,599,758

   Commercial

2,839,843

  2,791,704

  2,667,928

  2,498,546

  2,331,789

  2,288,229

   Industrial

6,145,012

  5,962,258

  5,841,102

  5,922,274

  5,593,722

  5,567,088

   Wholesale and street lighting

   713,596

    699,821

    683,691

    657,357

    666,383

    724,011

     Sales to regular customers

14,661,289

14,305,140

13,836,342

13,479,415

12,882,011

13,179,086

   Affiliated

1,820,213

  2,491,265

    894,094

    498,069

    591,876

     47,781

   Bulk power

1,416,257

    708,518

    233,189

    402,635

    369,732

    315,808

   Transmission and other

     energy services

3,441,738

  3,475,567

  2,789,957

  2,470,365

  4,044,837

  5,617,912

       Total sales volumes

21,339,497

20,980,490

17,753,582

16,850,484

17,888,456

19,160,587

Output and Delivery:

   Steam generation

2,501,489

  7,974,419

11,483,502

11,254,505

11,002,533

10,762,678

   Hydro and pumped-storage generation

     8,218

    309,093

    413,206

    416,983

    370,026

    401,998

   Pumped-storage input

   (357,143)

   (499,497)

   (486,823)

   (426,087)

   (455,142)

   Purchased power

16,230,470

10,309,506

  4,493,128

  4,190,098

  3,934,815

  3,639,519

   Transmission services

3,441,738

  3,606,710

  2,789,957

  2,470,365

  4,044,837

  5,617,912

   Losses and system uses

  (842,418
)
   (862,095)

   (926,714)

   (994,644)

(1,037,668)

   (806,378)

     Total transactions as above

21,339,497

20,980,490

17,753,582

16,850,484

17,888,456

19,160,587

D-13

The Potomac Edison Company

and Subsidiaries

CONSOLIDATED FINANCIAL AND OPERATING STATISTICS (continued)

2001

2000

1999

1998

1997

1996


CUSTOMERS
at Dec. 31:

Residential

   361,661

    353,721

    346,821

    339,584

    333,224

    327,344

Commercial

    48,592

     47,336

     45,968

     44,828

     43,794

     42,670

Industrial

     5,587

      5,382

      5,235

      5,122

      5,010

      4,887

Other

       640

        632

        620

        641

        598

        571

   Total customers

   416,480

    407,071

    398,644

    390,175

    382,626

    375,472

RESIDENTIAL SERVICE
:

Average use-kWh per customer

    13,887

     13,861

     13,523

     13,093

     13,003

     14,179

Average revenue-dollars per customer

    968.55

     948.77

     961.92

     919.42

     908.87

     999.10

Average rate-cents per kWh

      6.97

       6.84

       7.11

       7.02

       6.99

       7.05

(a) Capability available through contract arrangements with non-utility generators.

D-14

West Penn Power Company
and Subsidiaries

QUARTERLY FINANCIAL INFORMATION

(Thousands of Dollars)

Quarter Ended

2001

2000

Mar

June

Sept

Dec

Mar

June

Sept

Dec


Operating revenues

$292,826

$268,331

$272,801

$280,546

$257,544

$250,563

$266,528

$270,992

Operating income

  45,469

  38,658

  37,335

  37,322

  36,047

  44,377

  42,919

  40,973

Consolidated net

  Income

  33,083

  26,019

  25,446

  25,297

  20,053

  33,589

  29,972

  18,789

SUMMARY OF OPERATIONS

Year ended December 31

(Thousands of Dollars)

2001

2000

1999

1998

1997

1996


Operating revenues

$1,114,504

$1,045,627

$1,354,203

$1,078,727

$1,082,162

$1,089,124

Operation expense

   737,768

   684,132

    800,438

    552,514

    524,051

    531,522

Maintenance

    39,976

    37,305

     93,436

     91,724

     98,252

    104,211

Internal restructuring charges

  and asset write-offs

     53,343

Depreciation and amortization

    69,328

    62,379

    114,268

    114,709

    113,793

    119,066

Taxes other than income taxes

    55,279

    45,402

     80,719

     88,722

     90,140

     90,132

Federal and state income taxes

    53,369

    52,093

     71,573

     64,526

     73,279

     47,455

Allowance for funds used

  during construction

    (1,048)

      (744)

     (2,933)

     (2,403)

     (4,085)

     (2,723)

Interest charges

    51,541

    66,919

     68,723

     67,640

     69,629

     71,072

Other income, net

    (1,554)

    (4,262
)
     (9,621)

    (11,325)

    (17,562)

    (13,439)

Consolidated income before extra-

  ordinary charge

   109,845

   102,403

    137,600

    112,620

    134,665

     88,485

Extraordinary charge, net (a)





    (10,018)

   (275,426)

                _



Consolidated net income (loss)

$  109,845

$  102,403

$  127,582

$ (162,806)

$  134,665

$   88,485

Return on average common equity (b)

     26.89%

     66.98%

      20.97%

      13.12%

      13.70%

       8.72%

(a)   Loss on reacquired debt in 1999 and write-off in connection with Pennsylvania deregulation proceedings in 1998.

(b)   Excludes the extraordinary charge, net and Pennsylvania restructuring activities in 1998, and the extraordinary charge,
      net and a long dormant pumped-storage generation project in 1999. Includes the effect of internal restructuring in 1996.

D-15

West Penn Power Company
and Subsidiaries

FINANCIAL AND OPERATING STATISTICS

2001

2000

1999

1998

1997

1996


PROPERTY DATA at Dec. 31


(Thousands):

    Gross property

$1,713,390

$1,654,283

$1,597,484

$3,365,784

$3,293,039

$3,182,208

    Accumulated depreciation

  (585,417
)
  (543,000
)
   (506,416)

(1,362,413)

(1,254,900)

(1,152,383)

      Net property

$1,127,973

$1,111,283

$1,091,068

$2,003,371

$2,038,139

$2,029,825

Gross additions during year:

  Regulated operations

$   71,066

$   53,097

$   86,290

$   95,975

$  128,054

$  130,606

  Unregulated generation

$   27,956

TOTAL ASSETS
at Dec. 31


(Thousands)
$1,777,086

$1,792,547

$1,852,686

$2,887,706

$2,777,375

$2,724,367

CAPITALIZATION
at Dec 31

(Thousands):

  Common stock, other paid-in

    capital, and retained earnings

$  423,313

$  422,121

$   79,658

$  732,161

$  997,027

$  962,752

  Preferred stock

     79,708

     79,708

     79,708

  Long-term debt and QUIDS

   574,647

   678,284

    966,026

    837,725

    802,319

    905,243

$  997,960

$1,100,405

$1,045,684

$1,649,594

$1,879,054

$1,947,703

  Ratios:

    Common stock

      42.4%

      38.4%

        7.6%

       44.4%

       53.1%

       49.4%

    Preferred stock

        4.8

        4.2

        4.1

    Long-term debt and QUIDS

      57.6

      61.6

       92.4

       50.8

       42.7

       46.5

     100.0%

     100.0%

      100.0%

      100.0%

      100.0%

      100.0%

GENERATING CAPABILITY

  KW at Dec. 31:

    Company-owned

  3,721,408

  3,671,408

  3,671,408

    Nonutility contracts (a)

   138,000

   138,000

    138,000

    138,000

    138,000

    138,000

REVENUES (b)

  Residential

$  423,258

$  404,192

$  389,273

$  370,636

$  393,036

$  402,083

  Commercial

   244,441

   221,038

    201,728

    217,954

    223,347

    224,663

  Industrial

   337,266

   323,357

    290,491

    338,254

    352,730

    355,120

  Wholesale and street lighting

    27,775

    28,933

     27,425

     33,650

     27,051

     26,194

    Revenues from regular

      utility customers

1,032,740

   977,520

    908,917

    960,494

    996,164

  1,008,060

  Affiliated

    50,609

    47,052

     33,987

     45,180

     39,031

     44,231

  Other non-kWh

     7,735

    (3,528)

      6,468

      4,152

      6,377

      3,903

  Bulk power

       262

       403

      7,549

     49,605

     22,188

     10,012

  Transmission services

    23,158

    24,180

     20,300

     19,296

     18,402

     22,918

    Total regulated operations

      revenues

$1,114,504

$1,045,627

$  977,221

$1,078,727

$1,082,162

$1,089,124

  Total unregulated generation

      revenues

$  681,637

D-16

West Penn Power Company
and Subsidiaries

FINANCIAL AND OPERATING STATISTICS (continued)

2001

2000

1999

1998

1997

1996


KILOWATT-HOURS
(Thousands):

  Sales Volumes:

    Residential

  6,299,925

  6,061,759

  6,028,420

  5,778,155

  5,756,594

  5,913,412

    Commercial

  4,326,686

  4,278,514

  3,903,446

  4,023,523

  3,833,178

  3,835,831

    Industrial

  7,892,677

  8,381,329

  7,222,636

  8,237,627

  8,046,166

  7,974,265

    Wholesale and street lighting

    632,717

    673,015

    641,605

    617,841

    611,105

    591,122

      Sales to regular customers

19,152,005

19,394,617

17,796,107

18,657,146

18,247,043

18,314,630

    Affiliated

  2,455,118

  2,526,407

  1,295,975

  1,974,497

  1,789,476

  1,068,712

    Bulk power

      3,393

     11,046

    145,717

  2,332,825

  1,046,905

    453,028

    Transmission services

  4,576,169

  4,677,501

  3,522,145

  2,942,868(c)

  5,392,916

  7,567,153

      Total regulated operations

        sales volumes

26,186,685

26,609,571

22,759,944

25,907,336

26,476,340

27,403,523

    Total unregulated generation

      sales volumes

  9,970,100

Output and Delivery:

  Steam generation

     15,231

17,593,971

20,053,422

19,523,537

18,578,677

  Hydro and pumped-storage
    Generation

         82

    774,505

    620,496

    559,241

    682,747

  Pumped-storage input

         (3)

   (878,237)

   (640,242)

   (561,135)

   (612,877)

  Purchased power

22,678,418

22,992,742

12,979,203

  2,890,986

  2,968,258

  2,583,166

  Transmission services

  4,576,169

  4,677,501

  3,522,145

  3,850,394

  5,392,916

  7,567,153

  Losses and system uses

(1,067,902)

(1,075,982)

(1,261,543)

   (867,720)

(1,406,477)

(1,395,343)

    Total transactions as above

26,186,685

26,609,571

32,730,044

25,907,336

26,476,340

27,403,523

CUSTOMERS
at Dec. 31 (d):

  Residential

    595,497

    594,766

    591,665

    587,503

    583,745

    580,816

  Commercial

     75,497

     75,035

     73,480

     71,920

     70,559

     69,457

  Industrial

     12,896

     12,826

     12,615

     12,389

     12,142

     12,051

  Other

        557

        559

        570

        608

        629

        607

    Total customers

    684,447

    683,186

    678,330

    672,420

    667,075

    662,931

RESIDENTIAL SERVICE
(e):

  Average use-

    kWh per customer

    10,579

    10,210

    10,239

      9,775

      9,903

     10,223

  Average revenue-

    dollars per customer

    711.82

    683.90

    698.73

     644.98

     674.73

     695.08

  Average rate-

    cents per kWh

      6.73

      6.70

      6.82

       6.60

       6.81

       6.80

(a)   Capability available through contractual arrangements with nonutility generators.
(b)   Eliminations between regulated operations and unregulated generation are shown on page F-95.
(c)   Excludes 907,526 kWh (in thousands) delivered to customers participating in the Pennsylvania pilot program that are included in regular customer sales volumes.
(d)   Customers in the Company's service territory receiving delivery service.
(e)   Use, revenue, and rate statistics are calculated based on full service customers (customers receiving both generation and delivery from the Company).

D-17

QUARTERLY FINANCIAL INFORMATION

Allegheny Generating Company

(Thousands of Dollars)

Quarter Ended

2001

2000

Dec

Sept

June

March


Dec

Sept

June

March


Operating revenues

$18,563

$15,451

$16,738

$17,772

$18,256

$17,257

$17,359

$17,155

Operating income

  8,998

  7,132

  7,848

  8,797

  8,535

  9,032

  8,939

  8,583

Net income

  6,105

  4,012

  4,673

  5,510

  5,095

  5,914

  5,593

  5,278

SUMMARY OF OPERATIONS

Year ended December 31

   (Thousands of Dollars)

2001

2000

1999

1998

1997

1996

Operating revenues

$ 68,524

$ 70,027

$ 70,592

$ 73,816

$ 76,458

$ 83,402

  Operation and maintenance expense

   5,139

   5,652

   5,023

   4,592

   4,877

   5,165

  Depreciation

  16,973

  16,963

  16,980

  16,949

  17,000

  17,160

  Taxes other than income taxes

   3,437

   4,963

   4,510

   4,662

   4,835

   4,801

  Federal income taxes

  10,200

   7,360

   9,997

  10,959

  11,213

  13,297

  Interest charges

  12,479

  13,494

  13,261

  13,987

  15,391

  16,193

  Other income, net

      (4
)
    (285
)
    (394
)
     (86
)
  (9,126
)
      (3
)

  Net Income

$ 20,300

$ 21,880

$ 21,215

$ 22,753

$ 32,268

$ 26,789

Return on average common equity

  14.37%

  14.37%

  13.08%

  12.57%

  15.98%

  12.58%

FINANCIAL AND OPERATING STATISTICS

PROPERTY, PLANT, AND EQUIPMENT

at Dec. 31 (Thousands):

   Gross

$832,077

$829,872

$828,894

$828,806

$828,658*

$837,050

   Accumulated depreciation

(261,111
)
(244,138
)
(227,177
)
(210,198
)
(193,173
)
(176,178
)

   Net

$570,966

$585,734

$601,717

$618,608

$635,485

$660,872

GROSS ADDITIONS TO PROPERTY

  (Thousands)

$  2,205

$    978

$     85

$     69

$    444

$    178

TOTAL ASSETS

at Dec. 31 (Thousands)

$591,632

$602,045

$620,881

$639,458

$663,920

$692,408

CAPITALIZATION AND SHORT-TERM DEBT

At Dec. 31: (Thousands):

   Common stock

$132,670

$144,371

$154,491

$165,276

$199,523

$202,955

   Long-term and short-term debt

212,009

202,295

201,081

215,579

208,735

239,234

$344,679

$346,666

$355,572

$380,855

$408,258

$442,189

Ratios:

   Common stock

   38.5%

   41.6%

   43.4%

   43.4%

   48.9%

   45.9%

   Long-term and short-term debt

   61.5

   58.4

   56.6

   56.6

   51.1

   54.1

  100.0%

  100.0%

  100.0%

  100.0%

  100.0%

  100.0%

KILOWATT-HOURS (Thousands):

  Pumping energy supplied by Parents

2,600,313

2,326,923

1,962,534

1,497,887

1,297,787

1,405,470

  Pumped-storage generation

2,018,515

1,822,568

1,526,824

1,164,325

1,011,366

1,098,278

*Reflects a related settlement of $8.8 million in 1997 that was recorded as a reduction to plant.

D-18

Allegheny Energy Supply Company, LLC
and Subsidiaries

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarter Ended

Operating
Revenues

Cost of Fuel,
Purchased
Energy, and
Transmission, and Operating
Expenses

Operating
Income
Consolidated
Income Before
Income Taxes,
Minority Interest,
and Cumulative
Effect of
Accounting Change

Cumulative
Effect of
Accounting
Change
Consolidated
Net Income

(Thousands of dollars)

March 2000

$  376,020

$  343,947

$ 32,073

$ 27,571

$ 18,155

June 2000

410,350

394,796

15,554

12,104

9,949

September 2000*

689,229

657,114

32,115

23,042

14,759

December 2000*

783,973

719,722

64,251

51,360

32,625

March 2001**

1,203,808

1,126,840

76,968

67,223

$(31,147)

10,673

June 2001

2,556,966

2,417,609

139,357

112,197

71,744

September 2001

3,312,206

3,095,520

216,686

184,481

117,647

December 2001

1,538,575

1,508,717

29,858

936

3,624

*   Includes earnings associated with assets transferred on August 1, 2000, from Potomac Edison.

**  Results for the first quarter of 2001 reflect charges for the adoption of Statement of Financial Accounting

      Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities' on January 1, 2001.

73

ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
                    CONDITION AND RESULTS OF OPERATIONS______________

Page No.

AE

Monongahela

Potomac Edison

West Penn

AGC

AE Supply

M- 1

M-34

M-53

M-70

M-88

M-99

The information required by this Item was furnished in the copy of the Form 10-K filed with the Securities and Exchange Commission. You may obtain a complete copy of Form 10-K upon making a written or an oral request directed to: Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740, Attention: Marleen L. Brooks, Secretary (tel. 301-790-3400).

ALLEGHENY ENERGY, INC.

MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

FACTORS THAT MAY AFFECT FUTURE RESULTS

Certain statements within constitute forward-looking statements with respect to Allegheny Energy, Inc. and its subsidiaries (collectively, the Company). Such forward-looking statements include statements with respect to deregulated activities and movements toward competition in the states served by the Company; markets; products; services; prices; capacity purchase commitments; results of operations; capital expenditures; regulatory matters; liquidity and capital resources; the effect of litigation; and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results of the Company will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

Factors that could cause actual results of the Company to differ materially include, among others, the following: general economic and business conditions, including the continuing effects of the September 11, 2001, terrorists' attacks; changes in industry capacity, development, and other activities by the Company's competitors; changes in the weather and other natural phenomena; changes in technology; changes in the price of power and fuel for electric generation; changes in the underlying inputs and assumptions used to estimate the fair values of commodity contracts; changes in laws and regulations applicable to the Company, its markets, or its activities; litigation involving the Company; environmental regulations; the loss of any significant customers and suppliers; the effect of accounting policies issued periodically by accounting standard-setting bodies; and changes in business strategy, operations, or development plans.

OVERVIEW

The Company is a diversified utility holding company, which has experienced significant changes in its business as a result of the deregulation of electric generation in states where its subsidiaries operate. As deregulation of electric generation has been implemented, the Company's subsidiaries have transferred their generating assets, excluding Monongahela Power Company's (Monongahela Power) West Virginia jurisdictional generating assets, from their regulated utility businesses to an affiliated, unregulated generation business in accordance with approved deregulation plans.

As a result of the deregulation activities, the Company has aligned its businesses into three principal business segments. The unregulated generation operations segment consists primarily of the Company's subsidiary, Allegheny Energy Supply Company, LLC (Allegheny Energy Supply). Allegheny Energy Supply is an unregulated energy supply company that develops, owns, operates, and controls electric generating capacity and supplies and trades energy and energy-related commodities in selected domestic retail and wholesale markets. Allegheny Energy Supply manages the Company's generating assets as an integral part of its wholesale marketing, energy trading, fuel procurement, and risk management activities.

The regulated utility operations segment consists primarily of the Company's subsidiaries - Monongahela Power, including its subsidiary, Mountaineer Gas Company (Mountaineer Gas); The Potomac Edison Company (Potomac Edison); and West Penn Power Company (West Penn). The regulated utility operations segment operates electric and natural gas transmission and distribution (T&D) systems. It also generates electric energy for its West Virginia jurisdiction, where deregulation of electric generation has not been implemented.

The other unregulated operations segment consists of Allegheny Ventures, Inc. (Allegheny Ventures), an unregulated subsidiary, which invests in and develops fiber and data services and energy-related projects and provides energy consulting and management services and natural gas and other energy-related services.

On July 23, 2001, the Company filed a U-1 application with the Securities and Exchange Commission (SEC), seeking authorization under the Public Utility Holding Company Act of 1935 (PUHCA) to effect an initial public offering (IPO) of up to 18 percent of the common stock in a new holding company, which would own 100 percent of Allegheny Energy Supply, and then distribute the remaining common stock owned by the Company to its shareholders on a tax-free basis. In October 2001, the Company announced that the proposed IPO would be delayed due to market and other conditions. In January 2002, the Company announced that it would not proceed with the IPO. In February 2002, the Company filed an amendment to the U-1 application filed on July 23, 2001, with the SEC, withdrawing its IPO application.

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The Company's three business segments have experienced several significant events during the 1999 through 2001 period. Following is a summary of certain significant events by business segment for this period:

Unregulated generation operations:

-      The transfer of a significant portion of the Company's generating assets from the regulated utility operations
       segment to the unregulated generation operations segment. (See "Transfer of Generating Assets" below for
       additional details.)

-      The completion or announcement of the development or acquisition of generating assets and generating
       capacity. (See "Development and Acquisition of Generating Assets and Generating Capacity" starting on
       page M-4 for additional details.)

-     The acquisition of an energy commodity marketing, trading, and risk management business. (See "Global
      Energy Markets Acquisition" on page M-5 for additional details.)

-     The execution of several long-term power sales agreements. (See "Long-Term Power Sales Agreements"
       starting on page M-5 for additional details.)

Regulated utility operations:

-     The electric deregulation process and the acquisition of two energy distribution businesses, resulting in
      several rate-making proceedings with the respective state public utility commissions. (See "Rate Matters"
      starting on page M-6 for additional details.)

Other unregulated operations:

-     The acquisition of a natural gas and electricity consulting and management services company and a natural
      gas supply and transportation services company. (See "Allegheny Ventures' Acquisitions" on page M-9 for
      additional details.)

The Company also experienced several significant events that could not be associated with one particular segment. See "Other Events" on page M-10 for additional details regarding these significant events.

SIGNIFICANT EVENTS IN 2001, 2000, AND 1999

UNREGULATED GENERATION

Transfer, Development, and Acquisition of Generating Assets and Generating Capacity
The table below summarizes the Company's electric generating capacity, which was in operation on December 31, 2001, including generating capacity purchased through contractual obligations of which the Company does not exercise 100 percent control, along with announced construction and development, contractual control, and planned expansions:

Capacity in Megawatts

In operation:

  Unregulated generation

               9,944

  Regulated utility

               2,115

Announced construction and development, contractual control, and planned expansions:

  Unregulated generation

               2,643

Total

             14,702

The preceding table does not include purchases of generating capacity from qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) representing approximately 479 megawatts (MW). These power purchases are either used by the Company's regulated utility subsidiaries to fulfill their service obligations or are sold by the Company's regulated utility subsidiaries into the wholesale market.

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ALLEGHENY ENERGY, INC.

The unregulated generation operations segment, as part of its generating asset and energy commodity portfolio, manages the interface between the Company's electric generating capacity and various customers or markets. In early 2000, dispatch arrangements were put in place between regulated utility operations and unregulated generation operations. With these arrangements, regulated utility operations sells the amount of its bulk power that exceeds its regulated load to Allegheny Energy Supply and conversely buys generation from unregulated generation operations when regulated load exceeds regulated utility operations' bulk power. Such a relationship allows all of the Company's generation to be dispatched in a more efficient manner.

The two sections that follow provide the details regarding the generating asset transfers from regulated utility operations to unregulated generation operations and the acquisition and development of generating assets and capacity by unregulated generation operations.

Transfer of Generating Assets
On June 1, 2001, Monongahela Power transferred its 352 MW of Ohio and Federal Energy Regulatory Commission (FERC) jurisdictional generating assets to Allegheny Energy Supply at net book value. On August 1, 2000, Potomac Edison transferred approximately 2,100 MW of its Maryland, Virginia, and West Virginia jurisdictional generating assets to Allegheny Energy Supply at net book value. Potomac Edison's five MW of Virginia hydroelectric assets will be transferred to Allegheny Energy Supply in 2002. During the fourth quarter of 1999, West Penn transferred its jurisdictional generating assets, which totaled 3,778 MW, to Allegheny Energy Supply at net book value. The relevant state commissions, the FERC, and the SEC approved these transfers. The generating asset transfers from Monongahela Power, West Penn, and Potomac Edison included their 77.03-percent ownership interest in Allegheny Generating Company (AGC). In addition, West Penn and Potomac Edison also transferred their entitlement to 202 MW of capacity in the Ohio Valley Electric Corporation (OVEC).

Under the terms of the deregulation plans approved in Pennsylvania for West Penn, in Maryland for Potomac Edison, and in Ohio for Monongahela Power, these companies retain the obligation to provide electricity to customers who do not choose an alternate electricity supplier during a transition period. For West Penn's customers, the Pennsylvania transition period continues through December 31, 2008. For residential customers of Potomac Edison in Maryland, the transition period continues through December 31, 2008. For commercial and industrial customers of Potomac Edison in Maryland, the transition period continues through December 31, 2004. For Monongahela Power, the transition period for Ohio residential and small commercial customers continues through December 31, 2005, and, for all other Ohio customers, through December 31, 2003. The default service obligation for Potomac Edison in Virginia may be eliminated after July 1, 2004, if the Virginia State Corporation Commission (Virginia SCC) determines there is sufficient competition. In any event, after termination of capped rates, the rates for default service in Virginia will be based upon competitive market prices for generation services.

Pursuant to contracts, Allegheny Energy Supply provides West Penn, Potomac Edison, and Monongahela Power with energy during the Pennsylvania, Maryland, and Ohio transition periods, respectively. Allegheny Energy Supply also provides energy and capacity to serve retail load in Potomac Edison's West Virginia service territory, pursuant to a facilities lease and power supply agreement. The facilities lease covers the first 425 MW of retail load in the territory, with the power supply agreement covering deliveries over 425 MW. The facilities lease term is annual, with automatic renewal provisions. The term of the power supply agreement is the later of December 31, 2010, or 10 years after the implementation of retail electric competition in West Virginia. Allegheny Energy Supply provides energy pursuant to a contract to cover the retail load of Potomac Edison in Virginia during a capped rate period that ends on July 1, 2007, unless the Virginia SCC reduces this time period. Under these contracts, Allegheny Energy Supply provides these regulated electric distribution affiliates with the amount of electricity, up to their retail load, that they may require. These contracts currently represent a significant portion of the normal operating capacity of Allegheny Energy Supply's fleet of transferred generating assets. Allegheny Energy Supply may need to absorb changes in fuel prices and increased costs of environmental compliance, since the price of energy supplied to the regulated electric distribution affiliates may not correspond to higher company-specific costs.

In March 2000, the West Virginia Legislature passed House Resolution 27 approving an electric deregulation plan submitted by the Public Service Commission of West Virginia (West Virginia PSC), with certain modifications. Under the resolution, the implementation of the West Virginia deregulation plan cannot occur until the Legislature enacts certain tax changes regarding the preservation of tax revenues for state and local governments and other changes conforming to the plan and authorizing implementation. The plan provides for all customers to have choice of an electric generation supplier and allows Monongahela Power to transfer the West Virginia portion (approximately 2,037 MW of owned capacity and 78 MW of capacity from generating units over which the Company does not exercise 100-percent control) of its generating assets to Allegheny Energy Supply at net book value. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may

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ALLEGHENY ENERGY, INC.

reconsider the deregulation plan in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

On June 23, 2000, the West Virginia PSC issued an order regarding the transfer of the generating assets of Monongahela Power. The June 23, 2000, order permits Monongahela Power to submit a petition to the West Virginia PSC, seeking approval to transfer its West Virginia jurisdictional generating assets prior to the implementation of the deregulation plan. A filing before implementation of the deregulation plan is required to include commitments to the consumer and other protections contained in the deregulation plan. On August 15, 2000, with a supplemental filing on October 31, 2000, Monongahela Power filed a petition, seeking West Virginia PSC approval to transfer its West Virginia jurisdictional generating assets to Allegheny Energy Supply. Settlement discussions regarding the generating asset transfer are ongoing.

See Notes B and C to the consolidated financial statements for details of the Company's various state restructurings and other information about the electric generation deregulation process.

Development and Acquisition of Generating Assets and Generating Capacity
In 2001 and 2000, Allegheny Energy Supply completed construction of and placed into operation 88 MW of natural gas-fired merchant generating capacity in both Guilford Township and Gans, Pennsylvania. These facilities each consist of two 44-MW natural gas-fired combustion turbines that operate primarily at times of peak electrical demand - typically during the hottest and coldest days of the year.

On November 20, 2001, the Company announced that Allegheny Energy Supply plans to develop a 79-MW, barge-mounted, natural gas-fired combustion turbine generating facility that will be located in the Brooklyn Naval Yard. Estimated development costs for the project are $67 million.

On June 7, 2001, the Company announced that it plans to enter into a joint project with CONSOL Energy, Inc. to construct an 88-MW generating facility in southwest Virginia. Under the terms of the joint project, each company will have a 50-percent interest, or 44 MW, in two simple-cycle combustion turbines that will be fueled by coal-bed methane produced by CONSOL Energy's CNX Gas Operations. Allegheny Energy Supply will operate the facility, and its output will be sold into the competitive marketplace. Certification proceedings have been initiated with the Virginia Department of Environmental Quality and the Virginia SCC. The facility is expected to be in operation by mid-2002.

On May 11, 2001, the Company announced that Allegheny Energy Supply had signed a 15-year, agreement for 222 MW of generating capacity in Las Vegas, Nevada. This agreement gives Allegheny Energy Supply contractual control of a 222-MW, natural gas-fired combined-cycle generating facility beginning in the third quarter of 2002. The Company records this contract at its fair value on the consolidated balance sheet, with changes in fair value recorded as a component of unregulated generation revenues on the consolidated statement of operations.

On May 3, 2001, Allegheny Energy Supply completed the acquisition of three natural gas-fired generating facilities with a total capacity of 1,710 MW in Illinois, Indiana, and Tennessee (Midwest). The $1.1-billion purchase was financed with short-term debt of $550 million and a portion of the proceeds from the Company's common stock offering in May 2001. See Note E to the consolidated financial statements for additional details regarding the acquisition of these generating assets.

On March 16, 2001, Allegheny Energy Supply acquired Global Energy Markets, the energy commodity marketing and trading business of Merrill Lynch Capital Services, Inc. (Merrill Lynch). As part of this acquisition, Allegheny Energy Supply obtained the long-term contractual right to call up to 1,000 MW of natural gas-fired generating capacity at three generating stations in southern California, with capacity totaling approximately 4,000 MW. In this transaction, Allegheny Energy Supply acquired the contractual rights through May 2018 to call up to 25 percent of the total available generating capacity of the three stations at a price based on an indexed gas price and a heat rate that varies with the amount of capacity available. See "Global Energy Markets Acquisition" below and Note E to the consolidated financial statements for a detailed discussion of this acquisition and Note I to the consolidated financial statements for additional information regarding the contractual right to call up to 1,000 MW.

On January 5, 2001, the Company announced that Allegheny Energy Supply plans to construct a 630-MW, natural gas-fired merchant generating facility in St. Joseph County, Indiana, approximately 10 miles west of South Bend, Indiana. A combined-cycle facility with 542 MW of capacity will be completed in 2005. Two 44-MW, simple-cycle combustion turbines will be constructed as market conditions warrant. See "Operating Lease Transactions" on page M-24 for information concerning the operating lease transaction for this facility.

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ALLEGHENY ENERGY, INC.

The Company and a subsidiary of PPL Corporation in January 2001 finalized a successful co-bid to purchase Potomac Electric Power Company's 9.72-percent share in the 1,711-MW Conemaugh Generating Station. Each company acquired 83 MW. The purchase enhanced the Company's presence in the Pennsylvania - New Jersey - Maryland Interconnection, L.L.C. (PJM) power market.

In October 2000, the Company announced that Allegheny Energy Supply plans to construct a 1,080-MW, natural gas-fired generating facility in La Paz County, Arizona, approximately 75 miles west of Phoenix. Construction is currently expected to begin on the combined-cycle facility in 2002. When completed in 2005, the facility will allow Allegheny Energy Supply to sell generation into Arizona and other states, including all or parts of California, Colorado, Montana, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming.

In September 2000, Allegheny Energy Supply announced that Allegheny Energy Supply Hunlock Creek, LLC (Allegheny Energy Supply Hunlock Creek), a wholly owned subsidiary of the Company, along with partner UGI Development, a subsidiary of UGI Corporation (UGI), will market generating output from facilities at UGI's Hunlock Creek generating station near Wilkes-Barre, Pennsylvania. In addition to sharing 48 MW of existing coal-fired generation at Hunlock Creek, Allegheny Energy Supply Hunlock Creek installed a 44-MW, natural gas-fired combustion turbine on property owned by UGI in the fourth quarter of 2000. The two companies jointly share in the combined output of the coal-fired and combustion turbine generating units. UGI operates the facilities. These additions gave Allegheny Energy Supply access to 46 MW of generating capacity to sell into the PJM market. In 2002, the Company will transfer its ownership in Allegheny Energy Supply Hunlock Creek to Allegheny Energy Supply.

In January 2000, the Company announced the construction of a 540-MW, combined-cycle generating facility at Springdale, Pennsylvania. The new facility will include two natural gas-fired combustion turbines and a steam turbine. The facility is expected to be operational in 2003. See "Operating Lease Transactions" on page M-24 for information concerning the operating lease transaction for this facility.

In 1999, the Company completed construction of and placed into operation two 44-MW, simple-cycle gas combustion turbines at Springdale, Pennsylvania, and Allegheny Energy Supply purchased from an unregulated subsidiary of the Company its 276-MW share of capacity at Fort Martin Unit No. 1.

Global Energy Markets Acquisition
On March 16, 2001, Allegheny Energy Supply acquired Global Energy Markets, the energy commodity marketing and trading business of Merrill Lynch. Allegheny Energy Supply acquired this business for $489.2 million plus the issuance of a 1.967-percent equity membership interest. The acquired business helps the Company optimize its portfolio of generating assets by significantly enhancing its wholesale marketing, energy trading, fuel procurement, market analysis, and risk-management activities on a nationwide basis. This business provides the Company with valuable market intelligence to help it better identify opportunities to expand its acquisition and development activities and to compete outside of its traditional regions. As discussed above, the acquisition included a long-term contractual right to call up to 1,000 MW of generating capacity in southern California. See Notes E and S to the consolidated financial statements for additional information regarding the acquisition.

Long-term Power Sales Agreement
The Company's acquisition of Merrill Lynch's energy trading business included the long-term contractual right to call up to 1,000 MW of natural gas-fired generating capacity in southern California and related hedges. Shortly after acquiring this energy trading business, the Company evaluated the long-term and short-term risks associated with this portfolio in order to construct a prudent risk mitigation strategy. The Company concluded that the most significant risk was the changing relationship between electricity and natural gas prices over time and the resulting effects on the value of the Company's contractual right to call up to 1,000 MW of generating capacity. In the short-term, unusually high prices and volatility in the electricity and natural gas markets were expected to continue. Given the prevailing levels of volatility in the electricity and natural gas markets and the Company's contractual right to call up to 1,000 MW of generating capacity, the Company implemented a hedging strategy. Accordingly, on March 22, 2001, the Company closed a substantial part of its long position by entering into a power sales agreement with the California Department of Water Resources (CDWR), the electricity buyer for the state of California.

The agreement is for a period through December 2011. Under this agreement, Allegheny Energy Supply has committed to supply California with contract volumes varying from 150 MW to 500 MW through December 2004. For the last seven years of the contract, the contract volume will be fixed at 1,000 MW. The contract contains a fixed price of $61 per megawatt-hour.

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ALLEGHENY ENERGY, INC.

The Company remained concerned about the forward cost of natural gas and spot prices for electricity in California and the net position of the contractual right to call up to 1,000 MW of generating capacity. Consequently, the Company entered into a series of forward purchases of electricity through 2002 designed to hedge these risks. While these forward purchases were made at then market prices, the prices paid for these forward purchases exceeded the contractual price of the CDWR agreement. As a result, the CDWR agreement and related forward purchase hedges have negatively affected the Company's cash flows since March 2001. While this hedging strategy will result in short-term cash outflows through 2002, the total projected cash flows remain significantly positive. This hedging strategy is performing as designed.

In August 2001, Allegheny Energy Supply was the successful bidder to supply Baltimore Gas and Electric Company (BGE) with electricity from July 2003 through June 2006. Allegheny Energy Supply has committed to supply BGE with an amount needed to fulfill 10 percent of its provider of last resort obligations. This amount is estimated to range from 200 MW to 530 MW.

On July 31, 2001, Allegheny Energy Supply was named the electric generation supplier for eight boroughs in New Jersey that own and operate electric utilities as departments of municipal governments. The contracts, which will supply 150 MW of electricity to the boroughs, will run from June 2002 through 2004.

The Company records these contracts at their fair value on the consolidated balance sheet, with changes in fair value recorded as a component of unregulated generation revenues on the consolidated statement of operations.

Proposed Natural Gas Storage and Pipeline Project
On January 10, 2002, Allegheny Energy Supply announced its participation in an Open Season process for a proposed natural gas storage and pipeline project - the Desert Crossing Gas Storage and Transportation System - which would be located in Nevada and Arizona. Sponsored by Allegheny Energy Supply, the Salt River Project, and Sempra Energy Resources, the proposed project would include the development of a 10-billion-cubic-foot salt cavern storage complex north of Kingman, Arizona, and an associated north-south pipeline, extending approximately 300 miles from near Las Vegas, Nevada, to Wenden, in southwest Arizona. If constructed, the project would provide a high-deliverability natural gas storage facility and inter-connections with major natural gas pipelines in the southwest United States. It could be a stable source of natural gas supply for Allegheny Energy Supply's proposed 1,080-MW La Paz generating facility and would provide additional supply and delivery options for Allegheny Energy Supply's existing agreements in Las Vegas and California.

Open Season - when prospective natural gas shippers may bid for capacity on the project - was held from January 10, 2002, through February 8, 2002. In response to the Open Season, a number of bids were received from potential shippers, reflecting support for the project by the market. However, many of the bid submissions were not binding due to the inclusion of certain contingency clauses. In addition, the recent announcement of the cancellation or delay of several development projects for new generating facilities has caused many shippers to express concern over the commitment to a binding bid. As such, discussions are ongoing with interested parties to determine their level of commitment. A final decision regarding whether to move forward with the project will be made at the conclusion of the discussions with interested parties.

REGULATED UTILITY OPERATIONS

Rate Matters

The Company's regulated subsidiaries, doing business as Allegheny Power, operate electric and natural gas T&D systems. Monongahela Power also generates electric energy for West Virginia as deregulation of its electric generation has not been implemented in that state. These subsidiaries are subject to federal and state regulation, including the PUHCA. Allegheny Power's markets for regulated electric and natural gas retail sales are in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia.

Electric
Potomac Edison decreased the fuel portion of Maryland customers' bills by approximately $6.4 million annually, effective with bills rendered on or after December 7, 1999, based on the outcome of proceedings before the Maryland Public Service Commission (Maryland PSC). A proposed order was issued on February 18, 2000, granting the requested decrease in Potomac Edison's fuel rate, and, on March 21, 2000, the proposed order became final. Effective July 1, 2000, coincident with the start of customer choice in Maryland, the fuel rate was rolled into base rates, thus eliminating the fuel adjustment clause.

On March 24, 2000, the Maryland PSC issued an order requiring Potomac Edison to refund the 1999 deferred fuel balance overrecovery of approximately $9.9 million to customers over a period of 12 months that began April 30, 2000. This refund did not affect Potomac Edison's earnings, since the overrecovered amounts had been deferred.

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On October 4, 2000, the Maryland PSC approved Potomac Edison's filing, which represented the final reconciliation of its deferred fuel balance. Potomac Edison refunded to customers a $3.2-million overrecovery balance, which existed in the Maryland deferred fuel account as of September 30, 2000. The deferred fuel credit to customers began in October 2000 and ended in October 2001 when the balance fell to zero. The refund of the overrecovered balance did not affect Potomac Edison's earnings, since the overrecovered amounts had been deferred.

On June 23, 2000, the West Virginia PSC approved a Joint Stipulation and Agreement for Settlement, stating agreed-upon rates designed to make the West Virginia rates of Potomac Edison and Monongahela Power consistent. Under the terms of the settlement, several tariff schedules, notably those available to residential and small commercial customers, will require several incremental steps to reach the agreed-upon rate level. The settlement rates resulted in a revenue reduction of approximately $.3 million for 2000, increasing over eight years to an annual reduction of approximately $1.7 million. Offsetting the decrease in rates, the settlement approved by the West Virginia PSC directs Monongahela Power and Potomac Edison to amortize the existing over-collected deferred fuel balance as of June 30, 2000 (approximately $16 million), as a reduction of expenses over a four-and-one-half-year period beginning July 1, 2000. Also, effective July 1, 2000, Potomac Edison and Monongahela Power ceased their expanded net energy cost (fuel clause) as part of the settlement.

In conjunction with the order approving Phase I of Potomac Edison's Functional Separation Plan, the Virginia SCC approved a Memorandum of Understanding (MOU). The MOU provided that, effective with bills rendered on or after August 7, 2000, base rates were reduced by $1 million; Potomac Edison would not file for a base rate increase prior to January 1, 2001; and the fuel rate would be rolled into base rates effective with bills rendered on or after August 7, 2000. The Company was not required to refund to customers the overrecovered fuel balance of $.2 million. A fuel rate adjustment credit was also implemented on August 7, 2000, reducing annual fuel revenues by $750,000. Effective August 2001, the fuel rate adjustment credit dropped to $250,000. Effective August 2002, the fuel rate adjustment credit will be eliminated.

On November 29, 2000, the Maryland PSC approved the Power Sales Agreement between Potomac Edison and the winning bidder covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2001, through December 31, 2001. In November 2001, the Maryland PSC approved a further Power Sales Agreement between Potomac Edison and Allegheny Energy Supply, the winning bidder, covering the sale of the AES Warrior Run output to the wholesale market for the January 1, 2002, through December 31, 2004, period. The AES Warrior Run cogeneration project was developed under the 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 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, 2001, there was an increase in Maryland base rates. This increase was a result of the phase-in of the rate increase approved by the Maryland PSC in October 1998 pursuant to a settlement agreement, which includes recognition and dollar-for-dollar recovery of costs to be incurred from the AES Warrior Run PURPA project. The Maryland PSC approved rates to each customer class on December 22, 1998. Under the terms of the agreement, Potomac Edison increased its rates about four percent in each of the years 1999, 2000, and 2001 (a $79-million total revenue increase during 1999 through 2001). The increases were designed to recover additional costs of about $131 million, over the 1999 through 2001 period, for capacity purchases from the project, net of alleged overearnings of $52 million for the same period. The agreement also required that Potomac Edison share with customers 50 percent of earnings above an 11.4-percent return on equity for 1999 and 2000. As a result, 50 percent of the amount above the threshold earnings amount, or $9.7 million applicable to 1999, was distributed to customers in the form of an Earnings Sharing Credit, effective June 7, 2000, through April 30, 2001. An Earnings Sharing Credit of $1.9 million applicable to 2000 was distributed to customers from September 6, 2001, through January 8, 2002.

Effective with bills rendered on or after January 8, 2002, there was a decrease in Maryland distribution rates. This decrease, or Customer Choice Credit, is a result of implementing the rate reductions called for in the settlement agreement approved in December 1999. Under the terms of the agreement (covering stranded cost quantification mechanism, price protection mechanism, and unbundled rates), Potomac Edison decreased its rates seven percent for residential customers and one-half of one percent for the majority of commercial and industrial customers. 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 the electric universal surcharge has been introduced, both of which must be recovered under Potomac Edison's distribution rate cap consistent with the

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settlement agreement. Accordingly, distribution rates have been further reduced by $3 million from the previously approved rates in the settlement agreement. The distribution rate cap for all customers is effective through 2004.

Effective January 1, 2002, the Pennsylvania Department of Revenue increased the gross receipts tax rate from 4.4 percent to 5.9 percent for electric distribution companies in the state, including West Penn. State law directs West Penn to recover these increased tax charges by means of a State Tax Adjustment Surcharge (STAS) added to customer bills. On October 29, 2001, West Penn filed a request with the Pennsylvania Public Utility Commission (Pennsylvania PUC) to recover the increased tax liability of approximately $16.8 million from customers. By an order entered December 21, 2001, the Pennsylvania PUC directed West Penn to include the STAS on customer bills rendered between January 1, 2002, and December 31, 2002. On January 8, 2002, the Office of Consumer Advocate (OCA) filed an appeal of the Pennsylvania PUC order to the Commonwealth Court of Pennsylvania. Any further Pennsylvania PUC action on this matter is held in abeyance pending the resolution of the OCA Petition for Review in the Commonwealth Court. West Penn intends to intervene at the Commonwealth Court in support of the Pennsylvania PUC's decision.

Natural Gas
On October 11, 2000, the West Virginia PSC approved an interim increase of the commodity rate for natural gas customers of Monongahela Power, formerly West Virginia Power Company (West Virginia Power) customers, for natural gas service bills rendered on and after December 1, 2000. On December 11, 2000, the West Virginia PSC approved additional increases for bills rendered on and after January 1, 2001, through November 30, 2001 (total revenue increase for the 12-month period of $5.7 million or 25.1 percent for the commodity rate). The commodity rate, or Purchased Gas Adjustment (PGA) rate, is the portion of the bill that reflects the cost of gas, which increased significantly during 2000. The West Virginia PSC approved a tiered rate structure, with rates established for the winter heating season, effective January 1, 2001, through April 30, 2001, and further increased rates effective May 1, 2001, through November 30, 2001, dependent upon the level of cost recovery after the winter heating season. This approach allowed Monongahela Power full recovery of these costs, but eased the increase for the average customer. On October 10, 2001, the West Virginia PSC approved an interim decrease in the PGA rate, 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 for the commodity rate). This approval became final on December 25, 2001. The reduced PGA rate is the result of changes in the market price that Monongahela Power pays for natural gas. With this adjustment, customers will benefit from recent decreases in natural gas market prices. These increases and decreases in gas cost recovery revenues have no effect on earnings because they were implemented via the PGA mechanism. Under the PGA procedure, 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.

On January 4, 2001, Mountaineer Gas filed for a rate increase with the West Virginia PSC in response to significant increases in the market price for natural gas. On July 25, 2001, a settlement was reached and a Joint Stipulation and Agreement for Settlement was filed with the West Virginia PSC. In October 2001, the West Virginia PSC approved the settlement agreement, which provides for a base revenue increase of $5 million per year and an increase in natural gas cost-recovery revenues of approximately $23 million per year (a total increase of approximately 16.5 percent over existing rates), effective November 1, 2001. Also, Mountaineer Gas returned to the standard PGA treatment of purchased natural gas costs at the conclusion of the rate moratorium on October 31, 2001.

Mountaineer Gas and West Virginia Power Acquisitions
On August 18, 2000, Monongahela Power completed the purchase of Mountaineer Gas, a regulated natural gas sales, transportation, and distribution company serving a large portion of West Virginia, from Energy Corporation of America (ECA) for $325.7 million, which included the assumption of $100.1 million of existing long-term debt. The acquisition included the assets of Mountaineer Gas Services, which operates natural gas-producing properties, natural gas-gathering facilities, and intrastate transmission pipelines. The acquisition increased the number of Monongahela Power's natural gas customers in West Virginia by approximately 200,000. See Note E to the consolidated financial statements for additional information regarding the acquisition of Mountaineer Gas.

In December 1999, Monongahela Power purchased from UtiliCorp United Inc. the assets of West Virginia Power, an electric and natural gas distribution business located in southern West Virginia, for approximately $95 million.

Regional Transmission Organization (RTO)
On March 15, 2001, the Company and PJM filed documents with the FERC to expand the PJM transmission system and energy market through the creation of PJM West. The filing represents collaboration between the Company, PJM, and numerous stakeholders. The Company and PJM have asked the FERC to confirm that PJM West satisfies the FERC's requirements for RTOs as set forth in Order No. 2000. Under the PJM West proposal, the Company's regulated utility subsidiaries will transfer operational control over their transmission system to PJM. The Company will adopt PJM's transmission pricing methodology, including PJM's congestion management system. In addition, PJM will expand its day-ahead and real-time energy markets to include PJM West. As a result, energy suppliers will be able to reach consumers anywhere within the expanded PJM/PJM West market at a single transmission rate, instead of paying multiple transmission rates as they do today.

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The Company's filing also requested authorization to recover anticipated lost transmission revenues of approximately $24.4 million annually and PJM West start-up expenses billed to the Company by PJM of approximately $3.9 million annually through 2004. By order dated July 12, 2001, the FERC conditionally approved PJM West, subject to a compliance filing clarifying certain terms and conditions of PJM West and providing additional support for the Company's claim for lost transmission revenues and start-up expenses. The Company and PJM submitted their compliance filing on September 10, 2001.

On January 30, 2002, the FERC authorized the Company and PJM to proceed with PJM West, effective March 1, 2002. The FERC's order set for hearing the question of whether the Company had adequately supported its claim to recover anticipated lost transmission revenues and start-up expenses, and created uncertainty as to whether the FERC intended to initiate a general investigation into the Company's transmission rates, which could potentially lead to an overall reduction to its transmission revenues. The Company requested clarification, and, on March 1, 2002, the FERC issued a further order explaining that its January 30, 2002, order did not initiate a general investigation of the Company's transmission revenues. Accordingly, in light of the limited scope of the hearing ordered by the FERC, the Company has elected to proceed with PJM West, effective April 1, 2002. The Company anticipates the formation of PJM West will enhance its ability to compete for power sales in the expanded PJM/PJM West market area.

OTHER UNREGULATED OPERATIONS

Allegheny Ventures' Acquisitions
On November 1, 2001, Allegheny Ventures completed the acquisition of Fellon-McCord Associates, Inc. (Fellon-McCord), an energy consulting and management services company, and Alliance Energy Services Partnership (Alliance Energy Services), a provider of natural gas and other energy-related services to large commercial and industrial customers. The purchase of these businesses will add natural gas procurement and energy management services to the Company's current service offerings. The Company completed this acquisition for $30.5 million in cash plus a maximum of $18.7 million in contingent consideration to be paid over a three-year period, starting from the November 1, 2001, acquisition date. Pursuant to a participation agreement entered into as part of the acquisition of Mountaineer Gas, Allegheny Ventures is negotiating the sale of up to a 20-percent indirect interest in Alliance Energy Services to ECA.

On December 29, 2000, Allegheny Ventures signed an agreement to acquire Leasing Technologies International, Inc. (LTI), a financial services firm that specializes in equipment financing solutions for emerging growth companies for $26 million. During the second quarter of 2001, Allegheny Ventures notified LTI that it was terminating the purchase transaction as permitted by the agreement. LTI has reserved the right to pursue legal actions.

AFN, LLC
In March 2000, Allegheny Communications Connect, Inc. (ACC), along with five other companies and a consulting partner, created AFN, LLC (AFN), a super-regional, high-speed fiber and data services company. The network offers more than 7,700 route miles, or 140,000 fiber miles, connecting major markets in the eastern United States to secondary markets. Through its initial footprint of fiber, AFN reaches areas that comprise roughly 35 percent of the national wholesale communications capacity market.

AFN expects to expand its network to 10,000 route miles or 200,000 fiber miles by the end of 2002. AFN will reach this capacity by adding partners with existing fiber, installing fiber in areas of opportunity, and acquiring existing fiber from others or contracting long-term lease agreements for existing fiber. At December 31, 2001, ACC had a 17-percent interest in AFN as a result of contributing 339 miles of lit fiber, including revenue from capacity contracts related to these routes, and 845 miles of committed dark fiber.

Allegheny Energy Solutions, Inc.
In December 2001, Allegheny Energy Solutions, Inc. (Allegheny Energy Solutions) completed an agreement to provide seven natural gas-fired turbine generators for the South Mississippi Electric Power Association (SMEPA). The seven units, with a combined output of approximately 450 MW, will be located at three sites in southern Mississippi near the towns of Sylvarena, Silver Creek, and Moselle. The units will be owned by SMEPA. Construction is scheduled to begin in March 2002, with installation to be completed in May 2003 through May 2006. Allegheny Energy Solutions will provide design, construction, and installation services for the units. The agreement allows for liquidated damages, for a maximum amount of $10 million, in the event Allegheny Energy Solutions fails to meet either specified delivery dates or the generators fail to meet specified performance requirements.

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ALLEGHENY ENERGY, INC.

OTHER EVENTS

Issuance of Common Shares
On May 2, 2001, the Company completed a public offering of its common stock, selling a total of 14.3 million shares at $48.25 per share. The net proceeds of approximately $667 million were used to fund a portion of Allegheny Energy Supply's acquisition of generating facilities in the Midwest and for other corporate purposes.

Union Contract Negotiations
On April 30, 2001, the Company's collective bargaining agreement with the Utility Workers Union of America (UWUA) System Local 102 expired. The parties entered into a contract extension through May 31, 2001. The Company and the UWUA were unable to reach agreement on a new labor pact by this deadline. The parties continue to work under the terms and conditions of the prior labor agreement on a day-to-day basis. The Company and the UWUA have continued to meet from time to time in pursuit of a long-term agreement. The prior agreement covers approximately 840 employees in regulated utility operations and approximately 300 employees in unregulated generation operations.

During 2001, the Company successfully negotiated new labor agreements with three bargaining units of the International Brotherhood of Electrical Workers. During 2002, the Company anticipates negotiations with five other bargaining units whose contracts will expire during the year.

REVIEW OF OPERATIONS

Critical Accounting Policies and Estimates

Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires the Company 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, adverse power purchase commitments, and goodwill.

Commodity Contracts
Commodity contracts related to the Company's energy trading activities are recorded at their fair value in accordance with Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." At December 31, 2001, the fair value of the Company's commodity contracts was a net asset position of $760.4 million. The fair value of exchange-traded instruments, primarily futures and certain options, was based on actively quoted market prices. In establishing the fair value of commodity contracts that do not have quoted prices, such as physical forward contracts, over-the-counter options, and swaps, management uses available market data and pricing models to estimate fair values. Estimating fair values of instruments which do not have quoted market prices requires management's judgment in determining amounts which could reasonably be expected to be received from, or paid to, a third party in settlement of the contracts. The amounts could be materially different from the amounts that might be realized in an actual sale transaction. Fair values are subject to change in the near-term and reflect management's best estimate based on various factors.

In establishing the fair value of commodity contracts, the Company makes estimates using available market data and pricing models. Factors such as uncertainty in prices, operational risks related to generating facilities, and risks related to the performance by counterparties are evaluated in establishing the fair value of these contracts.

The Company's accounting for commodity contracts is discussed under "Sales and Revenues" starting on page M-12 and Note E to the consolidated financial statements. Also, see Note J to the consolidated financial statements and "Derivative Instruments and Hedging Activities" starting on page M-28 for additional information regarding the Company's accounting for derivative instruments under the Financial Accounting Standards Board's (FASB) Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities."

In addition to the above, the fair value of the Company's commodity contracts can be affected by regulatory challenges involving deregulation of energy prices and markets. The California Public Utilities Commission (California PUC) has filed a complaint with the FERC to abrogate or substantially modify the contracts between the CDWR and Allegheny Energy Supply, which could have a material effect on the fair value of the Company's commodity contracts. See Note T to the consolidated financial statements for additional discussion of the complaint filed by the California PUC.

M-10

ALLEGHENY ENERGY, INC.

Adverse Power Purchase Commitments
At December 31, 2001, the Company's adverse power purchase commitment liability was $278.3 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 the Company related to a commitment to buy power 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 could have a material affect on the adverse power purchase commitment.

Excess of Cost Over Net Assets Acquired (Goodwill)
As of December 31, 2001, the Company's intangible asset for acquired goodwill was $603.6 million primarily related to the acquisitions over the last three years. A new accounting standard, SFAS No. 142, "Goodwill and Other Intangible Assets" required that the amortization of goodwill cease beginning in 2002. Instead, goodwill is required to be tested at least annually for impairment using the fair value of the Company's reporting units. For the Company, the estimation of the fair value of its reporting units will involve the use of present value measurements and cash flow models. The Company is in the process of determining the affects of SFAS No. 142 on its financial position and results of operations.

Earnings Summary

Earnings

Basic Earnings

Per Average Share

(Millions of dollars except per share data)

2001

2000

1999

2001

2000

1999

Operations:

   Regulated utility

$203.3

$227.7

$236.5

$1.69

$2.06

$2.03

   Unregulated generation

245.8

83.7

49.1

2.05

.76

.42

   Other unregulated

(.2)

2.2

(.2)

.02

Consolidated income before extraordinary charges and cumulative effect of accounting change

448.9

313.6

285.4

3.74

2.84

2.45

Extraordinary charges, net (Notes B, C, and F to consolidated financial statements)

(77.0)

(27.0)

(.70)

(.23)

Cumulative effect of accounting change, net (Note J to consolidated financial statements)

(31.1)

(.26)

Consolidated net income

$417.8

$236.6

$258.4

$3.48

$2.14

$2.22

The increase in earnings for 2001, before extraordinary charges and the cumulative effect of an accounting change, was driven by the addition of more than 3,537 MW of unregulated generating capacity and the successful integration of a newly acquired energy trading and risk management business. The increase in unregulated generation operations' net revenues included the results of the acquired energy trading business, since March 16, 2001. See "Sales and Revenues" starting on page M-12 for a detailed discussion of unregulated generation operations' revenues, including the revenues from energy trading activities.

The decrease in earnings for the Company's regulated utility operations for 2001 was due to the transfer of Potomac Edison's Maryland, Virginia, and West Virginia jurisdictional generating assets to unregulated generation operations in August 2000 and the transfer of Monongahela Power's Ohio and FERC jurisdictional generating assets to unregulated generation operations on January 1, 2001. For segment reporting purposes, Monongahela Power's Ohio and FERC jurisdictional generating assets were transferred from regulated utility operations to unregulated generation operations on January 1, 2001, coincident with the start of customer choice in Ohio. These generating assets were transferred between the Company's subsidiaries, Monongahela Power and Allegheny Energy Supply, on June 1, 2001. This decrease was partially offset by the acquisition of Mountaineer Gas in August 2000.

The increase in earnings per share for 2001, before extraordinary charges and the cumulative effect of an accounting change, reflects the results of energy trading activities and higher net revenues for the unregulated generation operations 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.

Allegheny Energy 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, Allegheny Energy Supply recorded a charge of $31.1 million against earnings, net of the related tax effect ($52.3 million, before tax) for these contracts as a change in accounting principle on January 1, 2001. See Note J to the consolidated financial statements for additional details.

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ALLEGHENY ENERGY, INC.

The increase in unregulated generation operations' earnings for 2000, before extraordinary charges, resulted from the transfer of Potomac Edison's generating assets from regulated utility operations to unregulated generation operations in August 2000. In addition, the earnings for unregulated generation operations increased due to colder-than-normal weather in November and December of 2000. This increase was partially offset by the milder summer weather in 2000.

Earnings for the Company's regulated utility operations decreased in 2000 due to the transfer of Potomac Edison's generating assets in August 2000. This decrease was partially offset by the acquisition of two energy distribution businesses, West Virginia Power in December 1999 and Mountaineer Gas in August 2000.

The increase in earnings per share for 2000, before the extraordinary charge, reflects higher net revenue in the unregulated generation operations segment and a lower number of average shares of common stock outstanding as a result of the Company's 1999 stock repurchase program.

Extraordinary charges in 2000 and 1999 resulted from the Maryland, Ohio, Virginia, and West Virginia electric utility restructuring orders as discussed in Notes B and C to the consolidated financial statements.

Sales and Revenues
Total operating revenues for 2001, 2000, and 1999 were as follows:

(Millions of dollars)

2001

2000

1999

Operating revenues:

  Regulated utility:

    Electric

$2,417.2

$2,315.8

$2,169.0

    Natural gas

235.1

81.8

    Choice

5.6

28.4

34.3

    Bulk power

160.5

135.8

45.7

    Transmission and other energy services

70.8

73.2

61.0

        Total regulated utility revenues

2,889.2

2,635.0

2,310.0

  Unregulated generation:

   Bulk power

8,430.6

2,048.8

723.9

   Retail and other

213.8

232.8

155.5

        Total unregulated generation revenues

8,644.4

2,281.6

879.4

  Other unregulated

139.6

22.6

8.9

  Eliminations

(1,294.3)

(927.3)

(389.9)

        Total operating revenues

$10,378.9

$4,011.9

$2,808.4

The increase in regulated electric and natural gas revenues for 2001 was primarily due to an increase in the average number of customers and by Monongahela Power's acquisition of Mountaineer Gas in August 2000, partially offset by milder summer and winter weather in 2001. The increase in regulated electric and natural gas revenues for 2000 was primarily due to an increase in the number of customers and Monongahela Power's acquisition of West Virginia Power in December 1999 and Mountaineer Gas in August 2000.

Choice revenues represent T&D revenues from customers in West Penn's Pennsylvania, Potomac Edison's Maryland, and Monongahela Power's Ohio distribution territories who chose other suppliers to provide their energy needs. Pennsylvania, Maryland, and Ohio deregulation gave West Penn, Potomac Edison, and Monongahela Power's regulated customers the ability to choose another energy supplier. For 2001 and 2000, all of West Penn's regulated customers had the ability to choose. As of July 1, 2000, all of Potomac Edison's Maryland customers had the ability to choose, and, as of January 1, 2001, Monongahela Power's Ohio regulated customers had the ability to choose. At December 31, 2001, less than .2 percent of West Penn's customers and Potomac Edison's Maryland customers chose alternate energy suppliers. None of Monongahela Power's Ohio customers have switched to another supplier. At December 31, 2000, less than one percent of West Penn's customers and Potomac Edison's Maryland customers chose alternate energy suppliers. The decrease in choice revenues for 2001 and 2000 was primarily due to West Penn customers who previously chose an alternate energy supplier and then returned to full electric service from West Penn at regulated rates.

M-12

ALLEGHENY ENERGY, INC.

The change in regulated utility operations' bulk power for 2001 and 2000 was primarily due to increased sales between Monongahela Power and Potomac Edison and the Company's unregulated subsidiary, Allegheny Energy Supply, reflecting the dispatch arrangements that were put in place in early 2000. In addition, $47 million for 2001 and $28.1 million for 2000 was the result of the sale of the output of the AES Warrior Run cogeneration facility into the open wholesale market. This output was part of a Maryland PSC settlement agreement with Potomac Edison, allowing full recovery from Maryland customers of the purchased 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.

In October 1998, the Maryland PSC approved a settlement agreement for Potomac Edison. Under the terms of that agreement, Potomac Edison increased its rates about four percent in each of the years 1999, 2000, and 2001 (a $79- million total revenue increase during 1999 through 2001). The increases were designed to recover additional costs of about $131 million over the 1999 through 2001 period for capacity purchases from the AES Warrior Run cogeneration project, net of alleged overearnings of $52 million for the same period.

Regulated electric revenues reflect not only changes in kilowatt-hour sales and base rate changes, but also changes in revenues from fuel and energy cost adjustment clauses (fuel clauses), which were applicable in all Company jurisdictions, except for Pennsylvania, through various dates in 2000. Effective July 1, 2000, Potomac Edison's Maryland jurisdiction and the West Virginia jurisdiction for Monongahela Power and Potomac Edison ceased to have a fuel clause. Effective August 7, 2000, a fuel clause ceased to exist for Potomac Edison's Virginia jurisdiction. Effective January 1, 2001, a fuel clause ceased to exist for Monongahela Power's Ohio jurisdiction.

Where a fuel clause was in effect, changes in fuel revenues had no effect on consolidated net income because increases and decreases in fuel and purchased power costs and sales of transmission services and bulk power were passed on to customers through fuel clauses. Once the fuel clause was eliminated, the Company assumed the risks and benefits of changes in fuel and purchased power costs and sales of transmission services and bulk power.

Natural gas sales and services and electric revenues from West Virginia Power and Mountaineer Gas are included in regulated revenues in 2001 and 2000. Because a significant portion of the natural gas sold by Monongahela Power's natural gas distribution operations is ultimately used for space heating, both revenues and earnings are subject to seasonal fluctuations. The PGA mechanism continues to exist for West Virginia Power and came into effect for Mountaineer Gas following a three-year moratorium, which ended on October 31, 2001. See "Rate Matters" starting on page M-6 for additional details regarding rate matters for Monongahela Power and Mountaineer Gas.

The increase in unregulated generation operations' revenues for 2001 was primarily due to the results of energy trading activities. Allegheny Energy Supply has significantly increased the volume and scope of its energy commodity marketing and trading activities. The Company now trades electricity, natural gas, oil, coal, and other energy-related commodities. The Company records 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 unregulated generation revenues. The realized revenues from energy trading activities, with the exception of certain financial instruments, including swaps and certain options, are recorded on a gross basis as individual discrete transactions as either revenues or expenses because the contracts require physical delivery of the underlying asset. 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 market data and pricing models. The Company has certain 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 power prices, interest rates, estimates of market volatility for natural gas and power prices, the correlation of natural gas and power prices, and other factors such as generating unit availability and location, as appropriate. These inputs require management judgments and assumptions. The Company'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. Actual effects on the Company's financial position 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. See "Quantitative and Qualitative Disclosure About Market Risk" on page M-29 for additional information regarding the Company's exposure to market risks associated with commodity prices.

The fair value of energy trading commodity contracts, which represent the net unrealized gain and loss positions, are recorded as assets and liabilities as stated above, after applying the appropriate counterparty netting agreements in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts - an Interpretation

M-13

ALLEGHENY ENERGY, INC.

of APB Opinion No. 10 and FASB Statement No. 105." At December 31, 2001, the fair value of energy trading commodity contract assets and liabilities was $1,755.4 million and $995.0 million, respectively. At December 31, 2000, the fair value of energy trading commodity contract assets and liabilities was $234.5 million and $224.6 million, respectively.

The following table disaggregates the net fair value of commodity contract assets and liabilities, excluding the Company's generating assets and provider of last resort obligations, as of December 31, 2001, based on the underlying market price source and the contract delivery periods:

Fair value of contracts at December 31, 2001

Classifications of
contracts by source of
fair value

Delivery less
than 1 year

Delivery
2 - 3 years

Delivery
4 - 5 years

Delivery in excess of 5 years

Total fair value

(Millions of dollars)

Prices actively quoted

$(239.7)

$(75.6)

$     (.5)

$    5.1

$  (310.7)

Prices provided by other external sources

(12.8)

(1.9)

(14.7)

Prices based on models

24.8

134.0

364.3

562.7

1,085.8

Total

$(214.9)

$  58.4

$351.0

$565.9

$   760.4

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. The Company determines prices actively quoted from various industry services, broker quotes, and the New York Mercantile Exchange (NYMEX). Electricity markets are generally liquid for approximately three years and gas markets are generally liquid for approximately five years. Afterward, some market prices can be observed, but market liquidity is less robust.

Approximately $1.1 billion of the Company's commodity contracts were classified as prices based on models (even though a portion of these contracts are valued based on observable market prices). The most significant variable to the Company's models used to value these contracts is 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 three years and some observable market prices are available for about five years. After five 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 five years, and some observable market prices are available for about 10 years. Beyond 10 years, natural gas prices are escalated, based on trends in prior years.

For deliveries of less than one year, the fair value of the Company's commodity contracts was a net liability of $214.9 million, primarily related to commodity contracts to hedge the CDWR agreement. As discussed below, the Company expects to incur realized losses related to the contract with the CDWR and related hedges through 2002.

Net unrealized gains of $608.3 million in 2001 and $8.4 million in 2000 were recorded to the consolidated statement of operations in unregulated generation revenues to reflect the change in fair value of the energy commodity contracts. The following table provides a roll-forward of the net fair value, or commodity contract assets less commodity contract liabilities, of the Company's commodity contracts from December 31, 2000, to December 31, 2001:

(Millions of dollars)

Amount

Net fair value of commodity contract assets and liabilities at December 31, 2000

$    9.9

Net fair value of commodity contracts acquired with the energy trading business

218.3

Subtotal

228.2

Adoption of SFAS No. 133

(52.3)

Fair value of structured transactions when entered into during 2001

45.0

Net options paid and received

(23.8)

Unrealized gains on commodity contracts, net

563.3

Net fair value of commodity contract assets and liabilities at December 31, 2001

$760.4

M-14

ALLEGHENY ENERGY, INC.

During 2001, the Company did not have any changes in the fair value of commodity contracts attributed to changes in valuation techniques. With regard to the assumptions, the Company frequently evaluates availability, correlation, volatility, heat rate, and other factors against market observations and market adjustments. The effects of these changes cannot be readily separated from the effects of changes in forward prices for electricity and natural gas.

As shown in the table above, the net fair value of the Company's commodity contracts increased by $608.3 million as a result of unrealized gains recorded during the year. Of the unrealized gains, $578.9 million related to the Company's contracts in the Western Systems Coordinating Council (WSCC), including the fixed-price contract with the CDWR and the contract to call up to 1,000 MW of generating capacity in southern California. 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 to call up to 1,000 MW of generating capacity in southern California and other contracts primarily used to hedge the WSCC portfolio.

During 2001, the Company's energy trading activities resulted in $223.2 million of net realized losses. These losses were mainly related to the Company's contract with the CDWR and the related hedges, which were partially offset by realized gains from the sale of generation from the generating assets acquired in the Midwest and from other generation in excess of the power provided to the Company's regulated utility subsidiaries to meet their provider of last resort obligations. Due to the existing hedges of the CDWR contract, the Company is currently paying for power at prices above the fixed-price contract to sell power to the CDWR for reasons discussed under "Long-term Power Sales Agreements" starting on page M-5. The Company expects to continue to incur realized losses related to the CDWR contract due to the hedges through 2002, but at a reduced level as the hedges mature. Starting with 2003, the Company expects to realize gains related to the CDWR contract for the remainder of the term of the contract.

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 the Company's operating results. Similarly, volatility in interest rates will affect the Company's operating results. The effects may be either positive or negative, depending on whether the Company's subsidiaries are net buyers or sellers of electricity and natural gas.

The increase in unregulated generation operations' revenues for 2001 and 2000 also reflects increased transactions by Allegheny Energy Supply in the unregulated marketplace to sell electricity to wholesale customers and is due to having increased generation available for sale. As a result of the Electricity Generation Customer Choice and Competition Act (Customer Choice Act) in Pennsylvania, two-thirds of West Penn's generation was released in the first quarter of 1999 and was available for sale into the unregulated marketplace by Allegheny Energy Supply, subject to its obligations under the full requirements contracts it entered into with West Penn. In the first quarter of 2000, the final one-third of West Penn's generation was similarly released and became available for sale into the deregulated marketplace. In addition, the Company transferred approximately 2,100 MW of Potomac Edison's generating assets to Allegheny Energy Supply in August 2000 and transferred an additional 352 MW of Monongahela Power's Ohio and FERC jurisdictional generating assets and five MW of Potomac Edison's Virginia hydroelectric generating assets to unregulated generation operations in 2001. On May 3, 2001, Allegheny Energy Supply also completed the acquisition of three natural gas-fired generating facilities with a total generating capacity of 1,710 MW in the Midwest. As a result, the unregulated generation operations segment had more generation available for sale into the deregulated marketplace in 2001 and 2000, including sales to West Penn, Potomac Edison, and Monongahela Power to meet their provider of last resort obligations.

Other unregulated revenues increased by $117 million for 2001, primarily due to increased sales by Allegheny Ventures. Other unregulated revenues increased by $13.7 million for 2000, primarily due to increased sales of dark fiber by ACC.

The elimination between regulated utility operations, unregulated generation operations, and other unregulated operations revenues is necessary to remove the effect of affiliated revenues, primarily sales of power. See Note B to the consolidated financial statements for information regarding the Competitive Transition Charge (CTC).

M-15

ALLEGHENY ENERGY, INC.

OPERATING EXPENSES

Fuel expenses for 2001, 2000, and 1999 were as follows:

Fuel Expenses

(Millions of dollars)

2001

2000

1999

Regulated utility

$127.8

$232.7

$355.5

Unregulated generation

454.1

319.5

180.2

    Total fuel expenses

$581.9

$552.2

$535.7

Fuel expense represents the cost of coal, natural gas, and oil burned for electric generation. Total fuel expenses increased $29.7 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. Total fuel expenses for 2000 increased by $16.5 million as a result of increased kilowatt-hours generated, partially offset by decreased average fuel prices. The decrease in fuel expenses for regulated utility operations and the increase for unregulated generation operations for 2001 and 2000 was due to fuel expenses associated with the transfer of generating assets from regulated utility operations to unregulated generation operations as a result of deregulation activities.

Purchased power and exchanges, net, represents power purchases from and exchanges with other companies and purchases from qualified facilities under the PURPA and consists of the following items:

Purchased Power and Exchanges, Net

(Millions of dollars)

2001

2000

1999

Regulated utility:

  Purchased power:

    From PURPA generation*

$    191.6

$  191.0

$ 104.1

    Other purchased power

1,043.8

745.0

395.8

        Total purchased power for regulated utility

1,235.4

936.0

499.9

  Power exchanges, net

.1

6.9

(2.6)

Unregulated generation purchased power

7,183.9

1,520.9

390.1

Eliminations

(1,181.9)

(871.1)

(356.0)

  Purchased power and exchanges, net

$ 7,237.5

$1,592.7

$ 531.4

*PURPA cost (cents per kWh)

5.4

5.5

4.8

The increase in regulated utility operations' purchased power from PURPA generation of $.6 million for 2001 was due primarily to increased kilowatt-hours produced by these facilities.

The increase of $86.9 million in regulated utility operations' purchased power from PURPA generation for 2000 was due to the start of commercial operations of the AES Warrior Run cogeneration project. The Maryland PSC has approved Potomac Edison's full recovery of the AES Warrior Run purchased power costs as part of the settlement agreement to implement deregulation for Potomac Edison. Accordingly, the Company defers, as a component of other operation expenses, the difference between revenues collected related to AES Warrior Run and the cost of the AES Warrior Run purchased power.

The increase in regulated utility operations' other purchased power of $298.8 million and $349.2 million in 2001 and 2000, respectively, was primarily due to West Penn's and Potomac Edison's purchase of power from their unregulated generation affiliate, Allegheny Energy Supply, in order to provide energy to their customers who are eligible to choose an alternate electric supplier but elected not to do so. The increase for 2001 was also due to Monongahela Power's purchase of power from Allegheny Energy Supply in order to provide energy to Monongahela Power's Ohio customers who were eligible to choose an alternate electric supplier. The generation previously available to serve those Ohio customers was released and transferred to unregulated generation operations on January 1, 2001. For 2000, unplanned generating facility outages in the first quarter also caused the regulated utility operations of Potomac Edison and Monongahela Power to make purchases of higher-priced power on the wholesale market.

M-16

ALLEGHENY ENERGY, INC.

The increase in unregulated generation operations' purchased power of $5.7 billion in 2001 was primarily due to purchases made in support of various energy trading activities and physical power supply commitments.

The increase in unregulated generation operations' purchased power of $1.1 billion in 2000 was for power to serve the provider of last resort load of West Penn and Potomac Edison, unplanned first quarter generating facility outages that caused the Company to make purchases of higher-priced power on the wholesale market, and increased buy-sell transactions to optimize the value of unregulated generating assets in the fourth quarter.

The elimination for purchased power between regulated utility operations and unregulated generation operations is necessary to remove the effect of affiliated purchased power expenses.

Natural gas purchases and production expenses for 2001 and 2000 were as follows:

Natural Gas Purchases and Production

(Millions of dollars)

2001

2000

Regulated utility

$129.9

$57.0

Unregulated generation

8.0

Other unregulated

81.1

Total natural gas purchases and production expenses

$219.0

$57.0

Natural gas purchases and production represents the cost of natural gas for delivery to customers. The increase in natural gas purchases and production of $162 million for 2001 was primarily due to the acquisition of Mountaineer Gas in August 2000, purchases made for energy trading activities, and the acquisition of Alliance Energy Services. For 2000, natural gas purchases and production increased $57.0 million, reflecting the acquisition of West Virginia Power on December 31, 1999, and Mountaineer Gas in August 2000.

Other operation expenses for 2001, 2000, and 1999 were as follows:

Other Operation Expenses

(Millions of dollars)

2001

2000

1999

Regulated utility

$406.2

$345.7

$340.8

Unregulated generation

245.1

127.7

66.6

Other unregulated

54.9

18.2

5.8

Elimination

(120.1)

(74.5)

(23.8)

    Total other operation expenses

$586.1

$417.1

$389.4

The increase in regulated utility operations' other operation expenses of $60.5 million for 2001 was primarily due to Potomac Edison's generation lease payments to Allegheny Energy Supply and additional expenses related to Monongahela Power's acquisition of Mountaineer Gas. The transfer of Potomac Edison's generating assets to Allegheny Energy Supply on August 1, 2000, included Potomac Edison's generating assets located in West Virginia. A portion of these assets has been leased back to Potomac Edison to serve its West Virginia jurisdictional retail customers. The increase in regulated utility operations' expense of $4.9 million for 2000 reflects additional expenses related to the acquisition of West Virginia Power and Mountaineer Gas. These additional expenses were partially offset by reduced expenses related to the transfer of generating assets from regulated utility operations to unregulated generation operations during 2000.

The increase in unregulated generation operations' other operations expenses of $117.4 million for 2001 was due to increased salary, general, and administrative expenses, resulting from the acquired energy trading business, the increased purchases of electric trans-mission capacity for delivery of energy to customers, and expenses related to the generating assets transferred from regulated utility operations to unregulated generation operations. Unregulated generation operations' other operations expense for 2001 included a write-off to bad debt expense of $4.6 million for energy trades with Enron Corporation (Enron), which were determined to be uncollectible as a result of Enron's bankruptcy filing. The increase in unregulated generation operations' other operation expenses of $61.1 million for 2000 was primarily due to increased purchases of transmission capacity for delivery of energy to customers and expenses related to the transfer of generating assets during 2000.

M-17

ALLEGHENY ENERGY, INC.

The increase in other unregulated operations' other operations expenses of $36.7 million for 2001 was primarily due to activities by Allegheny Energy Solutions. The increase in other unregulated operations' other operations expenses of $12.4 million for 2000 primarily resulted from increased expenses related to the expanding fiber and data services business of ACC and the expanding distributed generation sales business of Allegheny Energy Solutions.

The eliminations for expenses between regulated utility operations, unregulated generation operations, and other unregulated operations are primarily to remove the effect of affiliated transmission purchases and affiliated lease payments.

Maintenance expenses for 2001, 2000, and 1999 were as follows:

Maintenance Expenses

(Millions of dollars)

2001

2000

1999

Regulated utility

$151.0

$149.0

$182.6

Unregulated generation

136.7

81.3

40.8

Other unregulated

.2

.1

    Total maintenance expenses

$287.9

$230.3

$223.5

Maintenance expenses represent costs incurred to maintain the power stations, T&D system, and general plant and reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. Variations in maintenance expense result primarily from unplanned events and planned projects, which vary in timing and magnitude depending upon the length of time equipment has been in service and the amount of work found necessary when the equipment is inspected.

The increase in regulated utility operations' maintenance of $2 million for 2001 was primarily due to increased expenses related to the acquisition of Mountaineer Gas and increased routine maintenance on the T&D system. These increases were partially offset by the transfer of generating assets from regulated utility operations to unregulated generation operations.

The increase in unregulated generation operations' maintenance expenses of $55.4 million for 2001 was primarily due to increased power station maintenance expenses related to the transfer of generating assets from regulated utility operations to unregulated generation operations and scheduled maintenance at the Fort Martin, Armstrong, Harrison, Hatfield's Ferry, Pleasants, and combustion turbine generating stations.

The decrease in regulated utility operations' maintenance and the increase in unregulated generation operations' maintenance in 2000 were due mainly to the transfer of generating assets from regulated utility operations to unregulated generation operations.

Unregulated generation maintenance in 2000 reflects the capitalization policy for Allegheny Energy Supply, which was formed in November 1999. The capitalization policy of Allegheny Energy Supply is based on operating generating assets in an unregulated environment in which fewer costs are capitalized and more costs expensed as maintenance. See Note K to the consolidated financial statements for additional details.

Depreciation and amortization expenses for 2001, 2000, and 1999 were as follows:

Depreciation and Amortization Expenses

(Millions of dollars)

2001

2000

1999

Regulated utility

$180.1

$194.5

$198.0

Unregulated generation

120.3

52.4

58.9

Other unregulated

1.1

1.0

.6

    Total depreciation and amortization expenses

$301.5

$247.9

$257.5

M-18

ALLEGHENY ENERGY, INC.

The decrease in regulated utility operations' depreciation and amortization expenses of $14.4 million for 2001 reflects the transfer of generating assets from regulated utility operations to unregulated generation operations, partially offset by depreciation of new capital additions, including the acquisition of Mountaineer Gas. The increase in depreciation and amortization expenses for unregulated generation operations of $67.9 million for 2001 was primarily due to depreciation expense related to the generating facilities in the Midwest that were acquired on May 3, 2001; amortization of goodwill of $21.1 million related to the acquired energy trading business; and generating assets transferred from regulated utility operations to unregulated generation operations.

Total depreciation and amortization expenses for 2000 decreased $9.6 million, reflecting the changes related to the establishment of capital recovery policies by Allegheny Energy Supply. See Note K to the consolidated financial statements for additional details. The decreases in regulated utility operations' depreciation and amortization expenses reflect the transfer of generating assets from regulated utility operations to unregulated generation operations during the year, partially offset by depreciation of new capital additions, including the acquisitions of West Virginia Power and Mountaineer Gas.

Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets," and, accordingly, ceased the amortization of all goodwill and accounted for goodwill on an impairment-only approach.

Taxes other than income taxes for 2001, 2000, and 1999 were as follows:

Taxes Other Than Income Taxes

(Millions of dollars)

2001

2000

1999

Regulated utility

$147.6

$148.4

$157.9

Unregulated generation

68.0

61.3

32.2

Other unregulated

.7

.5

.2

    Total taxes other than income taxes

$216.3

$210.2

$190.3

Total taxes other than income taxes increased $6.1 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 Federal Insurance Contribution Act taxes, resulting from a higher tax base due to the Mountaineer Gas and energy trading business acquisitions.

Total taxes other than income taxes increased $19.9 million for 2000, due primarily to increased gross receipts taxes, resulting from higher revenues from retail customers, increased property taxes, and increased West Virginia Business and Occupation taxes. The increases for 2000 were partially offset by reduced franchise and capital stock taxes, due to reduced tax rates and Pennsylvania Capital Stock tax adjustments related to prior years.

Regulated utility operations' and unregulated generation operations' taxes other than income taxes in 2001 and 2000 reflect the recategorization of taxes other than income taxes associated with the transfer of generating assets during those years. The 2000 decrease in regulated utility operations' taxes other than income taxes is partially offset by taxes related to the acquisitions of West Virginia Power and Mountaineer Gas.

Federal and State Income Taxes
Federal and state income taxes increased $60.3 million for 2001, due to increased taxable income. Federal and state income taxes for 2000 increased $20.4 million, due to an increase in taxable income and an increase in state income tax, net of federal income tax benefit.

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

Other Income and Deductions
The increases in allowance for borrowed funds used during construction and interest capitalized of $4.2 million in 2001 and $1.4 million in 2000 reflects more construction activity financed by short-term debt. The allowance for borrowed funds used during construction component of the formula receives greater weighting when short-term debt increases. Higher unregulated generation construction capitalized interest also contributed to the increases.

Other income, net, increased $8.5 million for 2001, primarily due to a gain on the sale of land, receipt of life insurance proceeds, and income tax adjustments. Other income, net, increased $2.9 million for 2000 due to interest income on temporary cash investments, income related to investments of Allegheny Ventures, and a refund of hydroelectric license fees of $2.8 million ($1.8 million, net of taxes) related to a cancelled facility.

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ALLEGHENY ENERGY, INC.

Interest on long-term debt and other interest for 2001, 2000, and 1999 were as follows:

Interest Expense

(Millions of dollars)

2001

2000

1999

Interest on long-term debt:

  Regulated utility

$155.1

$152.5

$127.5

  Unregulated generation

58.7

34.9

29.2

  Eliminations

(.5)

(14.7)

(1.5)

    Total interest on long-term debt

213.3

172.7

155.2

Other interest:

  Regulated utility

34.5

49.8

27.9

  Unregulated generation

56.2

10.7

3.7

  Other unregulated

.4

.3

  Eliminations

(21.1)

(4.2)

    Total other interest

70.0

56.6

31.6

        Total interest expense

$283.3

$229.3

$186.8

The increases in total interest on long-term debt of $40.6 million and $17.5 million for 2001 and 2000, respectively, resulted from increased average long-term debt outstanding.

The 2001 elimination between regulated utility operations' and unregulated generation operations' interest on long-term debt is to remove the effect of pollution control debt interest recorded by both Allegheny Energy Supply and Monongahela Power. Allegheny Energy Supply assumed the service obligation for the pollution control debt in conjunction with the transfer of Monongahela Power's Ohio and FERC jurisdictional generating assets. Monongahela Power continues to be a co-obligor with respect to this debt.

The 2000 elimination between regulated utility operations' and unregulated generation operations' interest on long-term debt is to remove the effect of pollution control debt interest recorded by Allegheny Energy Supply, West Penn, and Potomac Edison. Allegheny Energy Supply assumed the service obligation for this debt in conjunction with the transfer of West Penn and Potomac Edison's generating assets. West Penn and Potomac Edison continued to be co-obligors with respect to this debt through December 22, 2000.

Other interest expense reflects changes in the levels of short-term debt maintained by the companies throughout the year, as well as the associated interest rates. The increase in other interest expense of $13.4 million for 2001 resulted primarily from greater short-term debt outstanding, as a result of a $550-million bridge loan that will be refinanced with a long-term source of financing in 2002. Other interest expense increased by $25 million in 2000, due to an increase in the average short-term debt outstanding and higher average interest rates.

For additional information regarding the Company's short-term and long-term debt, see the consolidated statement of capitalization and Notes H and P to the consolidated financial statements.

Dividends on the preferred stock of the subsidiaries for 2000 decreased due to the redemption by Potomac Edison and West Penn of their cumulative preferred stock on September 30, 1999, and July 15, 1999, respectively.

Minority Interest
Minority interest was $2.3 million for 2001, which represented Merrill Lynch's 1.967-percent equity membership interest in Allegheny Energy Supply. In March 2001, Allegheny Energy Supply acquired an energy trading business for $489.2 million plus the issuance of a 1.967-percent equity membership interest in Allegheny Energy Supply. By order dated May 30, 2001, the SEC authorized the issuance of an equity membership interest in Allegheny Energy Supply to Merrill Lynch. Effective June 29, 2001, the transaction was completed. See Note E to the consolidated financial statements for additional information.

Extraordinary Charges
The extraordinary charge in 2000 of $77 million, net of taxes, reflects a write-off by the Company's subsidiaries, Monongahela Power 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.

M-20

ALLEGHENY ENERGY, INC.

The extraordinary charge in 1999 of $27 million, after taxes, was required to reflect a write-off of $17 million, after taxes, related to the Maryland PSC's approval in December 1999 of a deregulation plan for Potomac Edison and $10 million, after taxes, for the difference between the reacquisition price and the net carrying amount of first mortgage bonds repurchased as a result of the deregulation process in Pennsylvania. See Notes B, C, and F to the consolidated financial statements for additional information regarding the extraordinary charges.

Cumulative Effect of Accounting Change
Allegheny Energy 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, Allegheny Energy Supply recorded a charge of $31.1 million against earnings, net of the related tax effect ($52.3 mil-lion, before tax) for these contracts as a change in accounting principle on January 1, 2001. See Note J to the consolidated financial statements for additional information.

Other Comprehensive Income
Other comprehensive income includes available-for-sale securities and cash flow hedges. Other comprehensive income includes an unrealized loss, net of tax, on available-for-sale securities of $.1 million and $1.3 million for 2001 and 2000, respectively. In addition, other comprehensive income includes an unrealized loss, net of reclassification to earnings and tax, on cash flow hedges of $18.9 million for 2001. See Note D 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, the Company 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, the companies' cash needs, and capital structure objectives of the Company. The availability and cost of external financings depend upon the financial condition of the companies seeking those funds and market conditions.

During 2001, the Company issued $1.2 billion of long-term debt and issued 14.3 million shares of common stock, resulting in net proceeds of approximately $667 million primarily to finance its acquisition of an energy trading business and three generating facilities in the Midwest. The Company anticipates further financings to support future acquisitions and capital expenditures, while maintaining working capital. In addition, the Company's wholesale marketing, energy trading, fuel procurement, and risk management activities require direct and indirect credit support. As of December 31, 2001, the Company had total indebtedness of $4.8 billion.

The Company's ability to meet its payment obligations under its indebtedness, fund capital expenditures, and maintain adequate direct and indirect credit support will depend on its future operations. The Company's future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control, as discussed in "Factors That May Affect Future Results" on page M-1. The Company's future performance could affect its ability to maintain its investment grade credit rating. The Company and Allegheny Energy Supply have 364-day credit facilities totaling $1.3 billion, which require them to maintain an investment grade credit rating. The failure of the borrower, or, in the case of one of the Company's credit facilities for $50 million, the borrower and Allegheny Energy Supply, to maintain an investment grade credit rating constitutes an event of default as defined in the credit agreements. An event of default could result in the termination of the lending banks' commitments under the credit agreements and require the Company or Allegheny Energy Supply to immediately repay the principal and accrued interest on the agreements. These credit facilities will expire and be replaced by the Company by the end of the second quarter of 2002. To the extent that Allegheny Energy Supply does not maintain its current credit rating, it might be required to provide alternative and/or additional collateral to certain energy trading counterparties. The amount of collateral required is also affected by market price changes for electricity, natural gas, and other energy-related commodities. Such collateral might be in the form of letters of credit, cash deposits, or liquid securities. The requirement to provide additional collateral could have an adverse effect on the Company's liquidity. As of December 31, 2001, the Company had received $4.5 million of cash collateral from and provided $16.8 million of cash collateral with counterparties involved in the Company's energy trading activities.

The Company and certain of its subsidiaries have established credit facilities, or lines of credit, which provide for direct borrowings, a backstop to commercial paper programs, and the issuance of letters of credit to support general corporate purposes and energy trading activities. These facilities require the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio. At December 31, 2001, $126 million of the $865 million lines of credit with banks were drawn. Of the $739 million remaining lines of credit, $474 million was supporting commercial paper and $265 million was unused.

M-21

ALLEGHENY ENERGY, INC.

The Company and certain of its subsidiaries have also executed letter of credit facilities to provide for additional capacity of $425.7 million. Allegheny Energy Supply regularly posts cash deposits or letters of credit with counterparties to collateralize a portion of its energy trading obligations. At December 31, 2001, there was $223.4 million outstanding under the Company's letter of credit facilities.

These lines of credit, letters of credit, and certain other financing agreements contain pricing grids that are contingent upon the Company's credit rating. The pricing grids result in an increase in pricing if the Company's credit rating deteriorates.

The Company 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. This table does not include capacity contract commitments that were accounted for under fair value accounting, as discussed under "Sales and Revenues" starting on page M-12, or contingencies.

Payments Due by Period

Contractual Cash Obligations and Commitments

Less than
1 year

2 - 3 years

4 - 5 years

After 5 years

Total

(Millions of dollars)

Long-term debt*

$353.1

$  651.7

$  866.1

$1,695.3

$ 3,566.2

Capital lease obligations

12.5

19.9

13.3

12.9

58.6

Operating lease obligations

21.8

55.5

98.4

461.9

637.6

PUPRA power sales

  agreements

214.5

406.2

407.2

4,593.5

5,621.4

Fuel purchase commitments

361.6

646.6

360.7

14.2

1,383.1

Total

$963.5

$1,779.9

$1,745.7

$6,777.8

$11,266.9

*Long term debt does not include unamortized debt expense, discounts, and premiums.

The Company's capital expenditures, including construction expenditures, of all of the subsidiaries for 2002 and 2003, are estimated at $636.5 million and $660.0 million, respectively. These estimated expenditures include $219.5 million and $191.7 million, respectively, for environmental control technology. Future unregulated generation operations construction expenditures will support additions of generating capacity to sell into deregulated markets. As described under "Environmental Issues" starting on pageM-27, the subsidiaries could face significant mandated increases in capital expenditures and operating costs related to environmental issues. See Note S to the consolidated financial statements for additional information.

Capital expenditures, including construction expenditures, of all of the subsidiaries were $463.3 million, $402.4 million, and $411.5 million for 2001, 2000, and 1999, respectively. In 2001, Allegheny Energy Supply paid $489.2 million for the acquisition of an energy trading business, $78 million for the acquisition of an interest in the Conemaugh Generating Station, and $1.1 billion for the acquisition of three generating stations in the Midwest. In 2001, Allegheny Ventures also paid $30.5 million to acquire Fellon-McCord and Alliance Energy Services. In 1999, Monongahela Power acquired the assets of West Virginia Power for approximately $95 million, and, in 2000, purchased Mountaineer Gas for approximately $326 million (which included the assumption of $100.1 million in existing debt).

Cash Flow
Internal generation of cash, consisting of cash flows from operations reduced by common and preferred dividends, was $139.8 million in 2001, compared with $349.8 million in 2000.

Cash flows from operations in 2001 declined by $202.8 million. The Company's cash flows from operations include the results of its energy trading activities, reflecting the acquisition of the energy trading and marketing business of Merrill Lynch in March 2001. For 2001, the energy trading activities have resulted in approximately $223.2 million of cash outflows. See "Sales and Revenues" starting on page M-12 for additional details regarding the cash outflows for the energy trading activities.

Cash flows used in investing increased by $1.5 billion for 2001. In 2001, Allegheny Energy Supply paid approximately $1.7 billion for the acquisition of an energy trading business, an interest in a generating facility, and the purchase of three generating facilities in the Midwest. 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.

M-22

ALLEGHENY ENERGY, INC.

Cash flows provided by financing increased by $1.8 billion for 2001, due primarily to $670.5 million net proceeds for the issuance of common stock, $707.6 million net increase in proceeds from the issuance of long-term debt, and $451.2 million increase in short-term financing.

Cash flows from operations in 2000 declined by $84.9 million, reflecting an increase in accounts receivable, net of $105.1 million and partially offset by a $52-million increase in accounts payable, a $21.4-million decrease in deferred revenues, and a $58.1-million decrease in deferred power costs, net.

Cash flows used in investing increased by $121.1 million for 2000, reflecting an increase in the acquisition of businesses of $130.1 million, due to the acquisition of Mountaineer Gas in August of 2000. Construction expenditures were $402.4 million for 2000, compared to $411.5 million for 1999.

Cash flows provided by financing increased by $109.6 million for 2000. In 1999, the Company repurchased common stock for $398.4 million and retired preferred stock of $96.1 million. The Company's issuance of long-term debt for 2000 declined by $345.2 million, and its retirement of long-term debt for 2000 decreased by $238.2 million.

Dividends paid on common stock in each of the years 2001 and 2000 were $1.72 per share. The dividend payout ratio in 2001 of 46.5 percent, excluding the cumulative effect of an accounting change, decreased from the 60.6-percent ratio in 2000, excluding the extraordinary and other charges.

Financing

Common Stock
On May 2, 2001, the Company 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 million was used to partially fund Allegheny Energy Supply's acquisition of generating facilities located in the Midwest. Of the 14.3 million shares of common stock sold, 12 million shares related to treasury stock that had been repurchased by the Company in 1999, under the Company's stock repurchase program, at an aggregate cost of $398.4 million. In March 1999, the Company announced a stock repurchase program that authorized the repurchase of common stock worth up to $500 million from time to time at price levels the Company deemed attractive. Also during 2001, the Company issued .6 million shares of common stock for $23.2 million primarily under its Dividend Reinvestment and Stock Purchase Plan and its Employee Stock Ownership and Savings Plan. There were no shares of common stock purchased in 2001 and 2000.

Long-term Debt
The Company's long-term debt increased by $833.8 million to $3,553.5 million on December 31, 2001. The Company issued the following long-term debt during 2001:

     -   In November 2001, Allegheny Energy Supply borrowed $380 million at 8.13 percent under a credit agreement due to mature on November
         15, 2007;

     -   In November 2001, Potomac Edison issued debt of $100 million five-percent notes due on November 1, 2006;

     -   In October 2001, Monongahela Power issued $300 million five-percent first mortgage bonds due October 1, 2006;

     -   In June 2001, AFN Finance Company No. 2, LLC, a subsidiary of ACC, borrowed $10.5 million under a variable rate credit facility
         guaranteed by the Company with a maturity date of June 30, 2006; and

     -   In March 2001, Allegheny Energy Supply issued $400 million of unsecured 7.80-percent notes due 2011.

In 2001, the Company redeemed $100 million of first mortgage bonds, $85.5 million of Quarterly Income Debt Securities (QUIDS), $100 million of a senior secured credit facility, and $60.2 million of transition bonds, and also made repayments on unsecured notes of $10.5 million. See Note P to the consolidated financial statements for additional details regarding long-term debt issued and redeemed during 2001 and 2000 and additional capital requirements for debt maturities.

The long-term debt due within one year at December 31, 2001, of $353.1 million represents $25 million of Monongahela Power's first mortgage bonds; $70.3 million of West Penn Funding, LLC's, transition bonds; $.1 million of Mountaineer Gas' secured notes; $8.6 million of Monongahela Power's, Mountaineer Gas', and Allegheny Energy Supply's unsecured notes; and $249.1 million of West Penn's and Allegheny Energy Supply's medium-term debt. The

M-23

ALLEGHENY ENERGY, INC.

transition bonds are supported by an Intangible Transition Charge (ITC) that replaces a portion of the 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. Of the $249.1 million medium-term debt due within one year, $135.6 million is related to Allegheny Energy Supply's loan with the nonaffiliated special purpose entity as part of the St. Joseph lease transaction. The classification of this debt as due within one year is based upon the project cost funding requirements, which are subject to change, as discussed under "Operating Lease Transactions" on page M-24.

Short-term Debt
Short-term debt increased by $516.5 million to $1.2 billion in 2001 and consists of commercial paper borrowings of $562.7 million, notes payable of $126 million, and a $550-million bridge loan used to purchase the Midwest generating assets on May 3, 2001. The Company intends to refinance a significant portion of these obligations with long-term financing during 2002. At December 31, 2001, $126 million of the $865 million lines of credit with banks were drawn. Of the $739 million remaining lines of credit, $474 million was supporting commercial paper and $265 million was unused.

Short-term debt increased $81.1 million to $722.2 million in 2000 and consisted of commercial paper borrowings of $672.2 million and notes payable of $50 million. At December 31, 2000, $50 million of the $615 million lines of credit with banks were drawn. The remainder of the unused lines of credit of $565 million were committed to support outstanding commercial paper.

Operating Lease Transactions
In November 2001, Allegheny Energy Supply entered into an operating lease transaction, known as the St. Joseph lease transaction, in connection with a 630-MW, intermediate-load and peaking natural gas-fired facility located in St. Joseph County, Indiana. The St. Joseph lease transaction was structured to finance the construction of both the peaking and intermediate facility with a maximum commitment amount of $460 million. Allegheny Energy Supply will lease the facility from a nonaffiliated special purpose entity when the construction has been completed. Lease payments, to be recorded as rent expense, are estimated at $2.8 million per month, commencing on final completion of the entire facility in 2005 and continuing through November 2007. If Allegheny Energy Supply is unable to renew the lease in November 2007, it must either purchase the facility for the lessor's investment, or terminate the lease, abandon and release its interest in the facility, or sell the facility and pay the amount, if any, by which the lessor's investment exceeds the sale proceeds, up to a maximum recourse amount of approximately $392 million. Based on costs incurred on the project through December 31, 2001, Allegheny Energy Supply's maximum recourse obligation was $22.2 million, reflecting a lessor investment of $29.2 million.

In April 2001, Allegheny Energy Supply entered into an operating equipment lease transaction structured to finance the purchase of turbines and transformers with a maximum commitment amount of $150 million. The St. Joseph lease transaction included a transfer between lessors of some of the equipment previously financed in this lease. As a result, the commitment in the equipment lease has been reduced to approximately $42 million. The remainder of the equipment financed in the lease will be used for another project. During 2002, Allegheny Energy Supply plans to purchase this equipment for the amount of the lessor's investment, which was $29.6 million on December 31, 2001.

Included in the St. Joseph lease transaction is a loan to Allegheny Energy Supply of $380 million from the nonaffiliated special purpose entity. Allegheny Energy Supply is required to repay the loan during the construction period of the leased facility, based on project cost funding requirements. Loan repayments were $7.2 million in 2001 and are estimated to be $135.6 million in 2002, $175.9 million in 2003, and $61.3 million in 2004. On the closing date of the St. Joseph lease transaction, Allegheny Energy Supply repaid approximately $4.0 million of the loan and used approximately $376.0 million of the net proceeds to refinance existing short-term debt. At December 31, 2001, Allegheny Energy Supply recorded $135.6 million and $237.2 million as short-term and long-term debt, respectively, based on the project cost funding requirements, which are subject to change. This loan is required to be repaid if the lease balance or maximum recourse amount becomes payable under the lease.

In November 2000, Allegheny Energy Supply entered into an operating lease transaction relating to the construction of a 540-MW, combined-cycle generating facility located in Springdale, Pennsylvania. This transaction was structured to finance the construction of the facility with a maximum commitment amount of $318.4 million. Upon completion of the facility, a special purpose entity will lease the facility to Allegheny Energy Supply. Lease payments, to be recorded as rent expense, are estimated at $1.9 million per month, commencing during the second half of 2003 through November 2005. Subsequently, Allegheny Energy Supply has the right to negotiate a renewal of the lease. If Allegheny Energy Supply is unable to renew the lease in November 2005, it must either purchase the facility for the lessor's investment, or sell the facility and pay the difference between the proceeds and the lessor's investment up to a maximum recourse amount of approximately $275 million. Based on costs incurred on the project through December 31, 2001, Allegheny Energy Supply's maximum recourse obligation was approximately $120 million, reflecting a lessor investment of $133.7 million.

M-24

ALLEGHENY ENERGY, INC.

These operating lease transactions contain certain covenants, including maximum debt-to-capitalization ratios, which require compliance in order to avoid defaults and acceleration of payments. An event of default could require Allegheny Energy Supply to pay 100 percent of the lessor's investment.

The lease transactions for the St. Joseph and Springdale facilities were classified as operating leases, which were off balance sheet, as of December 31, 2001, in accordance with GAAP. However, a change in the accounting standards applicable to leases could result in the consolidation of the related special purpose entities, with the debt issued by the special purpose entities included in the Company's debt. As of December 31,2001, the effect of consolidating these special purpose entities would be to increase debt by $167.3 million.

Energy Trading Business Acquisition
The purchase agreement for Merrill Lynch's energy trading business provides that the Company shall use its best efforts to contribute to Allegheny Energy Supply the generating capacity from Monongahela Power's West Virginia jurisdictional generating assets by September 16, 2002. If, after using its best efforts to comply with this provision of the purchase agreement, the Company is prohibited by law from contributing to Allegheny Energy Supply substantially all of the economic benefits associated with such assets, then Merrill Lynch shall have the right to require the Company to repurchase all, but not less than all, of Merrill Lynch's equity interest in Allegheny Energy Supply for $115 million plus interest calculated from March 16, 2001.

The purchase agreement also provides that, if the Company has not completed an IPO involving Allegheny Energy Supply within two years of March 16, 2001, Merrill Lynch has the right to sell its equity interest in Allegheny Energy Supply to the Company for $115 million plus interest from March 16, 2001.

SIGNIFICANT CONTINUING ISSUES
Electric Energy Competition
The electricity supply segment of the energy industry in the United States is becoming increasingly competitive. The national Energy Policy Act of 1992 led to market-based regulation of the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. The Company continues to be an advocate of federal legislation to remove artificial barriers to competition in electricity markets, avoid regional dislocations, and ensure a level playing field.

In addition to the wholesale electricity market becoming more competitive, certain states have taken active steps toward allowing retail customers the right to choose their electricity supplier.

The Company is at the forefront of state-implemented retail competition, having negotiated settlement agreements in all of the states that Monongahela Power, Potomac Edison, and West Penn serve. Pennsylvania, Maryland, Virginia, and Ohio have retail choice programs in place. West Virginia's Legislature has approved a deregulation plan, pending additional legislation regarding tax revenues for state and local governments and allowing implementation. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider the deregulation plan in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

The regulatory environment applicable to the Company's generation and T&D businesses will continue to undergo substantial changes on both the federal and state level. These changes have significantly affected the nature of the electric industry and the manner in which its participants conduct their business. Moreover, existing statutes and regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to the Company or its facilities, and future changes in laws and regulations may have an effect on the Company in ways that cannot be predicted. Some markets, like California, have experienced interruptions of supply and price volatility, which have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some markets, including California, government agencies and other interested parties have made proposals to re-regulate areas of these markets that have been deregulated, and, in California, legislation has been passed placing a moratorium on the sale of generating facilities by regulated utilities. Proposals to re-regulate the wholesale power market have been made at the federal level. Proposals of this sort, and legislative or other attention to the electric power restructuring process in the states in which the Company currently operates, or may in the future operate, may cause deregulation to be delayed, discontinued, or reversed, which could have a material effect on the Company's operations and strategies.

The recent bankruptcy filing by Enron may affect the regulatory and legislative process. In response to the Enron bankruptcy filing and the September 11 terrorists' attacks, financial markets have been disrupted in general, and the availability and cost of capital for the Company's business and that of its competitors has been adversely affected. Following the Enron bankruptcy filing, credit ratings agencies reviewed the capital structure and earnings power of

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ALLEGHENY ENERGY, INC.

energy companies, including the Company. These events have constrained the capital available to the industry and could adversely affect the Company's access to funding for its operations.

Activities at the Federal Level
The terrorists' attacks of September 11 have altered the agenda of the 107th Congress. In fact, some legislative initiatives have been delayed or postponed since that date because the Congress and the Bush Administration have been focused on responding to these attacks. However, part of that response may well be the consideration of energy security legislation currently in development. The Company is lobbying for the inclusion of important electricity restructuring provisions in this legislation, including the repeal or significant revision of PUHCA , as well as for critical infrastructure protection legislation. Prior to the attacks, two primary bills had been introduced in the U.S. Senate: S. 388, by former Energy and Natural Resources Committee Chairman Senator Frank Murkowski of Alaska, and S. 597, by the committee's new chairman, Senator Jeff Bingaman of New Mexico. Provisions from these bills could be included in the new energy legislation. The primary House committee of jurisdiction, Energy and Commerce, initially passed the President's national energy security proposal and is only now considering accompanying electricity restructuring legislation. Among issues that are being addressed in this legislation are the repeal or significant revision of PUHCA and Section 210 (Mandatory Purchase Provisions) of PURPA. The Company continues to advocate the repeal of PUHCA and Section 210 of PURPA on the grounds that they are obsolete and anticompetitive and that PURPA results in utility customers paying above-market prices for power. Separately, the Senate Banking Committee in April 2001 approved S. 206, legislation to repeal PUHCA.

Maryland Activities
On June 7, 2000, the Maryland PSC approved the transfer of the generating assets of Potomac Edison to Allegheny Energy Supply. The transfer was completed in August 2000. Maryland customers of Potomac Edison have had the right to choose an alternate electric supplier since July 1, 2000. While few customers have switched suppliers in Potomac Edison's service territory, some retail competition is occurring in other portions of the state.

On July 1, 2000, the Maryland PSC issued a restrictive order imposing standards of conduct for transactions between Maryland utilities and their affiliates. Among other things, the order:

-      restricts sharing of employees between utilities and unregulated affiliates;

-      announces the Maryland PSC's intent to impose 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 unqualified benefits; and

-      requires asymmetric pricing for asset transfers between utilities and their affiliates. Asymmetric pricing requires that transfers of
       assets from the regulated utility to an affiliate be recorded at the greater of book cost or market value, while transfers of assets
       from the affiliate to the regulated utility be recorded at the lesser of book cost or market value.

Potomac Edison, along with substantially all of Maryland's natural gas and electric utilities, filed a Circuit Court petition for judicial review and a motion for a stay of the order. On April 25, 2001, the Circuit Court issued its decision affirming much of the Maryland PSC's order, but remanding portions of the order to the Maryland PSC, including the requirement for asymmetric pricing for asset transfers between utilities and their affiliates.

Potomac Edison and other Maryland natural gas and electric utilities have noted an appeal of the Circuit Court's decision to Maryland's Court of Special Appeals. The Court of Appeals, Maryland's highest court, assumed jurisdiction over the appeal. After the filing of briefs, the Court of Appeals heard oral arguments on January 8, 2002.

The Maryland PSC also has initiated a proceeding, Case No. 8868, to investigate certain affiliated activities of Potomac Edison and has also docketed similar proceedings for Maryland's other natural gas and electric companies. Case No. 8868 is pending before a Maryland PSC Hearing Examiner.

The Maryland PSC has initiated a proceeding, Case No. 8907, to investigate Potomac Edison's proposed revisions to its line extension charges and policies for non-residential customers. The Maryland PSC delegated the proceeding to the Hearing Examiner Division. The Hearing Examiner held a prehearing conference on January 10, 2002, and established a procedural schedule. The parties are entering into settlement discussions.

By letter order dated December 17, 2001, the Maryland PSC directed parties to commence meetings on January 17, 2002, on the status of the provision of default service. Potomac Edison is participating in those meetings.

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ALLEGHENY ENERGY, INC.

Ohio Activities
The Ohio General Assembly passed legislation in 1999 to restructure its electric utility industry. As of January 1, 2001, all of the state's electricity consumers were able to choose their electricity supplier, beginning a five-year transition to market rates. Residential customers are guaranteed a five-percent reduction in the generation portion of their rate.

Monongahela Power reached a stipulated agreement with major parties on a transition plan to bring electric choice to its 29,000 Ohio customers. None of Monongahela Power's Ohio customers has switched to another supplier. The restructuring plan allowed the Company to transfer its Ohio and FERC jurisdictional generating assets to Allegheny Energy Supply at book value. That transfer was made on June 1, 2001.

Pennsylvania Activities
As of January 2, 2000, all electricity customers in Pennsylvania have the right to choose their electric generation supplier. The number of customers who have switched to another supplier and the amount of electrical load transferred in Pennsylvania exceed that of any other state. However, West Penn had retained more than 99.8 percent of its Pennsylvania customers as of December 31, 2001.

As part of West Penn's restructuring settlement in Pennsylvania, West Penn retains the obligation to serve all customers who choose not to select an alternate supplier (provider of last resort) at rates that are capped at 1997 levels. The generation rates are capped through 2008.

Virginia Activities
The Virginia Electric Utility Restructuring Act (Restructuring Act) became law on March 25, 1999. All state utilities were required to submit a restructuring plan by January 1, 2001, to be effective on January 1, 2002. On December 21, 2001, the Virginia SCC approved Potomac Edison's Phase II of the Functional Separation Plan. In August 2000, Potomac Edison transferred its Virginia jurisdictional generating assets, excluding the hydroelectric assets located within Virginia, to Allegheny Energy Supply at book value. Customer choice was implemented for all customers in Potomac Edison's service territory beginning on January 1, 2002.

The Restructuring Act was amended during the 2000 General Assembly legislative session to direct the Virginia SCC to prepare for legislative approval a plan for competitive metering and billing and to authorize the Virginia SCC to implement a consumer education program on electric choice, funded through its regulatory tax. On December 12, 2000, the Virginia SCC issued a report on competitive metering and billing. Its recommendations include allowing licensed electricity suppliers to provide billing services, with the customer selecting its preferred billing option. The Virginia SCC also recommended that legislative action on competitive metering be deferred, pending further study, due to the complexities of the issue and limited competitive metering activities nationally. On May 15, 2001, the Virginia SCC initiated proceedings to establish rules and regulations for consolidated billing services, competitive metering, and customer minimum stay periods.

Various rulemaking proceedings to implement customer choice are ongoing before the Virginia SCC, including an application by Potomac Edison to participate in a regional transmission entity (PJM West).

West Virginia Activities
Electric restructuring in West Virginia remains unresolved and awaits further legislative action. In January 2000, the West Virginia PSC submitted a restructuring plan to the Legislature for approval that would open full retail competition on January 1, 2001. On March 11, 2000, the West Virginia Legislature approved the West Virginia PSC's plan, but assigned the tax issues surrounding the plan to a legislative subcommittee for further study. The start date of competition is contingent upon the necessary tax changes being made and implementation being approved by the Legislature. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider the deregulation plan in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

As approved by the West Virginia PSC, Potomac Edison transferred its generating assets to Allegheny Energy Supply in August 2000. In accordance with the same restructuring agreement, Potomac Edison and Monongahela Power implemented a commercial and industrial rate reduction program on July 1, 2000.

Environmental Issues
The Environmental Protection Agency's (EPA) nitrogen oxides (NO_X ) State Implementation Plan (SIP) call regulation has been under litigation, and, on March 3, 2000, the United States Court of Appeals issued a decision that upheld the regulation. However, state and industry litigants filed an appeal of that decision in April 2000. On June 23, 2000, the Court denied the request for the appeal. Although the Court did issue an order to delay the compliance date from May 1, 2003, until May 31, 2004, both the Maryland and Pennsylvania state rules to implement the EPA NO_X SIP call regulation still require compliance by May 1, 2003. West Virginia has issued a proposed rule that would require compliance by May 31, 2004. However, the EPA Section 126 petition regulation also

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ALLEGHENY ENERGY, INC.

requires the same level of NO_X reductions as the EPA NO_X SIP call regulation with a May 1, 2003, compliance date. The EPA Section 126 petition rule is also under litigation in the United States Court of Appeals. A Court decision in May 2001 upheld the rule. In August 2001, the Court issued an order that suspends the Section 126 petition rule May 1, 2003, compliance date pending EPA review of growth factors used to calculate the state NO_X budgets. The Company's compliance with such stringent regulations will require the installation of expensive post-combustion control technologies on most of its power stations. The Company's construction forecast includes the expenditure of $244.7 million of capital costs during the 2002 through 2003 period to comply with these regulations.

On August 2, 2000, the Company received a letter from the EPA requiring it to provide certain information on the following 10 electric generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island. Allegheny Energy Supply and Monongahela Power now own these electric generating stations. The letter requested information under Section 114 of the federal Clean Air Act to determine compliance with the Act and state implementation plan requirements, including potential application of the federal New Source Review (NSR). In general, these standards can require the installation of additional air pollution control equipment upon the major modification of an existing facility. The Company submitted these records in January 2001. The eventual outcome of the EPA investigation is unknown.

Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in many cases. The Company believes its generating facilities have been operating in accordance with the Clean Air Act and the rules implementing the Act. The experience of other utilities, however, suggests that, in recent years, the EPA may well have revised its interpretation of the rules regarding the determination of whether an action at a facility constitutes routine maintenance, which would not trigger the requirements of NSR, or a major modification of the facility, which would require compliance with NSR. If federal NSR were to be applied to these generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. In connection with the deregulation of generation, the Company has agreed to rate caps in each of its jurisdictions, and there are no provisions under those arrangements to increase rates to cover such expenditures.

In December 2000, the EPA issued a decision to regulate coal- and oil-fired electric utility mercury emissions under Title III, Section 112 of the 1990 Clean Air Act Amendments (CAAA). The EPA plans to issue a proposed regulation by December 2003 and a final regulation by December 2004. The timing and level of required mercury emission reductions are unknown at this time.

Other Litigation
In the normal course of business, the Company and its subsidiaries become involved in various legal proceedings. The Company and its subsidiaries do not believe that the ultimate outcome of these proceedings will have a material effect on their financial position. See Note S for additional information regarding environmental matters and litigation, including asbestos litigation and FERC proceedings in California.

Derivative Instruments and Hedging Activities
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 was subsequently 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." Effective January 1, 2001, the Company implemented the requirements of these accounting standards.

These standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. They require 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 the 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. SFAS No. 133 is expected to increase the volatility in reported earnings and other comprehensive income.

On January 1, 2001, Allegheny Energy 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. Allegheny Energy Supply had two principal risk management objectives regarding these cash flow hedge contracts. First, Allegheny Energy Supply has a contractual obligation to serve the instantaneous demands of its customers. When this instantaneous demand exceeds Allegheny Energy Supply's electric generating capacity, it must enter into contracts providing for the purchase of electricity to meet this shortage. Second, the price of electricity is subject to volatility. This volatility is the result of many market factors, including the weather, and tends to be the highest during the summer months. To ensure that energy market movements do not cause a significant degradation in earnings, Allegheny Energy Supply enters into fixed-price electricity purchase contracts.

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ALLEGHENY ENERGY, INC.

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

Allegheny Energy 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, Allegheny Energy 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, Allegheny Energy Supply recorded a charge of $31.1 million against earnings, net of the related tax effect ($52.3 million, before tax), 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 as a gain in unregulated generation revenues on the consolidated statement of operations.

On November 1, 2001, Allegheny Ventures completed the acquisition of Fellon-McCord and Alliance Energy Services. Alliance Energy Services is 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, uses 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.

Alliance Energy Services' primary strategy is 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 are accounted for as cash flow hedges, with the fair value of the offsetting contracts recorded as assets and liabilities on the consolidated balance sheet and changes in fair value for these contracts recorded to other comprehensive income. As of December 31, 2001, an unrealized loss of $18.9 million, net of reclassifications to earnings and tax, was recorded to other comprehensive income for these contracts. These hedges were highly effective during 2001. Based on the contracts' fair values at December 31, 2001, and the settlement dates of these contracts, the Company expects to reclassify a loss of approximately $23.1 million, before taxes, of the amount accumulated in other comprehensive income to earnings in 2002, when the related contracts are settled. As of December 31, 2001, the Company's cash flow hedge contracts were hedging forecasted transactions through December 2004 and had a net fair value of $(66.2) million.

Additionally, as a service to its customers, Alliance Energy Services offers price risk intermediation services in order to mitigate the market risk associated with natural gas. Under this program, Alliance Energy Services will execute positions with the customer and enter into offsetting positions with a third counterparty. These transactions do not qualify for hedge accounting under SFAS No. 133 and are accounted for on a mark-to-market basis. At December 31, 2001, the fair value of these contracts as an asset were $31.5 million and the fair value of the contracts as liabilities were $30.6 million.

Quantitative and Qualitative Disclosure About Market Risk
The Company is exposed to market risks associated with commodity prices and interest rates. The commodity price risk exposure results from market fluctuations in the price and transportation costs of electricity, natural gas, and other energy-related commodities. The interest rate risk exposure results from changes in interest rates related to interest rate swaps, commercial paper, and variable- and fixed-rate debt. The Company is mandated by its Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

The Company has a Corporate Energy Risk Policy adopted by its Board of Directors and monitored by a Risk Management Committee chaired by its Chief Executive Officer and composed of senior management. An independent risk management group within the Company actively measures and monitors the risk exposures to ensure compliance with the policy and it is periodically reviewed.

To manage the Company's financial exposure to commodity price fluctuations in its energy trading, fuel procurement, power marketing, natural gas supply, and risk management activities, the Company routinely enters into contracts, such as electricity and natural gas purchase and sale commitments, to hedge its risk exposure. However, the Company does not hedge the entire exposure of its operations from commodity price volatility for a variety of

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ALLEGHENY ENERGY, INC.

reasons. To the extent the Company does not successfully hedge against commodity price volatility, its results of operations and financial position may be affected either favorably or unfavorably by a shift in the future price curves.

Also, the Company's energy trading business enters into certain contracts for the sale of electricity produced by its Midwest generating assets and its other generating facilities in excess of the power provided to its regulated utility subsidiaries to meet their provider of last resort obligations. These contracts are recorded at their fair value and are an economic hedge for the generating facilities. For accounting purposes, the generating facilities are recorded at historical cost less depreciation. As a result, the Company's results of operations and financial position can be favorably or unfavorably affected by a change in future market prices used to value the contracts, since there is not an offsetting adjustment to the recorded cost of the generating facilities.

Of its commodity-driven risks, the Company is primarily exposed to risks associated with the wholesale marketing of electricity, including the generation, fuel procurement, power marketing, and trading of electricity. The Company's wholesale activities principally consist of marketing and trading over-the-counter forward contracts, swaps, and NYMEX futures contracts for the purchase and sale of electricity and natural gas. The majority of these contracts represent commitments to purchase or sell electricity and natural gas at fixed prices in the future. The Company's forward contracts generally require physical delivery of electricity and natural gas. The swap and NYMEX futures contracts generally require financial settlement.

The Company also uses option contracts to buy and sell electricity and natural gas at fixed prices in the future. These option contracts are generally entered into for energy trading and risk management purposes. The risk management activities focus on management of volume risks (supply), operational risks (facility outages), and market risks (energy prices).

A significant portion of the Company's energy trading activities involves long-term structured transactions. During 2001, the Company entered into several long-term contracts as part of its energy trading activities that may affect its market risk exposure. Uncertainty regarding market conditions and
75
commodity prices increases further into the future. The following contracts that extend beyond five years were added to the Company's energy trading portfolio during 2001:

-   In March 2001, Allegheny Energy Supply acquired an energy trading business, including the contractual right to call up to 1,000 MW of generation in California through May 2018;

-   In March 2001, Allegheny Energy Supply signed a power sales agreement with the CDWR, the electricity buyer for the state of California. The contract is for a period through December 2011. Under the terms of the agreement, the Company has committed to supply California with contract volumes, varying from 150 MW to 500 MW, through December 2004. For the last seven years of the contract, the contract volume will be fixed at 1,000 MW. The Company's source for this electricity will be partly through its contractual right to call up to 1,000 MW of generation capacity in California, which the Company acquired as part of the acquisition of an energy trading business;

-   In May 2001, Allegheny Energy Supply signed a 15-year agreement with Las Vegas Cogeneration II, LLC, for 222 MW of generating capacity, beginning in the third quarter of 2002; and

-   The Company has long-term agreements with El Paso Natural Gas Company for the transportation of natural gas that started on June 1, 2001, under tariffs approved by the FERC. These agreements, in part, provide for firm transportation of 7,222 thousand cubic feet (Mcf) of natural gas per day through September 30, 2006, from western Texas and northern New Mexico to the southern California border. The remainder of the agreements provide for firm transportation of 22,322 Mcf per day through September 30, 2009, from western Texas to the southern California border.

The Company's acquisition of Alliance Energy Services, on November 1, 2001, also increased its exposure to market risks associated with the purchase, sale, and transportation of natural gas. As previously discussed (see "Derivative Instruments and Hedging Activities" starting on page M-28), Alliance Energy Services is engaged in the sale and transportation of natural gas to various commercial and industrial customers across the United States. It, on behalf of its customers, uses forwards, NYMEX futures, options, and swaps in order to manage price risk associated with its purchase and sales activities.

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ALLEGHENY ENERGY, INC.

Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. The credit standing of counterparties is established through the evaluation of the prospective counterparty's financial condition, specified collateral requirements where deemed necessary, and the use of standardized agreements, which facilitate netting of cash flows, associated with a single counterparty. Financial conditions of existing counterparties are monitored on an ongoing basis. The Company's independent risk management group oversees credit risk. As of December 31, 2001, the Company has received $4.5 million of cash collateral from counterparties involved in the Company's energy trading activities.

The Company is engaged in various trading activities in which counterparties primarily include electric and natural gas utilities, independent power producers, oil and natural gas exploration and production companies, energy marketers, and commercial and industrial customers. In the event the counterparties do not fulfill their obligations, the Company may be exposed to credit risk. The risk of default depends on the creditworthiness of the counterparty or issuer of the instrument. The Company has a concentration of customers in the electric and natural gas utility and oil and natural gas exploration and production industries. These concentrations in customers may affect the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The following table provides the net fair value of commodity contract asset positions by counterparty credit quality for the Company at December 31, 2001:

76

Credit Quality*

Amount

(Millions of dollars)

Investment grade

$   333.8

Non-investment grade

12.6

No external ratings:

  Government agencies

1,344.8

  Other

64.2

Total

$1,755.4

* Where a parent company provided a guarantee for a counterparty, the Company used the parent company's credit rating.

The net fair value of $1.3 billion, or 11.8 percent of the Company's total assets, for "No external ratings - Government agencies" mainly relates to Allegheny Energy Supply's power sales agreement with the CDWR, the department within the state government of California that is responsible for buying electricity for that state. As of December 31, 2001, the CDWR did not receive a credit rating from an external, independent credit rating agency. On February 21, 2002, the California PUC approved a rate agreement with the CDWR in order for the CDWR to issue bonds to repay the state of California's general fund and other outstanding loans. The agreement would create two streams of revenue for the CDWR by establishing bond charges and power charges on electricity customers. Revenues from power charges will be used to pay the CDWR's operating expenses, including payment of its long-term power purchase agreements. Certain, as yet unspecified, operating expenses of the CDWR will be payable from the bond charge. The rate agreement would require the CDWR to use its best efforts to renegotiate its long-term power agreements and does not limit the ability of the California PUC or the CDWR to engage in litigation regarding those contracts. If the Company's agreement were renegotiated or if the CDWR failed for any reason to meet its obligations under this agreement, the value of the agreement as an asset might need to be reduced on the Company's consolidated balance sheet, with a corresponding reduction in net income. As of December 31, 2001, the CDWR has met all of its obligations under this agreement.

On February 25, 2002, the California PUC filed a complaint with the FERC seeking to abrogate various contracts to which the CDWR is a counterparty, including two contracts with the Company to sell power to the CDWR. The California PUC alleges that the contracts are unjust and unreasonable due to market dysfunction and the exercise of market power by electricity suppliers during 2001 in California. As a result, the California PUC argues that the CDWR was forced to pay prices that are too high and accept onerous terms and conditions. In the alternative, the California PUC requests that the FERC reform the challenged contracts to provide just and reasonable pricing, reduce the duration of the contracts, and eliminate certain non-price items.

The Company believes that its contracts with the CDWR are valid and binding upon the CDWR. The Company is evaluating the complaint filed by the California PUC and will respond to the complaint in the proceeding before the FERC. At this time, the Company cannot predict the outcome of this proceeding.

On December 2, 2001, various Enron entities, including, but not limited to, Enron North America Corporation and Enron Power Marketing, Inc., collectively Enron, filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court for the Southern District of New York.

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ALLEGHENY ENERGY, INC.

Allegheny Energy Supply and Enron have master trading agreements in place, which include an International Swaps and Dealers Association (ISDA) Agreement, a Master Power Purchase and Sale Agreement, and a Master Gas Purchase and Sale Agreement (Agreements). Within all of these Agreements, there is netting and set-off language. This language allows Allegheny Energy Supply and Enron to net and set-off all amounts owed to each other under the Agreements.

Pursuant to the Agreements, the voluntary petition for Chapter 11 reorganization by Enron constituted an event of default. Allegheny Energy Supply effected an early termination as of November 30, 2001, with respect to each of the Agreements, as permitted under the terms of the Agreements.

Allegheny Energy Supply believes it has appropriately exercised its contractual rights to terminate the Agreements and to net out transactions arising within each Agreement. Pursuant to the Bankruptcy Code, Allegheny Energy Supply believes it should be able to offset any termination values or payment amounts owed it against amounts it owes to Enron as a result of the netting. As of November 30, 2001, the fair value of all the Company's trades with Enron that were terminated was a net asset of approximately $27 million and the Company had a net payable to Enron of approximately $25 million. After applying the netting provisions of each Agreement, including any collateral posted by Enron with Allegheny Energy Supply, approximately $4.5 million was expensed as uncollectible in 2001. Allegheny Energy Supply continues to evaluate its Enron transactions on a daily basis.

Market Risk
Market risk arises from the potential for changes in the value of energy related to price and volatility in the market. The Company reduces these risks by using its generating assets and contractual generation under its control to back positions on physical transactions. Aggregate and counterparty market risk exposure and credit risk limits are monitored within the guidelines of the Corporate Energy Risk Policy. The Company evaluates commodity price risk, operational risk, and credit risk in establishing the fair value of commodity contracts.

The Company uses various methods to measure its exposure to market risk, including a value at risk model (VaR). VaR is a statistical model that attempts to predict risk of loss based on historical market price and volatility data over a given period of time. The quantification of market risk using VaR provides a consistent measure of risk across diverse energy markets and products with different risk factors to set the overall corporate risks tolerance, determine risk targets, and positions. The Company calculates VaR using a variance/covariance technique that models option positions, using a linear approximation of their value based upon the options' delta equivalents. Due to inherent limitations of VaR, including the use of approximations to value options, subjectivity in the choice of liquidation period, and reliance on historical data to calibrate the model, the VaR calculation may not accurately reflect the Company's market risk exposure. As a result, the actual changes in the Company's market risk sensitive instruments could differ from the calculated VaR, and such changes could have a material effect on its financial results. In addition to VaR, the Company routinely performs stress and scenario analyses to measure extreme losses due to exceptional events. The VaR and stress test results are reviewed to determine the maximum allowable reduction in the fair value of the energy trading portfolios.

The Company's VaR calculation includes all contracts, whether financially or physically settled, associated with its wholesale marketing and trading of electricity, natural gas, and other commodities. The Company calculates the VaR, including its generating capacity and the power sales agreements for the regulated utility subsidiaries' provider of last resort retail load obligations. The VaR calculation does not include positions beyond three years because there is a limited, observable, liquid market. The VaR calculation also does not include commodity price exposure related to the procurement of fuel for its generation. The Company believes that this represents the most complete calculation of its value at risk.

The VaR amount represents the potential loss in fair value from the market risk sensitive positions described above over a one-day holding period with a 95-percent confidence level. As of December 31, 2001, the Company's VaR was $14.4 million, including its generating capacity and power sales agreements with its regulated utility subsidiaries. For 2001, the Company's average VaR using the same calculation was $38.3 million. The Company also calculated VaR using the full term of all trading positions, but excluded its generating capacity and the provider of last resort retail load obligations of its regulated utility subsidiaries. This calculation includes positions beyond three years for which there is a limited, observable, liquid market. As a result, this calculation is based upon management's best estimates and modeling assumptions, which could materially differ from actual results. As of December 31, 2001, this calculation yielded a VaR of $16.9 million.

At December 31, 2000, the Company's VaR was $38.7 million. This calculation included contracts and positions for the next 12 months and the Company's generating assets, its provider of last resort retail load obligations of its regulated utility subsidiaries, retail, and other similar obligations. This calculation method was used prior to the

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ALLEGHENY ENERGY, INC.

purchase of the energy trading business. As of December 31, 2001, the comparable VaR was $8.1 million. The decrease in VaR for 2001 was primarily due to a reduction in the volatility of energy prices in 2001.

The Company has entered into long-term arrangements with original terms of 12 months or longer to purchase approximately 96 percent of its base coal requirements for its owned generation in 2002. The Company depends on short-term arrangements and spot purchases for its remaining requirements.

New Accounting Standards
In July 2001, the FASB issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." These standards changed the accounting for business combinations and goodwill in two significant ways. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. Use of the pooling-of-interests method will be prohibited. SFAS No. 141 is not expected to a have a material effect on the Company.

SFAS No. 142 changed the accounting for goodwill from an amortization method to an impairment-only approach. Amortization of goodwill, including goodwill recorded in past business combinations, ceased on January 1, 2002. Goodwill will now be tested at least annually for impairment. Intangible assets other than goodwill will continue to be amortized over their useful lives and reviewed for impairment. As of December 31, 2001, the Company had $603.6 million of goodwill. The Company had goodwill amortization in 2001 of $26.3 million. The Company is in the process of evaluating the effect of adopting SFAS No. 142 on its results of operations and financial position and plans to reflect the results of this evaluation in its first quarter 2002 financial statements.

In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This standard, which the Company will adopt on January 1, 2003, requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Over time, the liability will be accreted to its present value each period, and the capitalized cost will be depreciated over the useful life of the asset. Upon settlement of the liability, an entity either will settle the obligation for its recorded amount or incur a gain or loss upon settlement. The Company will be evaluating the effect of adopting SFAS No. 143 on its results of operations and financial position prior to its adoption of the standard.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This standard, which the Company adopted on January 1, 2002, establishes one accounting model for long-lived assets to be disposed of by sale, including discontinued operations, and carries forward the general impairment provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS No. 144 is not expected to have a material effect on the Company.

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and Subsidiaries

MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

FACTORS THAT MAY AFFECT FUTURE RESULTS

Certain statements within constitute forward-looking statements with respect to Monongahela Power Company and its subsidiaries (collectively, the Company). Such forward-looking statements include statements with respect to deregulated activities and movements towards competition in the states served by the Company, markets, products, services, prices, capacity purchase commitments, results of operations, capital expenditures, regulatory matters, liquidity and capital resources, the effect of litigation, and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results of the Company will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

Factors that could cause actual results of the Company to differ materially include, among others, the following: general economic and business conditions, including the continuing effects caused by the September 11, 2001, terrorists' attacks; changes in industry capacity, development, and other activities by the Company's competitors; changes in the weather and other natural phenomena; changes in technology; changes in the price of purchased power and fuel for electric generation; changes in laws and regulations applicable to the Company, its markets, or its activities; litigation involving the Company; environmental regulations; the loss of any significant customers and suppliers; the effect of accounting policies issued periodically by accounting standard-setting bodies; and changes in business strategy, operations, or development plans.

OVERVIEW

The Company is a wholly owned subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and along with its wholly owned subsidiary Mountaineer Gas Company (Mountaineer Gas) and its affiliates, The Potomac Edison Company (Potomac Edison) and West Penn Power Company (West Penn), together doing business as Allegheny Power, operate electric and natural gas transmission and distribution (T&D) systems. Allegheny Power also generates electric energy for its West Virginia jurisdiction, where deregulation of electric generation has not been implemented. The Company's business is the operation of electric T&D systems in Ohio and West Virginia, the operation of natural gas T&D systems in West Virginia, and the generation of electric energy in West Virginia.

The Company has sponsored deregulation plans in both Ohio and West Virginia. A component of the deregulation plans is the authority to transfer, at book value, electric generation to an unregulated affiliate. The Ohio deregulation efforts proved successful when the Public Utilities Commission of Ohio (Ohio PUC), on October 5, 2000, approved a stipulation agreement for the Company. The deregulation efforts for West Virginia remain ongoing. See State Deregulation Efforts and Notes B, C, and D to the consolidated financial statements for detailed discussions of the Company's deregulation efforts.

As a result of the deregulation plans in the various states and the Company's restructuring plan, and in accordance with the guidance of Emerging Issues Task Force (EITF) Issue No. 97-4, "Deregulation of the Pricing of Electricity-Issues Related to the Application of the Financial Accounting Standards Board's (FASB) Statement Nos. 71 and 101," the Company has discontinued the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation", to its electric generation businesses in all of the states in which the Company provides utility service. See Note C to the consolidated financial statements for additional information.

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STATE DEREGULATION EFFORTS

See Notes B, C, and D to the consolidated financial statements for detailed discussions of the Company's deregulation efforts.

Ohio Deregulation

On June 1, 2001, the Company transferred, at book value, the Ohio portion, approximately 352 megawatts (MW), of its generating assets to Allegheny Energy Supply, LLC (Allegheny Energy Supply), the nonutility generating subsidiary of Allegheny Energy. The transfer was approved by the Ohio PUC as part of a settlement that implemented a restructuring plan for the Company. This restructuring plan allowed the Company's Ohio customers to choose their generation supplier effective January 1, 2001. Additionally, the plan provides for the following: residential customers received a five percent reduction in the generation portion of their electric bills during a five-year market development period that continues through December 31, 2005; for commercial and industrial customers, existing generation rates were frozen at the January 1, 2001, rates for the market development period (the market development period continues through December 31, 2003, for large commercial and industrial customers and through December 31, 2005, for small commercial customers); the Company will collect from shopping customers a regulatory transition charge of $0.0008 per kilowatt-hour (kWh) for the market development period; and Allegheny Energy Supply is permitted to offer competitive generation service throughout Ohio.

West Virginia Deregulation

In March 2000, the West Virginia Legislature passed House Resolution 27 approving an electric deregulation plan submitted by the Public Service Commission of West Virginia (West Virginia PSC) with certain modifications. Under the resolution, the implementation of the West Virginia deregulation plan cannot occur until the Legislature enacts certain tax changes regarding the preservation of tax revenues for state and local governments and other changes conforming to the plan and authorizing implementation. The plan provides for all customers to have choice of a generation supplier and allows the Company to transfer, at book value, the West Virginia portion (approximately 2,037 MW of owned capacity and 78 MW of capacity in generating units at which the Company does not exercise control over 100 percent of the facility) of its generating assets to Allegheny Energy Supply. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider the deregulation plan in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

On June 23, 2000, the West Virginia PSC issued an order regarding the transfer of the generating assets of the Company. The June 23, 2000, order permits the Company to submit a petition to the West Virginia PSC seeking approval to transfer its West Virginia generating assets prior to the implementation of the deregulation plan. A filing before implementation of the deregulation plan is required to include commitments to the consumer and other protections contained in the deregulation plan. On August 15, 2000, with a supplemental filing on October 31, 2000, the Company filed a petition seeking West Virginia PSC approval to transfer its West Virginia jurisdictional generating assets to Allegheny Energy Supply. Settlement discussions regarding the generating asset transfer are ongoing.

In addition to the Company's deregulation efforts, the Company has been expanding its customer base through the acquisitions of Mountaineer Gas in August 2000 and West Virginia Power Company (West Virginia Power) in December 1999.

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OTHER SIGNIFICANT EVENTS IN 2001, 2000, AND 1999

Initial Public Offering of Allegheny Energy Supply

On July 23, 2001, Allegheny Energy filed a U-1 application with the Securities and Exchange Commission (SEC), seeking authorization under the Public Utility Holding Company Act of 1935 (PUHCA) to effect an initial public offering (IPO) of up to 18 percent of the common stock in a new holding company, which would own 100 percent of Allegheny Energy Supply, and then distribute the remaining common stock owned by Allegheny Energy to its shareholders on a tax-free basis. In October 2001, Allegheny Energy announced that the proposed IPO would be delayed due to market and other conditions. In January 2002, Allegheny Energy announced that it would not proceed with the IPO. In February 2002, Allegheny Energy filed an amendment to the U-1 application filed with the SEC on July 23, 2001, withdrawing its IPO application.

Acquisitions

On August 18, 2000, the Company completed the purchase of Mountaineer Gas, a regulated natural gas sales, transportation, and distribution company serving a large portion of West Virginia, from Energy Corporation of America (ECA) for $325.7 million, which included the assumption of $100.1 million of existing long-term debt. The acquisition included the assets of Mountaineer Gas Services, Inc. (Mountaineer Gas Services), which operates natural gas-producing properties, natural gas-gathering facilities, and intrastate transmission pipelines. The acquisition increased the Company's number of natural gas customers in West Virginia by approximately 200,000. See Note E to the consolidated financial statements for additional information.

In December 1999, the Company purchased from UtiliCorp United, Inc. the assets of West Virginia Power, an electric and natural gas distribution company located in southern West Virginia, for approximately $95 million. The West Virginia Power acquisition added approximately 26,000 electric distribution customers and 24,000 natural gas customers.

Rate Matters

The Company and its affiliates are subject to federal and state regulations, including the PUHCA. Allegheny Power's markets for regulated electric and gas retail sales are in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia.

On June 23, 2000, the West Virginia PSC approved a Joint Stipulation and Agreement for Settlement, stating agreed-upon rates designed to make the rates of Potomac Edison and the Company consistent. Under the terms of the settlement, several tariff schedules, notably those available to residential and small commercial customers, will require several incremental steps to reach the agreed-upon rate level. The settlement rates resulted in a revenue reduction of approximately $.5 million for 2000, increasing over eight years to an annual reduction of approximately $6.0 million. Offsetting the decrease in rates, the settlement approved by the West Virginia PSC directs the Company to amortize the existing over-collected deferred fuel balance as of June 30, 2000 (approximately $6.0 million), as a reduction of expenses over a four-and-one-half year period beginning July 1, 2000. Also, effective July 1, 2000, the Company ceased its expanded net energy cost (fuel clause) as part of the settlement.

On October 11, 2000, the West Virginia PSC approved an interim increase of the commodity rate for natural gas customers of the Company, formerly West Virginia Power customers, for natural gas service bills rendered on and after December 1, 2000. On December 11, 2000, the West Virginia PSC approved additional increases for bills rendered on and after January 1, 2001, through November 30, 2001 (total revenue increase for the twelve-month period of $5.7 million or 25.1 percent for the commodity rate). The commodity rate, or the Purchased Gas Adjustment (PGA) rate, is the portion of the bill that reflects the cost of gas, which increased significantly during 2000. The West Virginia PSC approved a tiered

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rate structure, with rates established for the winter heating season, effective January 1, 2001, through April 30, 2001, and further increased rates effective May 1, 2001, through November 30, 2001, dependent upon the level of cost recovery after the winter heating season. This approach allowed the Company full recovery of these costs, but eased the increase on the average customer. On October 10, 2001, the West Virginia PSC approved an interim decrease in the PGA rate effective with bills rendered on and after December 4, 2001 through November 30, 2002 (total revenue decrease for the twelve-month period of $5 million or 15.3 percent for the commodity rate). This approval became final on December 25, 2001. The reduced PGA rate is the result of changes in the market price that the Company pays for natural gas. With this adjustment, customers will benefit from recent decreases in natural gas market prices. These increases and decreases in gas cost recovery revenues have no effect on earnings because they were implemented via the PGA mechanism. Under the PGA procedure, 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 over-recoveries or under-recoveries, respectively.

On January 4, 2001, Mountaineer Gas filed for a rate increase with the West Virginia PSC in response to significant increases in the market price for natural gas. On July 25, 2001, a settlement was reached and a Joint Stipulation and Agreement for Settlement was filed with the West Virginia PSC. In October 2001, the West Virginia PSC approved the settlement agreement, which provides for a base revenue increase of $5 million per year and an increase in natural gas cost recovery revenues of approximately $23 million per year (a total increase of approximately 16.5 percent over existing rates) effective November 1, 2001. Also, Mountaineer Gas returned to the standard PGA treatment of purchased natural gas costs at the conclusion of the rate moratorium on October 31, 2001.

Regional Transmission Organization (RTO)

On March 15, 2001, Allegheny Energy and the Pennsylvania-New Jersey-Maryland Interconnection, LLC (PJM) filed documents with the Federal Energy Regulatory Commission (FERC) to expand the PJM transmission system and energy market through the creation of PJM-West. The filing represents collaboration among Allegheny Energy, PJM, and numerous stakeholders. Allegheny Energy and PJM have asked the FERC to confirm that PJM-West satisfies the FERC's requirements for a RTO as set forth in Order No. 2000. Under the PJM-West proposal, Allegheny Energy's regulated utility subsidiaries will transfer operational control over their transmission system to PJM. Allegheny Energy will adopt PJM's transmission pricing methodology, including PJM's congestion management system. In addition, PJM will expand its day-ahead and real-time energy markets to include PJM-West. As a result, energy suppliers will be able to reach consumers anywhere within the expanded PJM/PJM-West market at a single transmission rate, instead of paying multiple transmission rates as they do today.

Allegheny Energy's filing also requested authorization to recover anticipated lost transmission revenues of approximately $24.4 million annually and PJM-West start-up expenses billed to Allegheny Energy by PJM of approximately $3.9 million annually through 2004. By order dated July 12, 2001, the FERC conditionally approved PJM-West, subject to a compliance filing clarifying certain terms and conditions of PJM-West and providing additional support for Allegheny Energy's claims for lost transmission revenues and start-up expenses. PJM and Allegheny Energy submitted their compliance filing on September 10, 2001.

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that its January 30, 2002 order did not initiate a general investigation of Allegheny Energy's transmission revenues. Accordingly, in light of the limited scope of the hearing ordered by the FERC, Allegheny Energy has elected to proceed with PJM-West effective April 1, 2002. Allegheny Energy anticipates the formation of PJM-West will enhance its ability to compete for power sales in the expanded PJM/PJM-West market area.

Union Contract Negotiations

On April 30, 2001, Allegheny Energy Service Corporation's (AESC), an affiliate that employs all of the employees who work on behalf of the Company (see Note O), collective bargaining agreement with the Utility Workers Union of America (UWUA) System Local 102 expired. The parties entered into a contract extension through May 31, 2001. AESC and the UWUA were unable to reach agreement on a new labor pact by this deadline. The parties continue to work under the terms and conditions of the prior labor agreement on a day-to-day basis. AESC and the UWUA have continued to meet from time to time in pursuit of a long-term agreement. The prior agreement covers approximately 265 employees who work on behalf of the Company.

During 2001, AESC successfully negotiated new labor agreements with three bargaining units of the International Brotherhood of Electrical Workers. Of the three bargaining units, two represented employees who work on behalf of the Company. During 2002, AESC anticipates negotiations with five other bargaining units, all related to the Company and its subsidiary, whose contracts expire during the year.

Public Utility Regulatory Policies Act of 1978 (PURPA) Power Project Termination

In 1999, the Company settled for $2.3 million litigation by a developer alleging failure by the Company to comply with the PURPA regulations.

REVIEW OF OPERATIONS

Critical Accounting Policies and Estimates

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires the Company to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period.

Excess of Cost Over Net Assets Acquired (Goodwill)

As of December 31, 2001, the Company's intangible asset for acquired goodwill was $195.0 million primarily related to the acquisitions of Mountaineer Gas and West Virginia Power. A new accounting standard, SFAS No. 142, "Goodwill and Other Intangible Assets" required that the amortization of goodwill cease beginning in 2002. Instead, goodwill is required to be tested at least annually for impairment using the fair value of the Company. The estimation of the fair value of the Company will involve the use of present value measurements and cash flow models. The Company is in the process of determining the affects of SFAS No. 142 on its financial position and results of operations.

Earnings Summary
(Millions of Dollars)	2001	2000	1999

Operations	$89.5	$94.6	$92.3
Extraordinary charge, net (Note C to the
Consolidated financial statements)		(63.1)
Consolidated net income	$89.5	$31.5	$92.3

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Monongahela Power Company
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Earnings from operations, before extraordinary charge, for 2001 decreased by $5.1 million due to the June 1, 2001, transfer of the Company's Ohio portion of its generating assets to Allegheny Energy Supply. The increase in 2000 earnings from operations, before extraordinary charge, of $2.3 million was due primarily to increased income of $2.8 million related to the acquisition of Mountaineer Gas.

The extraordinary charge of $63.1 million, net of taxes, reflects write-offs by the Company of costs determined to be unrecoverable as a result of West Virginia and Ohio legislation requiring deregulation of electric generation and recognition of a rate stabilization obligation. See Notes B and C to the consolidated financial statements for additional details.

Sales and Revenues

The major retail customer classes (residential, commercial, and industrial) include electric and natural gas revenues as shown below:

(Millions of Dollars)	2001	2000	1999
Retail revenues
Residential:
Electric	$232.8	$230.9	$210.8
Natural gas	139.1	67.5
Commercial:
Electric	144.0	144.3	130.0
Natural gas	79.8	32.7
Industrial:
Electric	215.0	220.6	217.8
Natural gas	4.1	0.8
Total retail revenues	$814.8	$696.8	$558.6

The Company's residential, commercial, and industrial revenues in 2001 and 2000 were favorably affected by the addition of gas services revenues. In August 2000, the Company acquired Mountaineer Gas, a natural gas distribution company serving approximately 200,000 retail natural gas customers in West Virginia. In December 1999, the Company acquired West Virginia Power and its 24,000 natural gas customers. These acquisitions provide the Company the opportunity to offer natural gas service in its West Virginia service territory. The Company had gas revenues of $235.1 million for 2001 and $103.6 million for 2000. The majority of the Company's gas revenue is generated from residential, commercial, and industrial customers.

Percentage changes in electric revenues and kWh sales in 2001 and 2000 by major retail customer classes were:

	2001 vs. 2000		2000 vs. 1999
	Revenues	kWh	Revenues	kWh

Residential	.8%	1.3%	9.6%	9.2%
Commercial	(.2)	.4	11.0	13.6
Industrial	(2.5)	(2.2)	1.3	4.2
Total	(.7)%	(.7)%	6.7%	7.4%

The changes in residential kWh sales are more weather sensitive than the other classes. The change in residential kWh sales for 2001 was the result of an increase in customer usage coupled with an increase in the number of customers served. The changes in 2000 residential kWh sales were attributable to increased customer usage primarily because of weather conditions in late 2000.

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Monongahela Power Company
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Commercial kWh sales are also affected by weather, but to a lesser extent than residential. The increase in commercial kWh sales for 2001 is attributable to an increase in the number of customers served partially offset by a decline in commercial usage. The increase in 2000 for commercial kWh sales was due to customer usage.

The decrease in industrial kWh sales for 2001 was primarily due to a decrease in the usage by customers in the paper and printing, chemical, and iron and steel industries partially offset by an increase in sales to the coal mining industry. The increase in industrial kWh sales in 2000 was primarily due to increased kWh sales to iron and steel customers and to chemical customers.

Revenues reflect not only the changes in kWh sales and base rate changes, but also any changes in revenues from fuel and energy cost adjustment clauses (fuel clauses) through June 30, 2000, for West Virginia and December 31, 2000, for Ohio. Effective July 1, 2000, the Company's West Virginia jurisdiction ceased to have a fuel clause. Effective January 1, 2001, a fuel clause ceased to exist for the Company's Ohio jurisdiction. Through June 30, 2000, for West Virginia and December 31, 2000, for Ohio, changes in fuel revenues had no effect on the Company's net income because increases and decreases in fuel and purchased power costs and sales of transmission services and bulk power were passed on to customers by adjustment of customers' bills through a fuel clause.

Wholesale and other revenues, including affiliates were as follows:

(Millions of Dollars)	2001	2000	1999

Wholesale customers	$ 8.9	$ 6.5	$ 4.6
Affiliated companies	85.6	102.0	84.7
Street lighting and other	15.6	8.4	6.9
Total wholesale and other revenues	$110.1	$116.9	$96.2

Wholesale customers are cooperatives and municipalities that own their distribution systems and buy all or part of their bulk power needs from the Company under the FERC regulation. Competition in the wholesale market for electricity was initiated by the national Energy Policy Act of 1992, which permits wholesale generators, utility-owned and otherwise, and wholesale customers to request from owners of bulk power transmission facilities a commitment to supply transmission services. All of the Company's wholesale customers have signed contracts to remain as customers until November 30, 2003. Wholesale customer revenue for 2001 and 2000 remained relatively flat as compared to 2000 and 1999, respectively.

Revenues from affiliated companies represent sales of energy and intercompany allocations of generating capacity, generation spinning reserves, and transmission services pursuant to a power supply agreement among the Company and the other regulated utility subsidiaries of Allegheny Energy. Revenues from affiliated companies decreased by $16.4 million in 2001 due to the affiliates of the Company securing their power requirements from Allegheny Energy Supply. Revenues from affiliated companies increased by $17.3 million in 2000 due to the Company selling power to Allegheny Energy Supply offset, in part, by a decrease in power sold to the Company's affiliates. The Company has a dispatch arrangement with Allegheny Energy Supply.

Street lighting and other revenues increased by $7.2 million and $1.5 million for 2001 and 2000, respectively, due to sales of natural gas as a result of the acquisition of Mountaineer Gas in 2000 and West Virginia Power in 1999.

Transmission services and bulk power sales include transactions of transmission services, bulk power, and other energy services to power marketers and other utilities. Revenues from transmission services and bulk power sales remained relatively flat for 2001 when compared to 2000. Revenues from bulk power sales decreased by $4.2 million in 2000 when

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Monongahela Power Company
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compared to 1999 due to decreased sales to power marketers and other utilities. This decrease was the result of increased affiliated sales due to a dispatch agreement with the Company's unregulated affiliate, Allegheny Energy Supply. With this agreement, regulated operations sells the amount of its bulk power that exceeds its regulated load to Allegheny Energy Supply and conversely buys generation from unregulated operations when regulated load at times exceeds regulated generation. Such a relationship allows the Company's generation to be dispatched in a more efficient manner. Revenues from transmission and other energy services remained relatively flat in 2001. Revenues from transmission and other energy services in 2000 increased primarily due to increased megawatt-hours (MWh) transmitted.

Through June 30, 2000, and December 31, 2000, for the Company's West Virginia and Ohio jurisdictions, respectively, the costs of purchased power and revenues from sales to power marketers and other utilities, including transmission services, were recovered from or credited to customers under fuel and energy cost recovery procedures. The impact to the fuel and energy cost recovery clauses may either be positive or negative depending on whether the Company is a net buyer or seller of electricity during such periods and the open commitments, which exist at such times. The impact of such price volatility was insignificant to the Company in the first six months of 2000 for West Virginia and twelve months ended 2000 for Ohio because increases or decreases were passed on to customers through operation of fuel clauses.

Effective July 1, 2000, and December 31, 2000, once the fuel clauses were eliminated in West Virginia and Ohio, respectively, the Company assumed the risk and benefits of changes in fuel and purchased power costs and sales of transmission services and bulk power in its West Virginia and Ohio jurisdiction.

When a fuel clause is in effect, changes in fuel revenues have no effect on consolidated net income because increases and decreases in fuel and purchased power costs and sales of transmission services and bulk power are passed on to the customer through fuel clauses.

Operating Expenses

Fuel expense for 2001 decreased by $13.7 million as compared to 2000 due to an 11.6 percent decrease in kWhs generated, partially offset by a 2.6 percent increase related to average fuel prices. The decline in kWhs generated can be attributed, in part, to the Company's transfer of the Ohio portion of its generation assets to Allegheny Energy Supply on June 1, 2001. Fuel expenses increased by $5.3 million for 2000 as compared to 1999 due primarily to a 4.3 percent increase related to kWhs generated, offset in part by a .6 percent decrease in average fuel prices.

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Purchased power and exchanges, net, represents power purchases from and exchanges with other companies and purchases from qualified facilities under the PURPA, capacity charges paid to Allegheny Generating Company (AGC), an affiliate partially owned by the Company, and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and consists of the following items:

(Millions of Dollars)	2001	2000	1999

Nonaffiliated transactions:
Purchased power:
From PURPA generation*	$ 59.7	$70.7	$65.1
Other	23.8	22.9	15.1
Power exchanges, net		1.6	(.6)
Affiliated transactions:
AGC capacity charges	16.9	18.9	19.1
Other	30.7	5.3	.1
Purchased power and exchanges, net	$131.1	$119.4	$98.8
*PURPA cost (cents per kWh)	5.2	5.4	5.2

Power purchased from PURPA generators decreased in 2001 by $11 million due to an unscheduled shutdown of a PURPA generation facility and credits recorded by the Company for overpayments of PURPA generation in prior years. The increase of $5.6 million in power purchased from PURPA generators in 2000 was the result of an increase in the amount of kWh purchased.

Other purchased power from non-affiliates in 2001 remained relatively flat while increasing by $7.8 million in 2000 due to purchases required to serve customers acquired through the acquisition of West Virginia Power.

The AGC capacity charges decreased by $2 million in 2001 due to the transfer of the Company's Ohio portion of its generation assets on June 1, 2001, which included transferring a portion of the Company's ownership in AGC to Allegheny Energy Supply.

Other affiliated transactions increased in 2001 and 2000 by $25.4 million and $5.2 million, respectively, due to an increase in power purchased from Allegheny Energy Supply. In early 2000, a dispatch agreement was implemented between the Company and Allegheny Energy Supply that allows the Company's generation to be dispatched in a more efficient manner. The Company purchases generation from Allegheny Energy Supply when the Company's load exceeds its generation and sells excess generation to Allegheny Energy Supply when the Company's generation exceeds its load.

Natural gas purchases and production reflect the acquisition of Mountaineer Gas in August 2000 and West Virginia Power in December 1999.

The increase in other operation expenses in 2001 of $25.9 million was attributable to additional expenses associated with serving customers acquired through the acquisition of Mountaineer Gas in August 2000. The increase in 2000 of $26.7 million was due to additional expenses associated with serving the customers acquired through the acquisitions of West Virginia Power and Mountaineer Gas.

The increases of $12.2 million and $6.9 million in maintenance expenses in 2001 and 2000, respectively, were due primarily to increased power station maintenance and the T&D maintenance expenses associated with the Mountaineer Gas acquisition. The acquisition of West Virginia Power also contributed to the increase in maintenance expenses in 2000. Maintenance expenses represent costs incurred to maintain the power stations, the T&D system, and general plant and reflect routine maintenance of equipment and rights-of-way,

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as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. Variations in maintenance expense result primarily from unplanned events and planned projects, which vary in timing and magnitude depending upon the length of time equipment has been in service and the amount of work found necessary when the equipment is dismantled.

Depreciation and amortization expense increased by $6.3 million in 2001 as a result of the acquisition of Mountaineer Gas in August 2000 offset, in part, by the transfer of the Company's Ohio portion of its generation assets to Allegheny Energy Supply in June 2001. Depreciation and amortization expense increased by $11.8 million in 2000 due to increased investment, primarily associated with the acquisitions of West Virginia Power and Mountaineer Gas.

Taxes other than income taxes increased by $7.8 million in 2001 due in part to increased West Virginia Business and Occupation Taxes and West Virginia State Property Taxes due to the acquisition of Mountaineer Gas. Taxes other than income taxes increased by $12.6 million in 2000 primarily due to increased West Virginia Business and Occupation Taxes and West Virginia Gross Receipts Taxes related to the acquisitions of West Virginia Power and Mountaineer Gas. The increase in 2001 and 2000 is also attributable to increased payroll taxes as a result of an increase in the number of employees as a result of the Mountaineer Gas acquisition and an increase in the FICA base pay for each respective year.

The decrease in federal and state income taxes in 2001 of $13.7 million was attributable to a decrease in taxable income. The increase in federal and state income tax expense in 2000 of $10.2 million was primarily due to increased operating income and depreciation differences. Note F to the consolidated financial statements provides a further analysis of income tax expense.

Other Income and Deductions

The increase in other income, net, of $1.5 million in 2001 was primarily due to an increase in interest income as a result of investments within the money pool in the year offset, in part, by a decrease in the Company's share of the earnings from AGC. Other income, net remained relatively flat for 2000.

Interest Charges

The increases in interest charges in 2001 and 2000 of $7.5 million and $11.1 million, respectively, were primarily from increased average long-term debt outstanding as a result of additional debt incurred during the acquisition of Mountaineer Gas in August 2000. The increase in average long-term debt in 2000 was also the result of the acquisition of West Virginia Power in December 1999. Interest expense is also affected by changes in the levels of short-term debt maintained by the Company throughout the year, as well as the associated interest rates.

See Financing on page 13 for more information related to the Company's long-term debt.

Extraordinary Charge

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

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FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

Liquidity and Capital Requirements

To meet cash needs for operating expenses, the payment of interest, retirement of debt, and for its construction program, the Company has used internally generated funds (net cash provided by operating activities less common and preferred dividends) and external financings, such as 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, the Company's cash needs, and capital structure objectives of the Company. The availability and cost of external financings depend upon the financial condition of the companies seeking those funds and market conditions.

The Company's ability to meet its payment obligations under its indebtedness and to fund capital expenditures will depend on its future operations. The Company's future performance is subject to regulatory, economic, financial, competitive, legislative, and other factors that are beyond its control, as discussed in "Factors That May Affect Future Results" on page 2. The Company's future performance could affect its ability to maintain its investment grade credit rating.

To enhance liquidity and meet short-term borrowing needs, the Company has access to lines of credit and an Allegheny Energy internal money pool. The Company is a participant, along with Allegheny Energy and various affiliates, in bank lines of credit totaling $400 million for general corporate purposes and as a backstop to their commercial paper programs. At December 31, 2001, the Company's subsidiary, Mountaineer Gas, drew down $14.4 million of the lines of credit. The remaining $385.6 million lines of credit, were supporting commercial paper of Allegheny Energy and were unavailable to the Company. In addition to bank lines of credit, an Allegheny Energy internal money pool accommodates intercompany short-term borrowing needs, to the extent that Allegheny Energy and its regulated subsidiaries have funds available. As of December 31, 2001 and 2000, the Company had $91.5 million and $22.0 million invested in the money pool. The Company has SEC authorization for total short-term borrowings, from all sources, of $206 million. The Company has fee arrangements on all of its lines of credit and no compensating balance requirements.

The Company 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.

	Payments Due by Period
	(Thousands of Dollars)
Contractual Cash Obligations	Less Than			After
and Commitments	1 Year	2-3 Years	4-5 Years	5 Years	Total

Long-term debt*	$ 30,408	$ 69,271	$306,696	$ 410,786	$ 817,161
Capital lease obligations	4,509	7,465	5,304	4,538	21,816
Operating lease obligations	2,344	1,655	187		4,186
PURPA purchased power	69,312	116,563	114,869	1,410,583	1,711,327
Fuel purchase commitments	91,018	156,572	81,450	3,028	332,068

Total	$197,591	$351,526	$508,506	$1,828,935	$2,886,558
*Long-term debt does not include unamortized debt expense, discounts, and premiums.

Capital expenditures, including construction expenditures, were $104.5 million, $82.1 million, and $81.4 million for 2001, 2000, and 1999, respectively. In 2000, the Company acquired Mountaineer Gas for $325.7 million, which included the assumption of $100.1

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Monongahela Power Company
and Subsidiaries

million in existing debt. In 1999, the Company acquired the assets of West Virginia Power for approximately $95 million.

The Company's capital expenditures, including construction expenditures, for 2002 and 2003, are estimated at $105.1 million and $90.7 million, respectively. These estimated expenditures include $45.5 million and $32.6 million, respectively, for environmental control technology. As described under Environmental Issues starting on page 17, the Company could potentially face significant mandated increases in capital expenditures and operating costs related to environmental issues. See Note Q to the consolidated financial statements for additional information. Whether the Company can continue to meet the majority of its construction needs with internally generated cash is largely dependent upon the outcome of these issues.

Cash Flow

Internally generated funds, consisting of cash flows from operations reduced by common and preferred dividends, was $91.0 million in 2001, compared with $140.4 million in 2000.

Cash flows from operations for 2001 decreased by $11.3 million from the comparable 2000 period reflecting changes in net income, extraordinary charge, accounts receivable, materials and supplies, prepayments, accounts receivable from affiliates, and accounts payable to affiliates levels. Cash flows from operations for 2000 increased by $35.9 million from the comparable 1999 period reflecting changes in net income, extraordinary charge, accounts receivable, accounts receivable from affiliates, and accounts payable to affiliates.

Cash flows used in investing decreased by $206.5 million for 2001 and increased by $132.9 million for 2000, respectively, primarily due to the acquisition of Mountaineer Gas in 2000.

Cash flows used in financing increased by $194.2 million for 2001 from the comparable 2000 period due to the repayment of long-term debt and an increase in dividends paid. Cash flows provided by financing increased by $94.9 million for 2000 from the comparable 1999 period due primarily to an equity contribution from Allegheny Energy partially offset by repayment of long-term debt.

Financing

Long-term Debt

On October 2, 2001, the Company issued debt of $300 million of 5 percent first mortgage bonds due October 1, 2006. The first mortgage bonds were used to replenish funds used to redeem $40 million of 8 percent Quarterly Income Debt Securities (QUIDS) due June 30, 2025, refinanced $100 million senior secured credit facility that matured in October 2001, refinanced $50 million first mortgage bonds that carried a higher interest rate, and provided the Company funds for other corporate purposes. The QUIDS were redeemed on September 21, 2001.

The Company's $65 million of 5 5/8 percent series first mortgage bonds matured on April 1, 2000.

On August 18, 2000, the Company borrowed $61 million, under a senior secured credit facility, at a rate of 7.18 percent, with a maturity of November 20, 2000. The proceeds were used for the acquisition of Mountaineer Gas. On November 20, 2000, the Company borrowed $100 million, under a senior secured credit facility, at a rate of 7.21 percent, with a maturity of May 21, 2001. The proceeds were used to refinance the $61 million senior secured credit facility and provided funds for other corporate purposes. The Company requested and received an extension on the maturity of the $100 million senior secured credit facility until October 18, 2001.

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Monongahela Power Company
and Subsidiaries

On August 18, 2000, the Company's parent, Allegheny Energy, issued $165 million aggregate principal amount of its 7.75 percent notes due August 1, 2005. Of that amount, Allegheny Energy contributed $162.5 million to the Company to be used for the acquisition of Mountaineer Gas.

As part of the purchase of Mountaineer Gas on August 18, 2000, the Company assumed $100.1 million of existing Mountaineer Gas debt. This debt consists of several senior unsecured notes and a promissory note with fixed interest rates between 7.00 percent and 8.09 percent, and maturity dates between April 1, 2009, and October 31, 2019.

The Company's long-term debt due within one year at December 31, 2001, of $30.4 million represents $25 million of first mortgage bonds, and $5.4 million of unsecured notes.

Short-Term Debt

As of December 31, 2001, the Company had $14.4 million in short-term debt outstanding.

SIGNIFICANT CONTINUING ISSUES

Electric Energy Competition

The electricity supply segment of the electric industry in the United States is becoming increasingly competitive. The national Energy Policy Act of 1992 deregulated the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. The Company and its parent, Allegheny Energy, continue to be an advocate of federal legislation to remove artificial barriers to competition in electricity markets, avoid regional dislocations, and ensure a level playing field.

In addition, with the wholesale electricity market becoming more competitive, certain states have taken active steps toward allowing retail customers the right to choose their electricity supplier.

Allegheny Energy is at the forefront of state-implemented retail competition, having negotiated settlement agreements in all of the states that Allegheny Power serves. Maryland, Pennsylvania, Ohio, and Virginia have retail choice programs in place. West Virginia's Legislature has approved a deregulation plan for the Company pending additional legislation regarding tax revenues for state and local governments. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider the deregulation plan in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

The regulatory environment applicable to Allegheny Energy's generation and T&D businesses will continue to undergo substantial changes on both the federal and state level. These changes have significantly affected the nature of the electric industry and the manner in which its participants conduct their business. Moreover, existing statutes and regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to Allegheny Energy or its facilities, and future changes in laws and regulations may have an effect on Allegheny Energy in ways that cannot be predicted. Some markets, like California, have experienced interruptions of supply and price volatility, which have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some markets, including California, government agencies and other interested parties have made proposals to re-regulate areas of these markets that have been deregulated, and, in California, legislation has been passed placing a moratorium on the sale of generating facilities by regulated utilities. Proposals to re-regulate the wholesale power market have been made at the federal level. Proposals of this sort, and legislative or other attention to the electric power restructuring process in the states in which Allegheny Energy currently operates, or may

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Monongahela Power Company
and Subsidiaries

in the future operate, may cause deregulation to be delayed, discontinued, or reversed, which could have a material effect on Allegheny Energy's operations and strategies.

The recent bankruptcy filing by Enron Corporation (Enron) may affect the regulatory and legislative process. In response to the Enron bankruptcy filing and the September 11 terrorists' attacks, financial markets have been disrupted in general, and the availability and cost of capital for Allegheny Energy's business and that of its competitors has been adversely affected. Following the Enron bankruptcy filing, credit ratings agencies reviewed the capital structure and earnings power of energy companies, including Allegheny Energy. These events have constrained the capital available to the industry and could adversely affect Allegheny Energy's access to funding for its operations.

Activities at the Federal Level

The terrorists' attacks of September 11, 2001, have altered the agenda of the 107th Congress. In fact, some legislative initiatives have been delayed or postponed since that date because the Congress and the Bush Administration have been focused on responding to these attacks. However, part of that response may well be the consideration of energy security legislation currently in development. Allegheny Energy is lobbying for the inclusion of important electricity restructuring provisions in this legislation, including the repeal or significant revision of PUHCA, as well as for critical infrastructure protection legislation. Prior to the attack, two primary bills had been introduced in the U.S. Senate: S. 388, by former Energy and Natural Resources Committee Chairman Senator Frank Murkowski of Alaska, and S. 597, by the committee's new chairman, Senator Jeff Bingaman of New Mexico. Provisions from these bills could be included in the new energy legislation. The primary House committee of jurisdiction, Energy and Commerce, initially passed the President's national energy security proposal and is only now considering accompanying electricity restructuring legislation. Among issues that are being addressed in this legislation are the repeal or significant revision of PUHCA and Section 210 (Mandatory Purchase Provisions) of PURPA. Allegheny Energy continues to advocate the repeal of PUHCA and Section 210 of PURPA on the grounds that they are obsolete and anticompetitive and that PURPA results in utility customers paying above-market prices for power. Separately, the Senate Banking Committee in April 2001 approved S. 206, legislation to repeal PUHCA.

Ohio Activities

The Ohio General Assembly passed legislation in 1999 to restructure its electric utility industry. As of January 1, 2001, all of the state's electricity customers were able to choose their electricity supplier, beginning a five-year transition to market rates. Residential customers are guaranteed a five percent cut in the generation portion of their rate.

The Company reached a stipulated agreement with major parties on a transition plan to bring electric choice to its approximately 29,000 Ohio customers. None of the Company's Ohio customers have switched to another supplier. The restructuring plan allowed the Company to transfer its Ohio and FERC jurisdictional generating assets to Allegheny Energy Supply at book value on or after January 1, 2001. That transfer was made on June 1, 2001.

West Virginia Activities

Electric restructuring in West Virginia remains unresolved and awaits further legislative action. In January 2000, the West Virginia PSC submitted a restructuring plan to the Legislature for approval that would open full retail competition on January 1, 2001. On March 11, 2000, the West Virginia Legislature approved the West Virginia PSC's plan, but assigned the tax issues surrounding the plan to a legislative subcommittee for further study. The start date of competition is contingent upon the necessary tax changes being made and approved by the Legislature. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

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Monongahela Power Company
and Subsidiaries

As approved by the West Virginia PSC, Potomac Edison transferred its generating assets to Allegheny Energy Supply in August 2000. In accordance with the same restructuring agreement, Potomac Edison and the Company implemented a commercial and industrial rate reduction program on July 1, 2000.

The status of electric energy competition in Virginia, Maryland, and Pennsylvania in which affiliates of the Company serve are as follows:

Virginia Activities

The Virginia Electric Utility Restructuring Act (Restructuring Act) became law on March 25, 1999. All state utilities were required to submit a restructuring plan by January 1, 2001, to be effective on January 1, 2002. On December 21, 2001, the Virginia State Corporation Commission (Virginia SCC) approved Potomac Edison's Phase II of the Functional Separation Plan. In August 2000, Potomac Edison transferred its Virginia jurisdictional generating assets, excluding the hydroelectric assets located within Virginia, to Allegheny Energy Supply at book value. Customer choice was implemented for all customers in Potomac Edison's service territory beginning on January 1, 2002.

The Restructuring Act was amended during the 2000 General Assembly legislative session to direct the Virginia SCC to prepare for legislative approval a plan for competitive metering and billing and to authorize the Virginia SCC to implement a consumer education program on electric choice, funded through its regulatory tax. On December 12, 2000, the Virginia SCC issued a report on competitive metering and billing. Its recommendations include allowing licensed electricity suppliers to provide billing services, with the customer selecting its preferred billing option. The Virginia SCC also recommended that legislative action on competitive metering be deferred pending further study, due to the complexities of the issue and limited competitive metering activities nationally. On May 15, 2001, the Virginia SCC initiated proceedings to establish rules and regulations for consolidated billing services, competitive metering, and customer minimum stay periods.

Maryland Activities

On June 7, 2000, the Maryland Public Service Commission (Maryland PSC) approved the transfer of the generating assets of Potomac Edison to Allegheny Energy Supply. The transfer was completed in August 2000. Maryland customers of Potomac Edison have had the right to choose an alternate electric supplier since July 1, 2000. While few customers have switched suppliers in Potomac Edison's service territory, some retail competition is occurring in other portions of the state.

-
announces the Maryland PSC's intent to impose 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 unqualified benefits;" and

- requires asymmetric pricing for asset transfers between utilities and their affiliates. Asymmetric pricing requires that transfers of assets from the regulated utility to an affiliate be recorded at the greater of book cost or market value while transfers of assets from the affiliate to the regulated utility be recorded at the lesser of book cost or market value.

Potomac Edison, along with substantially all of Maryland's natural gas and electric utilities, filed a Circuit Court petition for judicial review and a motion for stay of the order. On April 25, 2001, the Circuit Court issued its decision affirming much of the Maryland PSC's order, but remanding portions of the order to the Maryland PSC, including the requirement for asymmetric pricing for asset transfers between utilities and their affiliates.

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Monongahela Power Company
and Subsidiaries

Potomac Edison and other Maryland natural gas and electric utilities have noted an appeal of the Circuit Court's decision to Maryland's Court of Special Appeals. The Court of Appeals, Maryland's highest court, assumed jurisdiction over the appeal. After the filing of briefs, the Court of Appeals heard oral arguments on January 8, 2002.

The Maryland PSC also has initiated a proceeding, Case No. 8868, to investigate certain affiliated activities of Potomac Edison and has also docketed similar proceedings for Maryland's other natural gas and electric companies. Case No. 8868 is pending before a Maryland PSC Hearing Examiner.

The Maryland PSC has initiated a proceeding, Case No. 8907, to investigate Potomac Edison's proposed revisions to its line extension charges and policies for non-residential customers. The Maryland PSC delegated the proceeding to the Hearing Examiner Division. The Hearing Examiner held a prehearing conference on January 10, 2002, and established a procedural schedule. The parties are entering into settlement discussions.

By letter order dated December 17, 2001, the Maryland PSC directed parties to commence meetings on January 17, 2002, on the status of the provision of default service. Potomac Edison will participate in those meetings.

Pennsylvania Activities

As of January 2, 2000, all electricity customers in Pennsylvania have the right to choose their electric generation supplier. The number of customers who have switched to another supplier and the amount of electrical load transferred in Pennsylvania exceed that of any other state. However, West Penn had retained more than 99.8 percent of its Pennsylvania customers as of December 31, 2001.

As part of West Penn's restructuring settlement in Pennsylvania, West Penn retains the obligation to serve all customers who choose not to select an alternate supplier (provider of last resort) at rates that are capped at 1997 levels. The generation rates are capped through 2008.

Environmental Issues

The Environmental Protection Agency's (EPA) nitrogen oxides (NO_X) State Implementation Plan (SIP) call regulation has been under litigation, and on March 3, 2000, the District of Columbia Circuit Court of Appeals issued a decision that upheld the regulation. However, state and industry litigants filed an appeal of that decision in April 2000. On June 23, 2000, the Court denied the request for the appeal. Although the Court did issue an order to delay the compliance date from May 1, 2003, until May 31, 2004, both the Maryland and Pennsylvania state rules to implement the EPA NO_X SIP call regulation still require compliance by May 1, 2003. West Virginia has issued a proposed rule that would require compliance by May 1, 2004. However, the EPA Section 126 petition regulation also requires the same level of NO_X reductions as the EPA NO_X SIP call regulation with a May 1, 2003, compliance date. The EPA Section 126 petition rule is also under litigation in the District Court of Columbia Circuit Court of Appeals. A Court decision in May 2001 upheld the rule. In August 2001, the Court issued an order that suspends the Section 126 petition rule May 1, 2003, compliance date pending EPA review of the growth factors used to calculate the state NO_X budgets. The Company's compliance with such stringent regulations will require the installation of expensive post-combustion control technologies on most of its power stations. The Company's construction forecast includes the expenditure of $52.4 million of capital costs during the 2002 through 2003 period to comply with these regulations.

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Monongahela Power Company
and Subsidiaries

On August 2, 2000, Allegheny Energy received a letter from the EPA requiring it to provide certain information on the following 10 electric generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island. Allegheny Energy Supply and the Company now own these electric generating stations. The letter requested information under Section 114 of the federal Clean Air Act to determine compliance with the Act and state implementation plan requirements, including potential application of federal New Source Review (NSR). In general, these standards can require the installation of additional air pollution control equipment upon the major modification of an existing facility. Allegheny Energy submitted these records in January 2001. The eventual outcome of the EPA investigation is unknown.

Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in many cases. The Company believes its generating facilities have been operating in accordance with the Clean Air Act and the rules implementing the Act. The experience of other utilities, however, suggests that, in recent years, the EPA may well have revised its interpretation of the rules regarding the determination of whether an action at a facility constitutes routine maintenance, which would not trigger the requirements of the NSR, or a major modification of the facility, which would require compliance with the NSR. If federal NSR were to be applied to these generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. In connection with the deregulation of generation, the Company has agreed to rate caps in each of its jurisdictions, and there are no provisions under those arrangements to increase rates to cover such expenditures.

In December 2000, the EPA issued a decision to regulate coal- and oil-fired electric utility mercury emissions under Title III, Section 112 of the 1990 Clean Air Act Amendments. The EPA plans to issue a proposed regulation by December 2003 and a final regulation by December 2004. The timing and level of required mercury emission reductions are unknown at this time.

In the normal course of business, the Company becomes involved in various legal proceedings. The Company does not believe that the ultimate outcome of these proceedings will have a material effect on its financial position. See Note Q for additional information regarding environmental matters and litigation.

Derivative Instruments and Hedging Activities

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 was subsequently 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." Effective January 1, 2001, the Company implemented the requirements of these accounting standards.

These standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. They require 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 the 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. SFAS No. 133 is expected to increase the volatility in entities' reported earnings and other comprehensive income.

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Monongahela Power Company
and Subsidiaries

As of December 31, 2001, the Company had no financial instruments, commodity contracts, or other commitments that required recognition as assets or liabilities on the balance sheet at fair value under the provisions of SFAS 133.

Quantitative and Qualitative Disclosure About Market Risk

The Company is exposed to market risks associated with commodity prices and interest rates. The commodity price risk exposure results from market fluctuations in the price and transportation costs of electricity and natural gas as discussed below. The interest rate risk exposure results from changes in interest rates related to variable- and fixed-rate debt. The Company is mandated by Allegheny Energy's Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

Allegheny Energy has a Corporate Energy Risk Policy adopted by Allegheny Energy's Board of Directors and monitored by a Risk Management Committee chaired by Allegheny Energy's Chief Executive Officer and composed of members of senior management. An independent risk management group within Allegheny Energy actively measures and monitors the risk exposures to ensure compliance with the policy and it is periodically reviewed.

As part of the Company's efforts to spur deregulation in West Virginia, the Company agreed to terminate its expanded net energy cost (fuel clause) effective July 1, 2000. However, as described under state deregulation efforts, the West Virginia deregulation process remains stalled. As a result, the Company is subject to capped rates from a revenue standpoint without the existence of a fuel clause to offset fluctuations in the market price of fuel and natural gas. In order to manage the Company's financial exposure to these price fluctuations, the Company routinely enters into contracts, such as fuel and natural gas purchase commitments in order to reduce its risk exposure. To the extent that the Company purchases fuel and natural gas at significantly higher prices, the Company's results of operations could be adversely affected.

As a result of the Company's restructuring plan in Ohio, the Company unbundled its rates in Ohio to reflect three separate charges-a generation (or supply) charge, a Competitive Transition Charge (CTC), and T&D charges. The generation rates applied to customers not choosing an alternate generation supplier are capped through a transition period that ends December 31, 2005.

Pursuant to agreements, Allegheny Energy Supply provides the Company with the amount of electricity needed for those Ohio customers not choosing an alternate generation supplier during the transition period. The original rate schedule for these agreements, effective through December 31, 2000, established fixed purchase prices corresponding to the capped generation rates charged to customers not electing an alternate generation supplier. Thus, the cost of purchased electricity was recovered through the capped generation rates charged to customers.

Under a revised rate schedule approved by the FERC effective January 1, 2001, a portion of the electricity purchased from Allegheny Energy Supply now has a market-based pricing component that could result in higher electricity prices when market prices exceed the fixed prices (corresponding to the capped generation rates). Purchased electricity prices would never be set below the established fixed prices. The amount of electricity purchased under this rate schedule that is subject to market prices escalates each year through 2005. To the extent that the Company purchases electricity from Allegheny Energy Supply at market prices that exceed the established fixed prices, the Company's results of operations could be adversely affected.

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Monongahela Power Company
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New Accounting Standards

In July 2001, the FASB issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." These standards changed the accounting for business combinations and goodwill in two significant ways. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. Use of the pooling-of-interests method will be prohibited. SFAS No. 141 is not expected to have a material effect on the Company.

SFAS No. 142 changed the accounting for goodwill from an amortization method to an impairment-only approach. Amortization of goodwill, including goodwill recorded in past business combinations, ceased on January 1, 2002. Goodwill will now be tested at least annually for impairment. Intangible assets other than goodwill will continue to be amortized over their useful lives and reviewed for impairment. As of December 31, 2001, the Company had $195.0 million of goodwill. The Company had goodwill amortization in 2001 of $5.1 million. The Company is in the process of evaluating the effect of adopting SFAS No. 142 on its results of operations and financial position and plans to reflect the results of this evaluation in its first quarter 2002 financial statements.

In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This standard, which the Company will adopt on January 1, 2003, requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Over time, the liability will be accreted to its present value each period, and the capitalized cost will be depreciated over the useful life of the asset. Upon settlement of the liability, an entity either will settle the obligation for its recorded amount or incur a gain or loss upon settlement. The Company will be evaluating the effect of adopting SFAS No. 143 on its results of operations and financial position prior to its adoption of the standard.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This standard, which the Company adopted on January 1, 2002, establishes one accounting model for long-lived assets to be disposed of by sale, including discontinued operations, and carries forward the general impairment provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of". SFAS No. 144 is not expected to have a material effect on the Company.

M-52

The Potomac Edison Company
and Subsidiaries

RESULTS MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND OF OPERATIONS

FACTORS THAT MAY AFFECT FUTURE RESULTS

Certain statements within constitute forward-looking statements with respect to the Potomac Edison Company and its subsidiaries (collectively, the Company). Such forward-looking statements include statements with respect to deregulated activities and movement towards competition in the states served by the Company, markets, products, services, prices, capacity purchase commitments, results of operations, capital expenditures, regulatory matters, liquidity and capital resources, the effect of litigation, and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results of the Company will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

Factors that could cause actual results of the Company to differ materially include, among others, the following: general economic and business conditions, including the continuing effect on the economy caused by the September 11, 2001, terrorists' attacks; changes in industry capacity, development, and other activities by the Company's competitors; changes in the weather and other natural phenomena; changes in technology; changes in the price of purchased power; changes in laws and regulations applicable to the Company, its markets, or its activities; litigation involving the Company; environmental regulations; the loss of any significant customers and suppliers; the effect of accounting policies issued periodically by accounting standard-setting bodies; and changes in business strategy, operations, or development plans.

OVERVIEW

The Company is a wholly owned subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and along with its regulated utility affiliates, The Monongahela Power Company (Monongahela Power), including its subsidiary, Mountaineer Gas Company (Mountaineer Gas), and West Penn Power Company (West Penn), together doing business as Allegheny Power, operate electric and natural gas transmission and distribution (T&D) systems. Allegheny Power also generates electric energy in its West Virginia jurisdiction where deregulation of electric generation has not been implemented. The Company's business is the operation of electric T&D systems in Maryland, Virginia and West Virginia.

In June 2001, the Company completed the process of transferring its generating assets to Allegheny Energy Supply Company, LLC (Allegheny Energy Supply), the nonutility generating subsidiary of Allegheny Energy, by transferring its Virginia hydroelectric assets. The process began in December 1999 when the Maryland Public Service Commission (Maryland PSC) approved an agreement allowing Maryland customers to choose their generation supplier. In June 2000, the Maryland PSC authorized the Company to transfer the Maryland portion of its generating assets to Allegheny Energy Supply. The Company also obtained the necessary approvals from the Virginia State Corporation Commission (Virginia SCC) and the Public Service Commission of West Virginia (West Virginia PSC) to transfer the Virginia and West Virginia portions of its generating assets to Allegheny Energy Supply.

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The Potomac Edison Company
and Subsidiaries

STATE DEREGULATION EFFORTS

See Notes B and C to the consolidated financial statements for detailed discussions of the various state restructurings and information regarding the electric generation deregulation process.

On August 1, 2000, the Company transferred, at book value, approximately 2,100 megawatts (MW) of its Maryland, Virginia, and West Virginia jurisdictional generating assets to Allegheny Energy Supply. State utility commissions in Maryland, Virginia, and West Virginia approved the transfer of these assets as part of deregulation proceedings in those states. The Federal Energy Regulatory Commission (FERC) and the Securities and Exchange Commission (SEC) also approved these transfers.

On June 1, 2001, the Company transferred the five MW of hydroelectric assets located within Virginia to Green Valley Hydro, LLC (Green Valley Hydro) and distributed its ownership of Green Valley Hydro to Allegheny Energy. Allegheny Energy will transfer Green Valley Hydro to Allegheny Energy Supply in 2002.

Under the terms of deregulation in Maryland, Virginia and West Virginia, the Company retains the obligation to provide electricity to customers that do not choose an alternative electricity supplier during a specified transition period. The transition periods not only differ by state, they also differ based upon customer class. For further details, see state activities on pages 14 through 16 and Notes B and C to the consolidated financial statements.

OTHER SIGNIFICANT EVENTS IN 2001, 2000, AND 1999

Initial Public Offering of Allegheny Energy Supply

On July 23, 2001, Allegheny Energy filed a U-1 application with the SEC, seeking authorization under the Public Utility Holding Company Act of 1935 (PUHCA) to effect an initial public offering (IPO) of up to 18 percent of the common stock in a new holding company, which would own 100 percent of Allegheny Energy Supply, and then distribute the remaining common stock owned by Allegheny Energy to its shareholders on a tax-free basis. In October 2001, Allegheny Energy announced that the proposed IPO would be delayed due to market and other conditions. In January 2002, Allegheny Energy announced that it would not proceed with the IPO. In February 2002, Allegheny Energy filed an amendment to the U-1 application filed with the SEC on July 23, 2001, withdrawing its IPO application.

Rate Matters

The Company decreased the fuel portion of Maryland customers' bills by approximately $6.4 million annually, effective with bills rendered on or after December 7, 1999, based on the outcome of proceedings before the Maryland PSC. A proposed order was issued on February 18, 2000, granting the requested decrease in the Company's fuel rate, and, on March 21, 2000, the proposed order became final. Effective July 1, 2000, coincident with customer choice in Maryland, the fuel rate was rolled into base rates, thus eliminating the fuel adjustment clause.

On March 24, 2000, the Maryland PSC issued an order requiring the Company to refund the 1999 deferred fuel balance over-recovery of approximately $9.9 million to customers over a period of 12 months that began April 30, 2000. This refund did not affect the Company's earnings since the over-recovered amounts had been deferred.

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The Potomac Edison Company
and Subsidiaries

On October 4, 2000, the Maryland PSC approved the Company's filing, which represented the final reconciliation of its deferred fuel balance. The Company refunded to customers a $3.2 million over-recovery balance, which existed in the Maryland deferred fuel account as of September 30, 2000. The deferred fuel credit to customers began in October 2000 and ended in October 2001 when the balance fell to zero. The refund of the over-recovered balance did not affect the Company's earnings, since the over-recovered amounts had been deferred.

On June 23, 2000, the West Virginia PSC approved a Joint Stipulation and Agreement for Settlement, stating agreed-upon rates designed to make the West Virginia rates of the Company and Monongahela Power consistent. Under the terms of the settlement, several tariff schedules, notably those available to residential and small commercial customers, will require several incremental steps to reach the agreed-upon rate level. The settlement rates resulted in a revenue increase of approximately $.2 million for 2000, increasing over eight years to an annual increase of approximately $4.3 million. The settlement approved by the West Virginia PSC directs the Company to amortize the existing over-collected deferred fuel balance as of June 30, 2000 (approximately $10 million), as a reduction of expenses over a four-and-one-half year period beginning July 1, 2000. Also, effective July 1, 2000, the Company and Monongahela Power ceased their expanded net energy cost (fuel clause) as part of the settlement.

In conjunction with the order approving Phase I of the Company's Functional Separation Plan, the Virginia SCC approved a Memorandum of Understanding (MOU). The MOU provided that, effective with bills rendered on or after August 7, 2000, base rates were reduced by $1 million; the Company would not file for a base rate increase prior to January 1, 2001; and the fuel rate would be rolled into base rates effective with bills rendered on or after August 7, 2000. The Company was not required to refund to customers the over-recovered fuel balance of $.2 million. A fuel rate adjustment credit was also implemented on August 7, 2000, reducing annual fuel revenues by $750,000. Effective August 2001, the fuel rate adjustment credit dropped to $250,000. Effective August 2002, the fuel rate adjustment credit will be eliminated.

On November 29, 2000, the Maryland PSC approved the Power Sales Agreement between the Company and the winning bidder covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2001, through December 31, 2001. In November 2001, the Maryland PSC approved a further Power Sales Agreement between the Company and Allegheny Energy 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 the Public Utility Regulatory Policies Act of 1978 (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 the Company 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, 2001, there was an increase in Maryland base rates. This increase is a result of the phase-in of the rate increase approved by the Maryland PSC in October 1998 pursuant to a settlement agreement, which includes recognition and dollar-for-dollar recovery of costs to be incurred from the AES Warrior Run PURPA project. The Maryland PSC approved rates to each customer class on December 22, 1998. Under the terms of the agreement, the Company increased its rates about four percent in each of the years 1999, 2000, and 2001 (a $79 million total revenue increase during 1999 through 2001). The increases were designed to recover additional costs of about $131 million, over the 1999-2001 period, for capacity purchases from the project net of alleged over-earnings of $52 million for the same period. The agreement also requires that the Company share with customers 50 percent of earnings above an 11.4 percent return on equity for 1999 and 2000. As a result, 50 percent of the amount above the threshold earnings amount, or $9.7 million applicable to 1999, was distributed to

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customers in the form of an Earnings Sharing Credit, effective June 7, 2000, through April 30, 2001. An Earnings Sharing Credit of $1.9 million applicable to 2000 was distributed to customers from September 6, 2001 through January 8, 2002.

Effective with bills rendered on or after January 8, 2002, there was a decrease in Maryland distribution rates. This decrease, or Customer Choice Credit, is a result of implementing the rate reductions called for in the settlement agreement approved in December 1999. Under the terms of the agreement (covering stranded cost quantification mechanism, price protection mechanism, and unbundled rates), the Company decreased its rates seven percent for residential customers and one half of one percent for the majority of commercial and industrial customers. 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 the electric universal surcharge has been introduced, both of which must be recovered under the Company's distribution rate cap consistent with the settlement agreement. Accordingly, distribution rates have been further reduced by $3 million from the previously approved rates in the settlement agreement. The distribution rate cap for all customers is effective through 2004.

Regional Transmission Organization (RTO)

On March 15, 2001, Allegheny Energy and the Pennsylvania-New Jersey-Maryland Interconnection, LLC (PJM) filed documents with the FERC to expand the PJM transmission system and energy market through the creation of PJM-West. The filing represents collaboration among Allegheny Energy, PJM, and numerous stakeholders. Allegheny Energy and PJM have asked the FERC to confirm that PJM-West satisfies the FERC's requirements for a RTO as set forth in Order No. 2000. Under the PJM-West proposal, Allegheny Energy's regulated utility subsidiaries will transfer operational control over their transmission system to PJM. Allegheny Energy will adopt PJM's transmission pricing methodology, including PJM's congestion management system. In addition, PJM will expand its day-ahead and real-time energy markets to include PJM-West. As a result, energy suppliers will be able to reach consumers anywhere within the expanded PJM/PJM-West market at a single transmission rate, instead of paying multiple transmission rates as they do today.

On January 30, 2002, the FERC authorized Allegheny Energy and PJM to proceed with PJM-West effective March 1, 2002. The FERC's order set for hearing the question whether Allegheny Energy had adequately supported its claim to recover anticipated lost transmission revenues and start-up expenses, and created uncertainty as to whether the FERC intended to initiate a general investigation into Allegheny Energy's transmission rates, which could potentially lead to an overall reduction to its transmission revenues. Allegheny Energy requested clarification, and on March 1, 2002, the FERC issued a further order explaining that its January 30, 2002 order did not initiate a general investigation of Allegheny Energy's transmission revenues. Accordingly, in light of the limited scope of the hearing ordered by the FERC, Allegheny Energy has elected to proceed with PJM-West effective April 1, 2002. Allegheny Energy anticipates the formation of PJM-West will enhance its ability to compete for power sales in the expanded PJM/PJM-West market area.

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Union Contract Negotiations

On April 30, 2001, Allegheny Energy Service Corporation's (AESC), an affiliate that employs all of the employees who work on behalf of the Company (see Note L), collective bargaining agreement with the Utility Workers Union of America (UWUA) System Local 102 expired. The parties entered into a contract extension through May 31, 2001. AESC and the UWUA were unable to reach agreement on a new labor pact by this deadline. The parties continue to work under the terms and conditions of the prior labor agreement on a day-to-day basis. AESC and the UWUA have continued to meet from time to time in pursuit of a long-term agreement. The prior agreement covers approximately 265 employees who work on behalf of the Company.

During 2001, AESC successfully negotiated new labor agreements with three bargaining units of the International Brotherhood of Electrical Workers. Of the three bargaining units, one represented employees who work on behalf of the Company. During 2002, AESC anticipates negotiations with five other bargaining units, all related to affiliates of the Company, whose contracts expire during the year.

Recapitalization

On September 30, 1999, the Company redeemed $16.4 million of preferred stock. In April 2000, the Company's shareholders amended its Articles of Incorporation. Prior to the amendment and restatement, the Company was authorized to issue 23,000,000 shares of common stock without par value and 5,378,611 shares of preferred stock with $100 par value per share. The Company now has authority to issue 26,000,000 shares of common stock with $.01 par value per share and 10,000,000 shares of preferred stock with $.01 par value per share. As a result of the change in par value, the Company's common stock decreased by and other paid-in capital increased by $447.5 million.

REVIEW OF OPERATIONS

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires the Company to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period.

Earnings Summary

(Millions of Dollars)	2001	2000	1999

Operations	$ 48.0	$ 84.4	$100.6
Extraordinary charge, net (Notes B and C
to the consolidated financial statements)		(13.9)	_(17.0)
Consolidated Net Income	$ 48.0	$ 70.5	$ 83.6

Earnings for 2001 and 2000, before the extraordinary charge, decreased by $36.4 million and $16.2 million, respectively, primarily due to the August 1, 2000, transfer, at book value, of 2,100 MW of the Company's generating capacity to Allegheny Energy Supply. The extraordinary charge in 2000 of $13.9 million, net of taxes, reflects a write-off by the Company of costs determined to be unrecoverable as a result of West Virginia legislation requiring deregulation of electric generation and recognition of a rate stabilization obligation. The extraordinary charge in 1999 resulted from the Maryland electric restructuring order. See Notes B and C to the consolidated financial statements for additional details.

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Sales and Revenues

Percentage changes in revenues and kilowatt-hour (kWh) sales in 2001 and 2000 by major retail customer classes were:

	2001 vs 2000		2000 vs 1999
	Revenues	kWh	Revenues	kWh

Residential	4.2 %	2.3%	.5%	4.5%
Commercial	1.0	1.7	(2.8)	4.6
Industrial	6.1	3.1	(2.3)	2.1
Total retail	4.0%	2.5%	(1.1)%	3.4%

The changes in residential kWh sales are more weather sensitive than the other classes. The changes in residential kWh sales for 2001 and 2000 were due primarily to an increase in the number of customers served. The growth in the number of residential customers was 2.1 percent and 1.9 percent in 2001 and 2000, respectively. The revenue increase for 2001 was the result of an increase in customers served coupled with an increase in the average rate-cents per kWh. The revenue increase in 2000 was slightly offset by reductions applied to certain customers' revenues. The reductions included credits to customer bills resulting from conditions within the Maryland settlement agreements and adjustments to revenues related to the over-recovery from the AES Warrior Run cogeneration project.

Commercial kWh sales are also affected by weather, but to a lesser extent than residential. The increases in commercial kWh sales for 2001 and 2000 were due primarily to the growth in the number of customers served, with increases of 2.8 percent and 2.9 percent in 2001 and 2000, respectively. The increase in 2001 was partially offset by a decrease in customer usage.

The increase in industrial kWh sales for 2001 was due to an increase in usage by a major customer in the primary metal industry and several customers in the food products industry. The increase in industrial kWh sales for 2000 was due to an increase in usage by customers in the primary metal industry and in the stone, glass, clay, and concrete industry.

In addition to usage and customers served, revenues for the residential, commercial, and industrial classes are affected by an AES Warrior Run surcharge. For these revenue classes, the AES Warrior Run surcharges have decreased for 2001. The changes for the AES Warrior Run surcharges are the result of the Company selling AES Warrior Run output into the wholesale energy market in 2001 and part of 2000. The Company did not sell the AES Warrior Run output into the wholesale market for the first six months of 2000. For additional information on the AES Warrior Run project, see "Rate Matters" beginning on page 3.

The decrease in revenues in 2000 for commercial and industrial customers was due primarily to a decrease in the fuel portion of customer bills, a decrease in surcharge revenues applicable to recovery of costs related to purchased power from the AES Warrior Run cogeneration project, a decrease in Virginia base rates, and, to a lesser extent, Maryland deregulation, which gave Maryland customers of the Company the ability to choose another energy supplier effective July 1, 2000.

In October 1998, the Maryland PSC approved a settlement agreement for the Company. Under the terms of that agreement, the Company increased its rates about four percent in 1999, 2000 and 2001 (a $79 million total revenue increase during 1999 through 2001).

Revenues reflect not only changes in kWh sales and base rate changes, but also any changes in revenues from fuel and energy cost adjustment clauses (fuel clauses). Effective July 1, 2000, a fuel clause ceased to exist for the Company's West Virginia jurisdiction and ceased to exist for the Company's Virginia jurisdiction effective August

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7, 2000. Through June 30, 2000, changes in fuel revenues had no effect on the Company's net income because increases and decreases in fuel and purchased power costs and sales of transmissions services and bulk power were passed on to customers by adjustment of customers' bills through a fuel clause. Effective July 1, 2000, the Company assumed the risk and benefits of changes in fuel and purchased power costs and sales of transmission services and bulk power in its Maryland and West Virginia jurisdictions, and on August 7, 2000, for its Virginia jurisdiction.

Wholesale and other revenues, including affiliates were as follows:

(Millions of Dollars)	2001	2000	1999

Wholesale customers	$22.3	$21.9	$21.5
Affiliated companies	26.9	45.2	11.4
Street lighting and other	14.5	8.6	4.7
Deferred revenues	4.8	2.3	(19.9)
Total wholesale and other revenues	$68.5	$78.0	$17.7

Wholesale customers are cooperatives and municipalities that own their distribution systems and buy all or part of their bulk power needs from the Company under the FERC regulation. Competition in the wholesale market for electricity was initiated by the national Energy Policy Act of 1992, which permits wholesale generators, utility-owned and otherwise, and wholesale customers to request from owners of bulk power transmission facilities a commitment to supply transmission services. Wholesale customer revenue for 2001 and 2000 remained relatively flat as compared to 2000 and 1999, respectively.

Revenues from sales to affiliated companies represent sales of energy and intercompany allocations of generating capacity, generation spinning reserves, and transmission services pursuant to a power supply agreement among the Company and the other regulated utility subsidiaries of Allegheny Energy. The decrease in sales to affiliated companies for 2001 as compared to 2000 was the result of the transfer of the Company's generating capacity to Allegheny Energy Supply on August 1, 2000. The increase in revenues from sales to affiliated companies for 2000 as compared to 1999 was the result of power sales to Allegheny Energy Supply.

Transmission services and bulk power sales include transactions of transmission services, bulk power, and other energy services to power marketers and other utilities. Transmission services and bulk sales for 2001, 2000, and 1999 were as follows:

(Millions of Dollars)	2001	2000	1999
Bulk power	$46.9	$28.9	$ 8.4
Transmission and other energy services
to nonaffiliated companies	17.5	17.7	16.2
Total	$64.4	$46.6	$24.6

The costs of purchased power and revenues from sales to power marketers and other utilities, including transmission services, were recovered from or credited to customers under fuel and energy cost recovery procedures. The impact to the fuel and energy cost recovery clauses may be either positive or negative depending on whether the Company is a net buyer or seller of electricity during such periods and the open commitments that exist at such times. The impact of such price volatility was insignificant to the Company in the first six months of 2000 because changes are passed to customers through operation of fuel clauses. Effective July 1, 2000, the fuel clause was discontinued in the Company's Maryland and West Virginia jurisdictions, and was discontinued for its Virginia jurisdiction effective August 7, 2000. The discontinuation of fuel clauses will increase the risk associated with the volatility of earnings for the Company. With the discontinuation of the fuel clauses, the Company assumes the risk and benefits of changes in fuel and purchased power costs and sales of transmission services and bulk power in its Maryland, West Virginia and Virginia jurisdictions.

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Revenue from transmission services and bulk power sales increased in 2001 and 2000 by $17.8 million and $22.0 million, respectively. The increase is attributable to the Company selling the AES Warrior Run output into the wholesale energy market beginning in the latter half of 2000.

Operating Expenses

Fuel expense was eliminated for 2001 and decreased by $56.3 million for 2000, as compared to 1999, as a result of the transfer of the Company's 2,100 MW generating capacity to Allegheny Energy Supply on August 1, 2000.

Purchased power and exchanges, net, represents power purchases from and exchanges with other companies, including affiliated companies and, purchases from qualified facilities under PURPA and consists of the following items:

(Millions of Dollars)	2001	2000	1999

Nonaffiliated transactions:
Purchased power:
Other	$	$ 3.8	$ 15.7
From PURPA generation	88.9	87.1	1.5
Power exchanges, net	.1	3.9	(2.6)
Affiliated transactions-energy and capacity charges	427.2	244.8	112.4
Purchased power and exchanges, net	$516.2	$339.6	$127.0

Purchased power and exchanges, net increased by $176.6 million and $212.6 million for 2001 and 2000, respectively. The increase for both years is primarily the result of the Company transferring its generating capacity to Allegheny Energy Supply; thus requiring the Company to purchase power in order to meet its retail load requirements in Maryland and Virginia. The Company's method of satisfying its West Virginia load requirement is discussed below. Purchased power from PURPA generation for 2001 remained relatively flat as compared to 2000. The increase in purchased power from PURPA generation for 2000 as compared to 1999 was primarily due to the start of commercial operations of the AES Warrior Run cogeneration project on February 10, 2000, in the Company's Maryland service territory. The Maryland PSC approved the Company's full recovery of the AES Warrior Run purchased power costs as part of the September 23, 1999, settlement agreement. Accordingly, the Company defers, as a component of other operation expenses, the difference between revenues collected related to AES Warrior Run and the cost of the AES Warrior Run purchased power.

The increases in other operation expenses for 2001 and 2000 of $34.5 million and $19.1 million, respectively, are primarily the result of leasing of generating assets. The transfer of the Company's generating assets to Allegheny Energy Supply on August 1, 2000, included the Company's assets serving West Virginia customers. A portion of these assets has been leased back by the Company to serve its West Virginia jurisdictional retail customers. The original lease term was for one year. The Company and Allegheny Energy Supply have mutually agreed to continue the lease beyond August 1, 2001. The ultimate treatment of the Company's West Virginia jurisdictional generating assets will be resolved when the West Virginia legislature addresses implementation of deregulation. For the years ended 2001 and 2000, rental expense from this arrangement totaled $75.2 million and $37.1 million, respectively. The increase in 2000 was offset by a reduction in expenses as a result of the transfer of the generation assets on August 1, 2000.

The decreases in maintenance expenses in 2001 and 2000 of $11.7 million and $15.8 million, respectively, were due primarily to the transfer of the Company's generating assets to Allegheny Energy Supply. Until the August 1, 2000, transfer of generating assets, maintenance expenses represented costs incurred to maintain the power stations, the T&D system, and general plant. These costs reflected routine maintenance of equipment

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and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. Effective with the August 1, 2000 transfer of generating assets, the Company's maintenance costs no longer reflect power station related maintenance expenses. Variations in maintenance expense result primarily from unplanned events and planned projects, which vary in timing and magnitude depending upon the length of time equipment has been in service without an overhaul and the amount of work found necessary when the equipment is dismantled.

The decreases in depreciation and amortization expense in 2001 and 2000 of $27.5 million and $14.5 million, respectively, reflects the transfer of the Company's generating assets to Allegheny Energy Supply, offset, in part, by depreciation of new capital additions.

The decreases in taxes other than income taxes for 2001 and 2000 of $16.9 million and $4.0 million, respectively, were primarily due to lower West Virginia Business and Occupation Taxes and property taxes. The decrease is the result of the transfer of the Company's generating assets to Allegheny Energy Supply.

The decreases in federal and state income taxes for 2001 and 2000 of $6.5 million and $4.1 million, respectively, resulted from a decrease in taxable income. Note E to the consolidated financial statements provides a further analysis of income tax expense.

Other Income and Deductions

The decreases in other income, net, for 2001 and 2000 were primarily due to a decrease in the Company's portion of Allegheny Generating Company's (AGC) earnings due to the transfer of the Company's ownership interest in AGC to Allegheny Energy Supply on August 1, 2000, coupled with a decrease in interest income and an increase in losses associated with Maryland coal brokerage activities.

Interest Charges

The decrease in interest charges for 2001 was due primarily to a reduction in long-term debt outstanding related to the Company's release from co-obligor status with Allegheny Energy Supply in December 2000 on $104.2 million of pollution control notes. Allegheny Energy Supply assumed these notes in conjunction with the Company's transfer of generating assets to Allegheny Energy Supply. Interest charges also decreased as a result of the maturity of $75 million of the Company's 5 7/8 percent series first mortgage bonds in March 2000. The decrease in interest charges for 2000 was due to a reduction in average long-term debt outstanding, offset by an increase in short-term debt.

Extraordinary Item

The extraordinary charge in 2000 of $ 22.6 million ($13.9 million after tax) was required to recognize $20.0 million ($12.3 million after tax) for the write-off of unrecoverable regulatory assets and the recognition of rate stabilization obligations due to West Virginia deregulation, and an additional $2.6 million ($1.6 million after tax) due to write-offs associated with deregulation in Virginia.

The extraordinary charge in 1999 of $26.9 million ($17.0 million after taxes) was required to reflect a write-off of certain disallowances in the Maryland PSC's December 1999 order. See Notes B and C to the consolidated financial statements for additional information.

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FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES

Liquidity and Capital Requirements

To enhance liquidity and meet short-term borrowing needs, the Company has access to lines of credit and an Allegheny Energy internal money pool. The Company is a participant, along with Allegheny Energy and various affiliates, in bank lines of credit totaling $400 million for general corporate purposes and as a backstop to their commercial paper programs. At December 31, 2001, a subsidiary of Monongahela Power, Mountaineer Gas, had drawn down $14.4 million of the lines of credit. The remaining $385.6 million lines of credit were supporting commercial paper of Allegheny Energy and were unavailable to the Company. In addition to bank lines of credit, an Allegheny Energy internal money pool accommodates intercompany short-term borrowing needs, to the extent that Allegheny Energy and its regulated subsidiaries have funds available. The Company has SEC authorization for total short-term borrowings, from all sources, of $130 million. The Company has fee arrangements on all of its lines of credit and no compensating balance requirements.

The Company has also executed letter of credit facilities to provide for additional capacity of $10.6 million. At December 31, 2001, the entire amount of the letter of credit facilities was outstanding.

The Company has various obligations and commitments to make future cash payments under contracts, such as debt instruments, lease arrangements, purchased power agreements, and other contracts. The table below provides a summary of the payments due by period for these obligations and commitments.

(Thousands of Dollars)	Payments Due by Period
Contractual Cash Obligations	Less Than			After
and Commitments	1 Year	2-3 Years	4-5 Years	5 Years	Total

Long-term debt*	$	$	$100,000	$ 320,000	$ 420,000
Capital lease obligations	3,162	5,102	3,345	3,682	15,291
Operating lease obligations	1,235	466			1,701
PURPA purchased power	90,106	183,468	187,797	2,517,948	2,979,319

Total	$ 94,503	$189,036	$291,142	$2,841,630	$3,416,311
*Long-term debt does not include unamortized debt expense, discounts, and premiums.

Capital expenditures, including construction expenditures, in were $54.8 million, $72.3 million, and $91.6 million for 2001, 2000, and 1999, and, for 2002 and 2003, are estimated at $50.8 million and $64.9 million, respectively.

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Cash Flow

Internally generated funds, consisting of cash flows from operations reduced by common dividends, was $32.6 million in 2001, compared with negative cash flows of $2.6 million in 2000.

Cash flows from operations for 2001 decreased by $22.6 million from the comparable 2000 period primarily from changes in net income, depreciation and amortization, deferred investment credit and income taxes, accrued taxes, and accrued interest levels. Cash flows from operations for 2000 decreased by $73.5 million from the comparable 1999 period reflecting changes in net income, depreciation and amortization, deferred revenues, deferred power costs, and accounts payable to affiliates.

Cash flows used in investing decreased by $16.8 million and $19.2 million for 2001 and 2000, respectively due to reductions in construction expenditures.

Cash flows used in financing decreased by $32.5 million for 2001 from the comparable 2000 period due primarily to a reduction in dividends paid. Cash flows used in financing increased by $ 8.2 million for 2000 from the comparable 1999 period due to changes in short-term debt and notes receivable from subsidiary.

Financing

Long-term Debt

On November 6, 2001, the Company issued debt of $100 million five percent notes due on November 1, 2006. The Company used the net proceeds from these notes, together with other corporate funds, for the following purposes: to redeem $50.0 million principal amount of the Company's first mortgage bonds, eight percent Series due on June 1, 2006, at the optional redemption price of 100 percent of their principal amount plus accrued interest to the redemption date; to redeem $45.5 million principal amount of the Company's eight percent Quarterly Income Debt Securities (QUIDS) due September 30, 2025, at a redemption price of 100 percent of their principal amount plus accrued interest to the redemption date; to pay issuance expenses relating to the notes; and to add to the Company's general funds which, together with other funds available to the Company, were used for other corporate purposes, including financing the Company's construction program.

In August 2000, Allegheny Energy Supply assumed the service obligation for $104.2 million of pollution control debt in conjunction with the transfer of the Company's generating assets to Allegheny Energy Supply. Through December 22, 2000, the Company was co-obligor on the pollution control debt and reflected the debt in its financial statements. The Company accrued interest expense on the pollution control debt and then reduced interest accrued and increased other paid-in capital when Allegheny Energy Supply paid interest.

On December 22, 2000, the trustees of the pollution control notes released the Company from its co-obligor status as a result of Allegheny Energy Supply acquiring surety bonds, which would repay these notes in the event Allegheny Energy Supply defaults. In accordance with FASB SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," the Company derecognized the pollution control notes with the effect of increasing equity by $104.3 million. See Note D to the consolidated financial statements for additional information.

On June 1, 2000, the Company issued $80 million of floating rate private placement notes, due May 1, 2002, assumable by Allegheny Energy Supply upon its acquisition of the Company's Maryland generating assets. In August 2000, after the Company's generating assets were transferred to Allegheny Energy Supply, the notes were remarketed as Allegheny Energy Supply floating rate (three-month London Interbank Offer Rate (LIBOR) plus .80 percent) notes with the same maturity date. No additional proceeds were received.

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In March 2000, $75 million of the Company's 5 7/8 percent series first mortgage bonds matured.

The Company had no long-term debt due within one year at December 31, 2001.

Short-term Debt

The Company had $24.2 million and $32.9 million in short-term debt outstanding at December 31, 2001 and 2000, respectively. The outstanding short-term debt consisted of commercial paper in 2001 and in 2000, consisted of commercial paper and a line of credit listed as a bank note payable. In addition, the Company had borrowings outstanding from the money pool at December 31, 2001 and 2000 of $33.4 million and $9.8 million, respectively.

SIGNIFICANT CONTINUING ISSUES

Electric Energy Competition

In addition, with the wholesale electricity market becoming more competitive, certain states have taken active steps toward allowing retail customers the right to choose their electricity supplier.

Allegheny Energy is at the forefront of state-implemented retail competition, having negotiated settlement agreements in all of the states that Allegheny Power serves. Maryland, Pennsylvania, Ohio, and Virginia have retail choice programs in place. West Virginia's Legislature has approved a deregulation plan pending additional legislation regarding tax revenues for state and local governments and allowing implementation. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider the deregulation plan in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

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Maryland Activities

On June 7, 2000, the Maryland PSC approved the transfer of the generating assets of the Company to Allegheny Energy Supply. The transfer was completed in August 2000. Maryland customers of the Company have had the right to choose an alternate electric supplier since July 1, 2000. While few customers have switched suppliers in the Company's service territory, some retail competition is occurring in other portions of the state.

On July 1, 2000, the Maryland PSC issued a restrictive order imposing standards of conduct for transactions between Maryland utilities and their affiliates. Among other things, the order:

-
  restricts sharing of employees between utilities and affiliates;
-  announces the Maryland PSC's intent to impose 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 unqualified benefits;" and
-  requires asymmetric pricing for asset transfers between utilities and their affiliates.    Asymmetric pricing requires that transfers of assets from the regulated utility to an affiliate    be recorded at the greater of book cost or market value while transfers of assets from the    affiliate to the regulated utility be recorded at the lesser of book costs or market value.

The Company, along with substantially all of Maryland's natural gas and electric utilities, filed a Circuit Court petition for judicial review and a motion for stay of the order. On April 25, 2001, the Circuit Court issued its decision affirming much of the Maryland PSC's order, but remanding portions of the order to the Maryland PSC, including the requirement for asymmetric pricing for asset transfers between utilities and their affiliates.

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The Company and other Maryland natural gas and electric utilities have noted an appeal of the Circuit Court's decision to Maryland's Court of Special Appeals. The Court of Appeals, Maryland's highest court, assumed jurisdiction over the appeal. After the filing of briefs, the Court of Appeals heard oral arguments on January 8, 2002.

The Maryland PSC also has initiated a proceeding, Case No. 8868, to investigate certain affiliated activities of the Company and has also docketed similar proceedings for Maryland's other natural gas and electric companies. Case No. 8868 is pending before a Maryland PSC Hearing Examiner.

The Maryland PSC has initiated a proceeding, Case No. 8907, to investigate the Company's proposed revisions to its line extension charges and policies for non-residential customers. The Maryland PSC delegated the proceeding to the Hearing Examiner Division. The Hearing Examiner held a prehearing conference on January 10, 2002, and established a procedural schedule. The parties are entering into settlement discussions.

By letter order dated December 17, 2001, the Maryland PSC directed parties to commence meetings on January 17, 2002, on the status of the provision of default service. The Company will participate in those meetings.

Virginia Activities

The Virginia Electric Utility Restructuring Act (Restructuring Act) became law on March 25, 1999. All state utilities were required to submit a restructuring plan by January 1, 2001, to be effective on January 1, 2002. On December 21, 2001, the Virginia SCC approved the Company's Phase II of the Functional Separation Plan. In August 2000, the Company transferred its Virginia jurisdictional generating assets, excluding the hydroelectric assets located within Virginia, to Allegheny Energy Supply at book value. The Virginia hydroelectric assets were transferred on June 1, 2001 to Green Valley Hydro. Customer choice was implemented for all customers in the Company's service territory beginning on January 1, 2002.

The Restructuring Act was amended during the 2000 General Assembly legislative session to direct the Virginia SCC to prepare for legislative approval, a plan for competitive metering and billing and to authorize the Virginia SCC to implement a consumer education program on electric choice, funded through its regulatory tax. On December 12, 2000, the Virginia SCC issued a report on competitive metering and billing. Its recommendations include allowing licensed electricity suppliers to provide billing services, with the customer selecting its preferred billing option. The Virginia SCC also recommended that legislative action on competitive metering be deferred pending further study, due to the complexities of the issue and limited competitive metering activities nationally. On May 15, 2001, the Virginia SCC initiated proceedings to establish rules and regulations for consolidated billing services, competitive metering, and customer minimum stay periods.

Various rulemaking proceedings to implement customer choice are ongoing before the Virginia SCC, including an application by the Company to participate in a regional transmission entity (PJM West).

West Virginia Activities

Electric restructuring in West Virginia remains unresolved and awaits further legislative action. In January 2000, the West Virginia PSC submitted a restructuring plan to the Legislature for approval that would open full retail competition on January 1, 2001. On March 11, 2000, the West Virginia Legislature approved the West Virginia PSC's plan, but assigned the tax issues surrounding the plan to a legislative subcommittee for further study. The start date of competition is contingent upon the necessary tax changes being made and implementation being approved by the Legislature. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

M-66

The Potomac Edison Company
and Subsidiaries

As approved by the West Virginia PSC, the Company transferred its generating assets to Allegheny Energy Supply in August 2000. In accordance with the same restructuring agreement, the Company and Monongahela Power implemented a commercial and industrial rate reduction program on July 1, 2000.

The status of electric energy competition in Ohio and Pennsylvania in which affiliates of the Company serve are as follows:

Ohio Activities

The Ohio General Assembly passed legislation in 1999 to restructure its electric utility industry. As of January 1, 2001, all of the state's electricity customers were able to choose their electricity supplier, beginning a five-year transition to market rates. Residential customers are guaranteed a five percent cut in the generation portion of their rate.

Monongahela Power reached a stipulated agreement with major parties on a transition plan to bring electric choice to its 29,000 Ohio customers. None of Monongahela Power's Ohio customers have switched to another supplier. The restructuring plan allowed Monongahela Power to transfer its Ohio and FERC jurisdictional generating assets to Allegheny Energy Supply at book value on or after January 1, 2001. That transfer was made on June 1, 2001.

Derivative Instruments and Hedging Activities

At December 31, 2001, the Company had no financial instruments, commodity contracts, or other commitments that required recognition as assets or liabilities on the balance sheet at fair value under the provisions of SFAS 133.

M-67

The Potomac Edison Company
and Subsidiaries

Quantitative and Qualitative Disclosure About Market Risk

The Company is exposed to market risks associated with commodity prices and interest rates. The commodity price risk exposure results from market fluctuations in the price of electricity as discussed below. The interest rate risk exposure results from changes in interest rates related to variable- and fixed-rate debt. The Company is mandated by Allegheny Energy's Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

As a result of the Company's restructuring plan, the Company unbundled its rates to reflect three separate charges-a generation (or supply) charge, a Competitive Transition Charge (CTC), and T&D charges. The generation rates applied to customers not choosing an alternate generation supplier are capped through a transition period that ends December 31, 2008.

Pursuant to agreements, Allegheny Energy Supply provides the Company with the total amount of electricity needed for those customers not choosing an alternate generation supplier during the transition period. The original rate schedule for these agreements, effective through December 31, 2000, established fixed purchase prices corresponding to the capped generation rates charged to customers not electing an alternate generation supplier. Thus, the cost of purchased electricity was recovered through the capped generation rates charged to customers.

Under a revised rate schedule approved by the FERC effective January 1, 2001, a portion of the electricity purchased from Allegheny Energy Supply now has a market-based pricing component that could result in higher electricity prices when market prices exceed the fixed prices (corresponding to the capped generation rates). Purchased electricity prices would never be set below the established fixed prices. The amount of electricity purchased under this rate schedule that is subject to market prices escalates each year through June 30, 2007, in Virginia and December 31, 2008, in Maryland (from 4 percent of total purchases in 2001 to approximately 31 percent in 2008). To the extent that the Company purchases electricity from Allegheny Energy Supply at market prices that exceed the established fixed prices, the Company's results of operations could be adversely affected.

New Accounting Standards

In July 2001, the FASB issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." These standards will change the accounting for business combinations and goodwill in two significant ways. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. Use of the pooling-of-interests method will be prohibited. SFAS No. 141 is not expected to a have a material effect on the Company.

M-68

The Potomac Edison Company
and Subsidiaries

M-69

West Penn Power Company
and Subsidiaries

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Factors That May Affect Future Results

Certain statements within constitute forward-looking statements with respect to West Penn Power Company and its subsidiaries (collectively, the Company). Such forward-looking statements include statements with respect to deregulated activities and movements toward competition in the states served by the Company, markets, products, services, prices, results of operations, capital expenditures, regulatory matters, liquidity and capital resources, the effect of litigation, and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results of the Company will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

Factors that could cause actual results of the Company to differ materially include, among others, the following: general economic and business conditions, including the continuing effect on the economy caused by the September 11, 2001, terrorists' attacks; changes in industry capacity, development, and other activities within the utility industry; changes in the weather and other natural phenomena; changes in technology; changes in the price of purchased power; changes in laws and regulations applicable to the Company, its markets, or its activities; litigation involving the Company; environmental regulations; the loss of any significant customers and suppliers; the effect of accounting policies issued periodically by accounting standard setting bodies; and changes in business strategy, operations, or development plans.

Overview

The Company is a wholly-owned subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and along with its regulated utility affiliates-Monongahela Power Company (Monongahela Power), including its subsidiary, Mountaineer Gas Company (Mountaineer Gas), and The Potomac Edison Company (Potomac Edison), collectively doing business as Allegheny Power-operate electric and natural gas transmission and distribution (T&D) systems. Allegheny Power also generates electric energy for its West Virginia jurisdiction, where deregulation of electric generation has not been implemented. The Company's business is the operation of electric T&D systems in western Pennsylvania.

Pennsylvania Deregulation

See Note B to the consolidated financial statements for a detailed discussion of the deregulation of the electric utility industry in Pennsylvania and, specifically, the provisions of the Company's restructuring plan that were approved by the Pennsylvania Public Utility Commission (Pennsylvania PUC) on May 29, 1998 (as amended on November 19, 1998). See also Notes C and D to the consolidated financial statements for related information.

As a result of Pennsylvania's deregulation laws and the Company's related restructuring plan, and in accordance with Financial Accounting Standards Board (FASB) Emerging Issues Task Force (EITF) Issue No. 97-4, "Deregulation of the Pricing of Electricity-Issues Related to the Application of FASB Statement Nos. 71 and 101," the Company discontinued application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," to its electric generation business in 1998 resulting in an extraordinary charge of $466.9 million ($275.4 million after taxes) reflecting the write-off of certain disallowances. However, the Company's restructuring plan provides for the recovery of, and return on, $670 million in transition costs beginning January 1999.

M-70

West Penn Power Company
and Subsidiaries

Under the terms of the Company's restructuring plan, two-thirds of the Company's customers were permitted to choose an alternate electricity supplier beginning January 2, 1999. In other words, two-thirds of the Company's customers were given the ability to choose another provider for the generation or supply portion of their service while retaining the Company's transmission and distribution services. All of the Company's customers were permitted to choose an alternate electricity supplier beginning January 2, 2000. They were able to remain as Company customers at the Company's capped generation rates or to alternate back and forth. Under Pennsylvania's restructuring law, all electric utilities, including the Company, retain the responsibility to provide electricity to all customers in their respective franchise territories who do not choose an alternate electricity supplier (as the provider of last resort). The Company retains this obligation through a transition period that ends December 31, 2008. As of December 31, 2001, less than 0.2% of the Company's customers were using alternate electricity suppliers.

From January 1, 1999, through November 17, 1999, the Company participated as a supplier of electricity in deregulated markets through the sale of output from two-thirds of its generation (see "Review of Operations - Operating Revenues" for additional information). On November 18, 1999, the Company transferred its generating capacity of 3,778 megawatts (MW) to Allegheny Energy Supply Company, LLC (Allegheny Energy Supply), the nonutility generating subsidiary of Allegheny Energy, at book value. From November 18, 1999, through January 1, 2000, Allegheny Energy Supply leased back to the Company one-third of its generating assets, providing the Company with the unlimited right to use those facilities to serve its regulated load. Pursuant to contracts, Allegheny Energy Supply provides the Company with the total amount of electricity, up to its retail load, that it may demand as the provider of last resort during the transition period ending December 31, 2008.

In 1999, the Company completed the following steps in its recapitalization process concurrent with its restructuring plan.
- $600 million of transition bonds were issued in November 1999;
- $525 million of first mortgage bonds were called or redeemed during the year;
- $79.7 million of preferred stock was called or redeemed in July 1999; and
- the Company revised its Articles of Incorporation to provide greater financial flexibility.

Other Significant Events in 2001, 2000, and 1999

Initial Public Offering of Allegheny Energy Supply

On July 23, 2001, Allegheny Energy filed a U-1 application with the Securities and Exchange Commission (SEC), seeking authorization under the Public Utility Holding Company Act of 1935 (PUHCA) to effect an initial public offering (IPO) of up to 18 percent of the common stock in a new holding company, which would own 100 percent of Allegheny Energy Supply, and then distribute the remaining common stock owned by Allegheny Energy to its shareholders on a tax-free basis. In October 2001, Allegheny Energy announced that the proposed IPO would be delayed due to market and other conditions. In January 2002, Allegheny Energy announced that it would not proceed with the IPO. In February 2002, Allegheny Energy filed an amendment to the U-1 application filed on July 23, 2001, with the SEC, withdrawing its IPO application.

M-71

West Penn Power Company
and Subsidiaries

Rate Matters

Effective January 1, 2002, the Pennsylvania Department of Revenue increased the gross receipts tax rate from 4.4 percent to 5.9 percent for electric distribution companies in the state, including the Company. State law directs the Company to recover these increased tax charges by means of a State Tax Adjustment Surcharge (STAS) added to customer bills. On October 29, 2001, the Company filed a request with the Pennsylvania PUC to recover the increased tax liability of approximately $16.8 million from customers. By an order entered December 21, 2001, the Pennsylvania PUC directed the Company to include the STAS on customer bills rendered between January 1, 2002, and December 31, 2002. On January 8, 2002, the Office of Consumer Advocate (OCA) filed an appeal of the Pennsylvania PUC order to the Commonwealth Court of Pennsylvania. Any further Pennsylvania PUC action on this matter is held in abeyance pending the resolution of the OCA Petition for Review in the Commonwealth Court. The Company intends to intervene at the Commonwealth Court in support of the Pennsylvania PUC's decision.

Regional Transmission Organization (RTO)

On March 15, 2001, Allegheny Energy and the Pennsylvania-New Jersey-Maryland Interconnection, LLC (PJM) filed documents with the Federal Energy Regulatory Commission (FERC) to expand the PJM transmission system and energy market through the creation of PJM-West. The filing represents a collaboration between Allegheny Energy, PJM, and numerous stakeholders. Allegheny Energy and PJM have asked the FERC to confirm that PJM-West satisfies the FERC's requirements for RTOs as set forth in Order No. 2000. Under the PJM-West proposal, Allegheny Energy's regulated utility subsidiaries will transfer operational control over their transmission system to PJM. Allegheny Energy will adopt PJM's transmission pricing methodology, including PJM's congestion management system. In addition, PJM will expand its day-ahead and real-time energy markets to include PJM-West. As a result, energy suppliers will be able to reach consumers anywhere within the expanded PJM/PJM-West market at a single transmission rate, instead of paying multiple transmission rates as they do today.

On January 30, 2002, the FERC authorized Allegheny Energy and PJM to proceed with PJM-West effective March 1, 2002. The FERC's order set for hearing the question of whether Allegheny Energy had adequately supported its claim to recover anticipated lost transmission revenues and start-up expenses, and created uncertainty as to whether the FERC intended to initiate a general investigation into Allegheny Energy's transmission rates, which could potentially lead to an overall reduction to its transmission revenues. Allegheny Energy requested clarification, and on March 1, 2002, the FERC issued a further order explaining that its January 30, 2002, order did not initiate a general investigation of Allegheny Energy's transmission revenues. Accordingly, in light of the limited scope of the hearing ordered by the FERC, Allegheny Energy has elected to proceed with PJM-West effective April 1, 2002. Allegheny Energy anticipates the formation of PJM-West will enhance its ability to compete for power sales in the expanded PJM/PJM-West market area.

M-72

West Penn Power Company
and Subsidiaries

Union Contract Negotiations

On April 30, 2001, the collective bargaining agreement between Allegheny Energy Service Corporation (AESC), an affiliate that employs all of the employees who work on behalf of the Company (see Note N), and the Utility Workers Union of America (UWUA) System Local 102 expired. The parties entered into a contract extension through May 31, 2001. AESC and the UWUA were unable to reach agreement on a new labor pact by this deadline. The parties continue to work under the terms and conditions of the prior labor agreement on a day-to-day basis. AESC and the UWUA have continued to meet from time to time in pursuit of a long-term agreement. The prior agreement covers approximately 600 employees who work on behalf of the Company.

During 2001, AESC successfully negotiated new labor agreements with three bargaining units of the International Brotherhood of Electrical Workers, all related to affiliates of the Company. During 2002, AESC anticipates negotiations with five other bargaining units, all related to affiliates of the Company, whose contracts expire during the year.

REVIEW OF OPERATIONS

Critical Accounting Policies and Estimates

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires the Company to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reporting period. The estimates that require management's most difficult, subjective, and complex judgments involve adverse power purchase commitments.

Adverse Power Purchase Commitments

At December 31, 2001, the Company's adverse power purchase commitment liability was $278.3 million, which related to a contract that extends to the year 2016. As a result of the deregulation plan approved in 1998 for the Company, an adverse power purchase liability was recorded by the Company related to a commitment to buy power 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 could have a material affect on the adverse power purchase commitment.

Earnings Summary
(Millions of Dollars)	2001	2000	1999

Operations:
Regulated operations	$109.8	$102.4	$ 98.0
Unregulated generation			39.6
Consolidated income before extraordinary charges	$109.8	$102.4	137.6
Extraordinary charges, net (Note E to
consolidated financial statements)			(10.0)
Consolidated net income	$109.8	$102.4	$127.6

Earnings for 2001 increased due to higher revenues resulting primarily from the return of choice customers to full service and lower interest expense on long-term debt, partially offset by higher operating expenses.

Earnings for 2000 decreased due to the restructuring plan in Pennsylvania which permitted the Company to transfer its 3,778 MW of generating capacity at book value to Allegheny Energy Supply. As a result of the transfer, the Company no longer has generation available for sale.

M-73

West Penn Power Company
and Subsidiaries

In 1999, earnings from unregulated generation operations reflect the deregulation of two-thirds of the Company's electric generation effective January 1, 1999, as approved by the Pennsylvania PUC's restructuring order. Accordingly, the operating results for these assets, reflecting the sale of generation from these assets as discussed under "Operating Revenues," are classified as unregulated generation in 1999.

The extraordinary charge in 1999 resulted from the redemption of debt related to the securitization of stranded costs as discussed in Note E to the consolidated financial statements.

Operating Revenues

Total operating revenues for 2001, 2000, and 1999 were as follows:

(Millions of Dollars)	2001	2000	1999

Regulated operations revenues:
Regulated	$1,085.8	$ 992.7	$ 915.1
Choice	5.3	28.3	34.3
Bulk power	.3	.4	7.5
Transmission and other energy services	23.1	24.2	20.3
Total regulated operations revenues	1,114.5	1,045.6	977.2
Unregulated generation revenues:
Retail and other			126.6
Bulk power			555.0
Total unregulated generation revenues			681.6
Elimination between regulated and
unregulated generation			(304.6 )
Total operating revenues	$1,114.5	$1,045.6	$1,354.2

Regulated operations regulated revenues include revenues from all the Company's customers eligible to choose an alternate electricity supplier but electing not to do so. Regulated operations choice revenues represent T&D revenues from the Company's franchised customers (customers in the Company's distribution territory) who chose another supplier to provide their electricity needs. In 2001, regulated revenues increased $93.1 million primarily due to the return of choice customers in the commercial and industrial classes to full service (see explanation below). Also contributing to higher regulated revenues was an increase in the average number of customers served in all retail customer classes. Partially offsetting the increase in regulated revenues were decreased industrial sales, primarily to the steel industry. The decrease in choice revenues in 2001 of $23.0 million reflects the return of choice customers to full service.

The return of choice customers to full service had no effect on sales but had the effect of increasing revenues. As a result of the Company's restructuring settlement, beginning in January 1999 two-thirds of the Company's customers were permitted to choose an alternate electricity supplier-that is, customers had the ability to choose another provider for the generation or supply portion of their service while retaining the Company's transmission and distribution services. All of the Company's customers were permitted to make this choice beginning in January 2000. Many of those customers choosing an alternate electricity supplier began returning to the Company as their electricity supplier during 2000, particularly in the third quarter of 2000 and thereafter. Such a return of customers to full service does not impact sales since the Company determines sales on the basis of kilowatt-hours (kWh) delivered to customers (regardless of their electricity supplier). However, such a return of customers to full service results in a significant increase in revenues due to the addition of a supply charge that the Company had not collected while the customers were using an alternate electricity

M-74

West Penn Power Company
and Subsidiaries

supplier. Thus, the return of choice customers results in no impact on kWh sales but a significant increase in revenues. The effect on revenues of customers returning to full service was especially noticeable in the commercial and industrial classes where a higher percentage of sales were associated with choice customers returning to full service. As of December 31, 2001, less than 0.2% of the Company's customers were using alternate electricity suppliers.

The increase in regulated operations regulated revenues for 2000 of $77.6 million also reflects the return of choice customers to full service and an increase in the average number of customers served in all retail customer classes. In addition, regulated revenues increased due to colder weather in the fourth quarter of 2000. This increase was partially offset by the milder summer weather for 2000. The decrease in choice revenues in 2000 of $6.0 million reflects the return of choice customers to full service.

The decrease in regulated operations bulk power revenues (wholesale sales to other utilities) in 2000 of $7.1 million was due to the Company no longer having generation available for sale.

Unregulated generation revenues reflect sales between January 1, 1999, and November 17, 1999, to retail customers outside of the Company's franchised service territory in Pennsylvania's competitive marketplace, to wholesale customers throughout eastern North America, and of bulk power to nonaffiliated companies. Unregulated generation sales ceased on November 18, 1999, as a result of the transfer of the Company's generation assets to Allegheny Energy Supply.

The elimination between regulated operations and unregulated generation revenues in 1999 is necessary to remove the effect of affiliated revenues, primarily sales of power.

See Note B to the consolidated financial statements for information regarding the Competitive Transition Charge.

Operating Expenses

Operation - Fuel Expenses

Fuel expenses for 2001, 2000, and 1999 were as follows:

(Millions of dollars)	2001	2000	1999

Regulated operations	$ -	$.2	$ 72.0
Unregulated generation			141.6
Total fuel expenses	$ -	$.2	$213.6

Total fuel expenses for 2000 decreased due to the November 1999 transfer of the Company's generating capacity to Allegheny Energy Supply.

In 1999, regulated operations and unregulated generation fuel expenses reflect the movement of fuel expenses associated with the two-thirds of the Company's generation transferred from regulated operations to unregulated generation.

Operation - Purchased Power and Exchanges, Net

Purchased power and exchanges, net, represents power purchases from and exchanges with other companies, including affiliated companies, and purchases from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA), and, prior to November 18, 1999, capacity charges paid to Allegheny Generating Company (AGC), and consists of the following items:

M-75

West Penn Power Company
and Subsidiaries

(Millions of dollars)	2001	2000	1999

Regulated operations:
Purchased Power:
From PURPA generation*	$ 43.0	$ 33.2	$ 37.5
Other	569.2	526.7	363.3
Power exchanges, net		1.4	.5
AGC capacity charges			11.6
Total regulated operations	$612.2	$561.3	412.9
Unregulated generation purchased power			298.4
Elimination			(313.1)
Purchased power and exchanges, net	$612.2	$561.3	$ 398.2

*PURPA cost (cents per kWh)	4.7	4.7	4.6

Regulated operations purchased power from PURPA generation increased $9.8 million in 2001 and decreased $4.3 million in 2000 primarily due to increased and decreased purchases, respectively, resulting from a major outage of the AES Beaver Valley facility in 2000.

The increase in regulated operations other purchased power in 2001 of $42.5 million was primarily due to the Company's purchase of additional energy from Allegheny Energy Supply to supply former choice customers who returned to the Company for their electricity supply. The additional energy purchased from Allegheny Energy Supply in 2001 also included $7.5 million of additional costs related to a rate schedule revision (see "Significant Continuing Issues - Quantitative and Qualitative Disclosure About Market Risk" beginning on page M-85). The increase in regulated operations other purchased power in 2000 of $163.4 million was primarily due to the increased purchase of power from Allegheny Energy Supply following the transfer of the Company's generating capacity to Allegheny Energy Supply in November 1999.

In 2000, AGC capacity charges and unregulated generation purchased power decreased due to the transfer of the Company's generation, including its ownership interest in AGC, to Allegheny Energy Supply in November 1999. See Notes D and G to the consolidated financial statements for additional information.

The unregulated generation purchased power in 1999 was due to the Company's purchase of power to provide electricity to new customers in deregulated markets who chose the Company as their alternate supplier of electricity.

The elimination between regulated operations and unregulated generation purchased power in 1999 is necessary to remove the effect of affiliated purchased power expenses.

Operation - Other Expenses

Other operation expenses for 2001, 2000, and 1999 were as follows:

(Millions of dollars)	2001	2000	1999

Regulated operations	$125.6	$122.6	$152.5
Unregulated generation			49.9
Elimination			(13.8)
Total other operations expenses	$125.6	$122.6	$188.6

Total other operation expenses decreased $66.0 million for 2000 primarily due to reduced expenses related to the transfer of generating assets to Allegheny Energy Supply, including the $49.8 million reduction in payments made by the Company to AESC. See Note N to the consolidated financial statements for additional details.

M-76

West Penn Power Company
and Subsidiaries

In 1999, regulated operations and unregulated generation other operation expenses reflect the movement of other operation expenses associated with the two-thirds of the Company's generation transferred from regulated operations to unregulated generation.

The 1999 elimination between regulated operations and unregulated generation other operation expenses is necessary to remove the effect of affiliated transmission purchases.

Maintenance Expenses

Maintenance expenses for 2001, 2000, and 1999 were as follows:

(Millions of dollars)	2001	2000	1999

Regulated operations	$40.0	$37.3	$60.2
Unregulated generation			33.2
Total maintenance expenses	$40.0	$37.3	$93.4

Prior to 2000, maintenance expenses represented costs incurred to maintain the power stations, the T&D system, and general plant and reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. In 2000 and beyond, maintenance expenses support the Company's delivery business only.

Variations in maintenance expenses result primarily from unplanned events and planned projects, which vary in timing and magnitude depending upon the length of time equipment has been in service without a major overhaul and the amount of work found necessary when the equipment is dismantled.

Maintenance expenses increased $2.7 million in 2001 primarily due to higher maintenance costs related to the Company's distribution system. The decrease in total maintenance expenses of $56.1 million for 2000 was primarily due to the transfer of the Company's generation to Allegheny Energy Supply in November 1999. The decrease in regulated operations maintenance expenses of $22.9 million for 2000 was primarily due to the transfer of the final one-third of Company's generation to Allegheny Energy Supply.

Depreciation and Amortization Expense

Depreciation and amortization expense for 2001, 2000, and 1999 were as follows:

(Millions of dollars)	2001	2000	1999

Regulated operations	$69.3	$62.4	$ 68.7
Unregulated generation			45.6
Total depreciation and amortization
expense	$69.3	$62.4	$114.3

Total depreciation and amortization expense increased $6.9 million in 2001 primarily due to higher property, plant, and equipment balances, including computer software which is amortized over comparatively short lives.

Total depreciation and amortization expenses for 2000 decreased $51.9 million due to the transfer of generating assets to Allegheny Energy Supply in November 1999.

M-77

West Penn Power Company
and Subsidiaries
|

Taxes Other Than Income Taxes

Taxes other than income taxes for 2001, 2000, and 1999 were as follows:

(Millions of dollars)	2001	2000	1999

Regulated operations	$55.3	$45.4	$58.9
Unregulated generation			21.8
Total taxes other than income taxes	$55.3	$45.4	$80.7

Total taxes other than income taxes increased $9.9 million in 2001 primarily due to increased gross receipts taxes resulting from higher revenues and Pennsylvania Capital Stock tax adjustments.

Total taxes other than income taxes decreased $35.3 million in 2000 due to the transfer of generating assets to Allegheny Energy Supply in November 1999, reduced capital stock taxes due to reduced tax rates, and Pennsylvania Capital Stock tax adjustments.

Federal and State Income Taxes

The decrease in federal and state income taxes for 2000 was due to a decrease in taxable income. Note F to the consolidated financial statements provides a further analysis of income tax expense.

Other Income and Deductions

The decrease in other income, net, of $2.7 million in 2001 was primarily due to decreased interest income in 2001 and litigation settlement proceeds received in 2000.

The decrease in other income, net, of $5.4 million in 2000 was primarily due to a decrease in the Company's portion of AGC's earnings due to the transfer of the Company's 45% ownership share in the common stock of AGC to Allegheny Energy Supply in November 1999, offset in part by interest income earned on intercompany money pool loans.

Interest Charges

Interest on long-term debt and other interest for 2001, 2000, and 1999 were as follows:

(Millions of dollars)	2001	2000	1999

Interest on long-term debt:
Regulated operations	$49.0	$64.0	$42.9
Unregulated generation			18.8
Total interest on long-term debt	$49.0	$64.0	61.7
Other interest:
Regulated operations	$2.6	$2.9	3.4
Unregulated generation			3.6
Total other interest	$2.6	$2.9	7.0
Total interest expense	$51.6	$66.9	$68.7

Interest on long-term debt decreased $15.0 million in 2001 due primarily to the Company's release from co-obligor status with Allegheny Energy Supply in December 2000 on $231 million of pollution control notes (see explanation below). The repayment of transition bonds also contributed to the decrease in interest on long-term debt.

In November 1999, Allegheny Energy Supply assumed the service obligation for $231 million of pollution control debt in conjunction with the transfer of the Company's

M-78

West Penn Power Company
and Subsidiaries

generating assets to Allegheny Energy Supply. Through December 22, 2000, the Company was co-obligor on the pollution control debt and reflected the debt in its financial statements. The Company accrued interest expense on the pollution control debt and then reduced interest accrued and increased other paid-in capital when Allegheny Energy Supply paid interest.

On December 22, 2000, the trustees of the pollution control notes released the Company from its co-obligor status as a result of Allegheny Energy Supply acquiring surety bonds, which would repay these notes in the event Allegheny Energy Supply defaults. In accordance with FASB's SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," the Company derecognized the pollution control notes with the effect of increasing equity by $231.9 million. See Note D to the consolidated financial statements for additional information.

Other interest expense reflects changes in the levels of short-term debt maintained by the Company throughout the year, as well as the associated interest rates.

For additional information regarding the Company's short-term and long-term debt, see the consolidated statement of capitalization and Notes H and L to the consolidated financial statements.

Allowance for borrowed funds used during construction and interest capitalized decreased $2.3 million in 2000 due primarily to the transfer of generation and generation related construction activity to Allegheny Energy Supply.

Extraordinary Item

The extraordinary charge in 1999 of $17.0 million ($10 million after taxes) was required to reflect the difference between the reacquisition price and the net carrying amount of first mortgage bonds repurchased with proceeds from the sale of transition bonds as a result of the deregulation process in Pennsylvania. See Note E to the consolidated financial statements for additional information.

FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

Liquidity and Capital Requirements

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

M-79

West Penn Power Company
and Subsidiaries

their commercial paper programs. At December 31, 2001, $14.4 million of the lines of credit were drawn by an affiliate of the Company. Of the remaining $385.6 million lines of credit, all was supporting commercial paper of Allegheny Energy and thus was unavailable to the Company. In addition to bank lines of credit, an Allegheny Energy internal money pool accommodates intercompany short-term borrowing needs, to the extent that Allegheny Energy and its regulated subsidiaries have funds available. The Company has SEC authorization for total short-term borrowings, from all sources, of $500 million. The Company had no short-term debt outstanding at December 31, 2001. See Note H to the consolidated financial statements for additional information.

	Payments Due by Period
	(Thousands of Dollars)
Contractual Cash Obligations	Less Than			After
and Commitments	1 Year	2-3 Years	4-5 Years	5 Years	Total

Long term debt*	$103,845	$233,710	$148,822	$194,156	$ 680,533
Capital lease obligations	4,554	6,904	4,654	4,658	20,770
Operating lease obligations	2,077	805	1		2,883
PURPA purchased power	55,119	106,169	104,555	664,971	930,814
Total	$165,595	$347,588	$258,032	$863,785	$1,635,000
*Long-term debt does not include unamortized debt expense, discounts, and premiums.

The Company's capital expenditures, including construction expenditures, for 2002 and 2003, are estimated at $54.1 million and $40.9 million, respectively.

Cash Flow

Internally generated funds, consisting of cash flows from operations reduced by common dividends, was $94.7 million in 2001, compared with $46.8 million in 2000.

Cash flows from operations increased $156.5 million in 2001 reflecting higher net income, decreased accounts receivable, net, and increased accounts payable to affiliates. Cash flows used in investing increased $17.6 million in 2001 as a result of higher construction expenditures. Cash flows used in financing activities increased $125.6 million in 2001 primarily due to the payment of common dividends of $108.7 million to Allegheny Energy in 2001. The Company made no dividend payments to Allegheny Energy in 2000 in order to increase the Company's equity as a percent of total capitalization. In 2001, internally generated funds were sufficient to cover all construction expenditures and net repayments of debt.

Cash flows from operations decreased $226.6 million in 2000 primarily due to a $87 million decrease in net income before depreciation and amortization and extraordinary charges as well as increased accounts receivable, net and decreased accounts payable, including accounts payable to affiliates. Cash flows used in investing decreased $61.2 million in 2000 as a result of lower construction expenditures reflecting, in part, the transfer of generating assets in November 1999. Cash flows used in financing activities decreased $137.4 million in 2000 primarily due to common dividend payments not being made to Allegheny Energy and a decrease in notes receivable from affiliates. In 2000, internally generated funds financed most of the Company's construction expenditures.

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West Penn Power Company
and Subsidiaries

Financing

Long-term Debt

The Company issued no long-term debt, preferred stock, or common stock in 2001 and 2000. In 2001 the Company redeemed $27.2 million of class A-1 6.32-percent transition bonds and $33.0 million of class A-2 6.63-percent transition bonds. In 2000 the Company redeemed $46.8 million of class A-1 6.32-percent transition bonds.

In 1999, the Company took the following steps in its recapitalization process concurrent with its restructuring plan resulting from the implementation of deregulation of electric generation in Pennsylvania.
- Issued $600 million of transition bonds with varying average lives ranging from one to eight years with a weighted average cost of 6.887 percent to "securitize" transition costs related to its restructuring plan described in Note B to the consolidated financial statements.

- Called or redeemed all outstanding shares of its cumulative preferred stock with a combined par value of $79.7 million plus redemption premiums of $3.3 million on July 15, 1999, with proceeds from new $84 million five-year unsecured medium-term notes issued in the second quarter at a 6.375 percent coupon rate. The redemption of the preferred stock allowed the Company to revise its Articles of Incorporation, providing greater financial flexibility in restructuring debt.
- Reacquired all of its outstanding $525 million of first mortgage bonds.

The transition bonds are supported by an Intangible Transition Charge (ITC) that replaces a portion of the Competitive Transition Charge 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.

In November 1999, Allegheny Energy Supply assumed the service obligation for $231 million of pollution control debt in conjunction with the transfer of the Company's generating assets to Allegheny Energy Supply. During 2000, the Company was co-obligor on the notes and reflected the notes as debt in its financial statements. The Company accrued interest expense on the pollution control notes and then reduced interest accrued and increased other paid-in capital when Allegheny Energy Supply made interest payments.

On December 22, 2000, the trustees of the pollution control notes released the Company from its co-obligor status as a result of Allegheny Energy Supply acquiring surety bonds, which would repay these notes in the event Allegheny Energy Supply defaults. In accordance with SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," the Company derecognized the pollution control notes with the effect of increasing equity by $231.9 million. See Note D to the consolidated financial statements for additional information.

The Company's long-term debt due within one year at December 31, 2001, was $70.3 million of transition bonds and $33.6 million of medium-term debt.

Short-term Debt

The Company had no short-term debt outstanding at December 31, 2001, and 2000.

SIGNIFICANT CONTINUING ISSUES

Electric Energy Competition

The electricity supply segment of the energy industry in the United States is becoming increasingly competitive. The national Energy Policy Act of 1992

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West Penn Power Company
and Subsidiaries

deregulated the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. The Company and its parent, Allegheny Energy, continue to be an advocate of federal legislation to remove artificial barriers to competition in electricity markets, avoid regional dislocations, and ensure a level playing field.

In addition to the wholesale electricity market becoming more competitive, certain states have taken active steps toward allowing retail customers the right to choose their electricity supplier.

Allegheny Energy is at the forefront of state-implemented retail competition, having negotiated settlement agreements in all of the states that Monongahela Power, Potomac Edison, and the Company serve. Pennsylvania, Maryland, Virginia, and Ohio have retail choice programs in place. West Virginia's Legislature has approved a deregulation plan pending additional legislation regarding tax revenues for state and local governments and allowing implementation. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

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West Penn Power Company
and Subsidiaries

provisions in this legislation, including the repeal or significant revision of PUHCA, as well as for critical infra-structure protection legislation. Prior to the attack, two primary bills had been introduced in the U.S. Senate: S. 388, by former Energy and Natural Resources Committee Chairman Senator Frank Murkowski of Alaska, and S. 597, by the committee's new chairman, Senator Jeff Bingaman of New Mexico. Provisions from these bills could be included in the new energy legislation. The primary House committee of jurisdiction, Energy and Commerce, initially passed the President's national energy security proposal and is only now considering accompanying electricity restructuring legislation. Among issues that are being addressed in this legislation are the repeal or significant revision of PUHCA and Section 210 (Mandatory Purchase Provisions) of PURPA. Allegheny Energy continues to advocate the repeal of PUHCA and Section 210 of PURPA on the grounds that they are obsolete and anticompetitive and that PURPA results in utility customers paying above-market prices for power. Separately, the Senate Banking Committee in April 2001 approved S. 206, legislation to repeal PUHCA.

Pennsylvania Activities

As of January 2, 2000, all electricity customers in Pennsylvania have the right to choose their electric generation supplier. The number of customers who have switched to another supplier and the amount of electrical load transferred in Pennsylvania exceed that of any other state. However, the Company had retained more than 99.8 percent of its Pennsylvania customers as of December 31, 2001.

As part of the Company's restructuring settlement in Pennsylvania, the Company retains the obligation to serve all customers who choose not to select an alternative supplier (provider of last resort) at rates that are capped at 1997 levels. The generation rates are capped through 2008.

The status of electric energy competition in Maryland, Ohio, Virginia, and West Virginia in which affiliates of the Company serve are as follows:

Maryland Activities

On June 7, 2000, the Maryland Public Service Commission (Maryland PSC) approved the transfer of the generating assets of Potomac Edison to Allegheny Energy Supply. The transfer was completed in August 2000. Maryland customers of Potomac Edison have had the right to choose an alternate electric supplier since July 1, 2000. While few customers have switched suppliers in Potomac Edison's service territory, some retail competition is occurring in other portions of the state.

On July 1, 2000, the Maryland PSC issued a restrictive order imposing standards of conduct for transactions between Maryland utilities and their affiliates. Among other things, the order:
- restricts sharing of employees between utilities and unregulated affiliates;
- announces the Maryland PSC's intent to impose 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 unqualified benefits; and
- requires asymmetric pricing for asset transfers between utilities and their affiliates. Asymmetric pricing requires that transfers of assets from the regulated utility to an affiliate be recorded at the greater of book cost or market value, while transfers of assets from the affiliate to the regulated utility be recorded at the lesser of book cost or market value.

Potomac Edison, along with substantially all of Maryland's natural gas and electric utilities, filed a Circuit Court petition for judicial review and a motion for a stay of the order. On April 25, 2001, the Circuit Court issued its decision affirming much of the Maryland PSC's order, but remanding portions of the order to the Maryland PSC, including the requirement for asymmetric pricing for asset transfers between utilities and their affiliates.

M-83

West Penn Power Company
and Subsidiaries

Ohio Activities

The Ohio General Assembly passed legislation in 1999 to restructure its electric utility industry. As of January 1, 2001, all of the state's electricity consumers were able to choose their electricity supplier, beginning a five-year transition to market rates. Residential customers are guaranteed a five percent reduction in the generation portion of their rate.

Virginia Activities

The Virginia Electric Utility Restructuring Act (Restructuring Act) became law on March 25, 1999. All state utilities were required to submit a restructuring plan by January 1, 2001, to be effective on January 1, 2002. On December 21, 2001, the Virginia State Corporation Commission (Virginia SCC) approved Potomac Edison's Phase II of the Functional Separation Plan. In August 2000, Potomac Edison transferred its Virginia jurisdictional generating assets, excluding the hydroelectric assets located within the state of Virginia, to Allegheny Energy Supply at book value. Customer choice was implemented for all customers in Potomac Edison's service territory beginning on January 1, 2002.

M-84

West Penn Power Company
and Subsidiaries

Various rulemaking proceedings to implement customer choice are ongoing before the Virginia SCC, including an application by Potomac Edison to participate in a regional transmission entity (PJM West).

West Virginia Activities
Electric restructuring in West Virginia remains unresolved and awaits further legislative action. In January 2000, the Public Service Commission of West Virginia (West Virginia PSC) submitted a restructuring plan to the Legislature for approval that would open full retail competition on January 1, 2001. On March 11, 2000, the West Virginia Legislature approved the West Virginia PSC's plan, but assigned the tax issues surrounding the plan to a legislative subcommittee for further study. The start date of competition is contingent upon the necessary tax changes being made and implementation being approved by the Legislature. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

As approved by the West Virginia PSC, Potomac Edison transferred its generating assets to Allegheny Energy Supply in August 2000. In accordance with the same restructuring agreement, Potomac Edison and Monongahela Power implemented a commercial and industrial rate reduction program on July 1, 2000.

Derivative Instruments and Hedging Activities

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 was subsequently 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." Effective January 1, 2001, the Company implemented the requirements of these accounting standards.

Quantitative and Qualitative Disclosure About Market Risk

The Company is exposed to market risks associated with commodity prices and interest rates. The commodity price risk exposure results from market fluctuations in the price of electricity as discussed below. The interest rate risk exposure results from changes in interest rates related to variable- and fixed-rate debt. The Company is mandated by Allegheny Energy's Board of Directors to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

M-85

West Penn Power Company
and Subsidiaries

As a result of the Company's restructuring plan, the Company unbundled its rates to reflect three separate charges-a generation (or supply) charge, a Competitive Transition Charge (CTC), and T&D charges. The generation rates applied to customers not choosing an alternate electricity supplier are capped through a transition period that ends December 31, 2008.

Pursuant to agreements, Allegheny Energy Supply provides the Company with the total amount of electricity needed for those customers not choosing an alternate electricity supplier during the transition period. The original rate schedule for these agreements, effective through December 31, 2000, established fixed purchase prices corresponding to the capped generation rates charged to customers not electing an alternate electricity supplier. Thus, the cost of purchased electricity was recovered through the capped generation rates charged to customers.

Under a revised rate schedule approved by the FERC effective January 1, 2001, a portion of the electricity purchased from Allegheny Energy Supply now has a market-based pricing component that could result in higher electricity prices when market prices exceed the fixed prices (corresponding to the capped generation rates). Purchased electricity prices would never be set below the established fixed prices. The amount of electricity purchased under this rate schedule that is subject to market prices escalates each year through 2008 (from 2% of total purchases in 2001 to approximately 51% in 2008). To the extent that the Company purchases electricity from Allegheny Energy Supply at market prices that exceed the established fixed prices, the Company's results of operations could be adversely affected. In 2001, the Company incurred $7.5 million of additional purchased electricity costs due to the market-based pricing component of the revised rate schedule.

New Accounting Standards

SFAS No. 142 changed the accounting for goodwill from an amortization method to an impairment-only approach. For entities with calendar year ends, amortization of goodwill, including goodwill recorded in past business combinations, ceased upon adoption of the standard on January 1, 2002. An entity's goodwill will now be tested at least annually for impairment. Intangible assets other than goodwill will continue to be amortized over their useful lives and reviewed for impairment. As of December 31, 2001, the Company had no goodwill but had intangible assets consisting primarily of software.

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West Penn Power Company
and Subsidiaries

depreciated over the useful life of the asset. Upon settlement of the liability, an entity either will settle the obligation for its recorded amount or incur a gain or loss upon settlement. The Company will be evaluating the effect of adopting SFAS No. 143 on its results of operations and financial position prior to its adoption of the standard.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This standard, which the Company adopted on January 1, 2002, establishes one accounting model for long-lived assets to be disposed of by sale, including discontinued operations, and carries forward the general impairment provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS No. 144 is not expected to have a material effect on the Company.

M-87

Allegheny Generating Company

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FACTORS THAT MAY AFFECT FUTURE RESULTS

Certain statements within constitute forward-looking statements with respect to Allegheny Generating Company (the Company). Such forward-looking statements include statements with respect to deregulated activities and movements towards competition in the states served by the Company, markets, products, services, prices, results of operations, capital expenditures, regulatory matters, liquidity and capital resources, resolution and impact of litigation, and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results of the Company will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

Factors that could cause actual results of the Company to differ materially include, among others, the following: general and economic and business conditions; including the continuing impact on the economy and deregulation activity caused by the September 11, 2001, terrorist attacks; industry capacity; changes in technology; changes in political, social and economic conditions; changes in the price of power and fuel for electric generation; environmental regulations; litigation involving the Company; regulatory conditions applicable to the Company; the loss of any significant customers; and changes in business strategy or development plans.

SIGNIFICANT EVENTS IN 2001, 2000 AND 1999

Initial Public Offering of Allegheny Energy Supply

On July 23, 2001, Allegheny Energy, Inc. (Allegheny Energy) filed a U-1 application with the Securities and Exchange Commission (SEC) seeking authorization under the Public Utility Holding Company Act of 1935 (PUHCA) to effect an initial public offering (IPO) of up to 18 percent of the common stock in a new holding company, which would own 100 percent of Allegheny Energy Supply Company, LLC (Allegheny Energy Supply), one of the Company's parents. The common stock of this Maryland holding company owned by Allegheny Energy and not sold in the IPO would then be distributed to Allegheny Energy's shareholders on a tax-free basis. In October 2001, Allegheny Energy announced that the proposed IPO would be delayed due to market and other conditions. In January 2002, Allegheny Energy announced that it would not proceed with the IPO. In February 2002, Allegheny Energy filed an amendment to the U-1 application filed on July 23, 2001, with the SEC, withdrawing the IPO application.

Transfer of Generating Assets

On June 1, 2001, Monongahela Power Company (Monongahela Power) transferred its 352 megawatts (MW) of Ohio and the Federal Energy Regulatory Commission (FERC) jurisdictional generating assets to Allegheny Energy Supply, at book value. The transfer was approved by the Public Utilities Commission of Ohio (Ohio PUC) as part of a settlement that implemented a restructuring plan for Monongahela Power. This restructuring plan allowed Monongahela Power's Ohio customers to choose their generation supplier effective January 1, 2001. Accordingly, Monongahela Power's interest in the common stock of the Company decreased to 22.97% from 27% effective June 1, 2001. Allegheny Energy Supply owns the remaining shares.

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Allegheny Generating Company

In March 2000, the West Virginia Legislature passed House Resolution 27 approving an electric deregulation plan submitted by the Public Service Commission of West Virginia (West Virginia PSC) with certain modifications. Under the resolution, the implementation of the West Virginia deregulation plan cannot occur until the Legislature enacts certain tax changes regarding the preservation of tax revenues for state and local governments and other changes conforming to the plan and authorizing implementation. The plan provides for all customers to have choice of a generation supplier and allows Monongahela Power to transfer, at book value, the West Virginia portion of its generating assets, including its 22.97% ownership share of common stock of Monongahela Power to Allegheny Energy Supply. No final legislative action was taken in 2001 regarding implementation of the deregulation plan. Although the West Virginia Legislature may reconsider the deregulation plan in the January to March 2002 session, the current climate regarding restructuring makes it unlikely that the existing plan will be advanced in 2002.

On June 23, 2000, the West Virginia PSC issued an order regarding the transfer of the generating assets of Monongahela Power. The June 23, 2000, order permits Monongahela Power to submit a petition to the West Virginia PSC seeking approval to transfer its West Virginia generating assets prior to the implementation of the deregulation plan. A filing before implementation of the deregulation plan is required to include commitments to the consumer and other protections contained in the deregulation plan. On August 15, 2000, with a supplemental filing on October 31, 2000, Monongahela Power filed a petition seeking West Virginia PSC approval to transfer its West Virginia jurisdictional generating assets to Allegheny Energy Supply. Settlement discussions regarding the generating asset transfer are ongoing.

On July 31, 2000, Allegheny Energy received approval from the SEC regarding the transfer of the generating assets of The Potomac Edison Company (Potomac Edison) to Allegheny Energy Supply. State utility commissions in Maryland, Virginia, and West Virginia approved the transfer of these assets as part of deregulation proceedings in those states. The FERC also approved the transfer. In August 2000, Allegheny Energy transferred approximately 2,100 megawatts MW of its subsidiary Potomac Edison's Maryland, Virginia, and West Virginia jurisdictional generating assets to Allegheny Energy Supply at book value, including Potomac Edison's 28% ownership share in the common stock of the Company.

On November 19, 1998, the Pennsylvania Public Utility Commission (Pennsylvania PUC) approved a settlement agreement between West Penn Power Company (West Penn) and parties to West Penn's restructuring proceedings related to legislation in Pennsylvania to provide customer choice of electric suppliers and deregulate electricity generation. The terms of the settlement agreement permitted West Penn to transfer its generating assets to a separate legal entity at book value, contingent upon other regulatory approvals. On November 18, 1999, West Penn transferred its deregulated generating capacity, which included its 45% ownership share in the common stock of the Company, to Allegheny Energy Supply. During the period from November 18, 1999, through January 1, 2000, Allegheny Energy Supply leased back to West Penn one-third of its generating assets, including one-third of its 45% ownership share in the Company, providing West Penn with the unlimited right to use those facilities to serve its regulated load.

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Allegheny Generating Company

REVIEW OF OPERATIONS

Critical Accounting Policies and Estimates

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires the Company to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosure of contingencies during the reported period. The estimates require management's most difficult, subjective, and complex judgments.

The Company's only operating assets are an undivided 40% interest in the Bath County (Virginia) pumped-storage hydroelectric station and its connecting transmission facilities. The Company has no plans for construction of any other major facilities.

Pursuant to an agreement, Monongahela Power and Allegheny Energy Supply (the Parents), buy all of the Company's capacity in the station priced under a "cost-of-service formula" wholesale rate schedule approved by the FERC. Under this arrangement, the Company recovers in revenues all of its operation and maintenance expenses, depreciation, taxes, and a return on its investment. On December 29, 1998, the FERC issued an Order accepting a proposed amendment to the Parents' Power Supply Agreement for the Company effective January 1, 1999. This amendment sets the generation demand for each Parent proportional to its ownership in the Company. Previously, demand for each Parent fluctuated due to customer usage.

The Company's rates are set by a formula filed with and previously accepted by the FERC. The only component that changes is the return on equity (ROE). Pursuant to a settlement agreement filed with and approved by the FERC, the Company's ROE is set at 11% for the purpose of calculating billing to affiliates and will continue at that rate unless any affected party seeks a change.

Revenues are expected to decrease each year due to a normal continuing reduction in the Company's net investment in the Bath County station and its connecting transmission facilities upon which the return on investment is determined.

The net investment (primarily net plant less deferred income taxes) decreases to the extent that provisions for depreciation and deferred income taxes exceed net plant additions. Operating revenues for the year ended December 31, 2001, decreased primarily due to a reduction in net investment.

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Allegheny Generating Company

The increase in operating expense in 2001 was the net result of increases in federal income taxes and depreciation expense. The increase was only slightly offset by decreases in operation and maintenance expense, and taxes other than income tax. The 2000 decrease in operating expense was due to the decrease in federal income taxes directly related to the reduction in operating income before taxes.

The decrease in operation and maintenance expense in 2001 resulted from decreased licensing fees.

The increase in income taxes in 2001 resulted from an increase in income before income taxes and the change in deferred income taxes related to accelerated depreciation. See Note B to the financial statements for information regarding income tax provisions.

The decrease in other income, net, from 2000 to 2001 resulted from the recording of interest income related to an income tax settlement recorded in 2000.

The interest on long-term debt remained relatively flat in 2001 since no new debt was issued.

The decrease in other interest expense for 2001 resulted from a decrease in the applicable interest rate for outstanding short-term obligations. Short-term debt from money pool borrowings increased from $53.3 million to $62.9 million at December 31, 2001, with interest rates decreasing from 6.45% at December 31, 2000, to 1.54% at December 31, 2001. The average outstanding money pool borrowing in 2001 was $38.9 million with an average interest rate of 3.76%, compared to 2000 average outstanding borrowings of $49.8 million at an average interest rate of 6.17%. See Note H to financial statements for more information regarding short-term obligations.

LIQUIDITY AND CAPITAL REQUIREMENTS

As previously reported, the Company received authority from the SEC to pay common dividends from time to time through December 31, 2001, out of capital to the extent permitted under applicable corporation law and any applicable financing agreements which restrict distributions to shareholders. Due to the nature of being a single asset company with declining capital needs, the Company systematically reduces capitalization each year as its asset depreciates. This has resulted in the payment of dividends in excess of current earnings out of other paid-in capital and the reduction of retained earnings to zero.

To meet cash needs for operating expenses, the payment of interest, retirement of debt, and for its construction program, the Company has used internally generated funds, external financings, and debt instruments. The timing and amount of external financings depend primarily upon economic and financial market conditions, the Company's cash needs, and capital stru

The following table indicates the volume of natural gas purchased and percentage of total volume of natural gas purchased, with respect to Mountaineer's largest suppliers for the twelve months ended December 31, 2001:
	Twelve Months Ended December 31, 2001
	Volume (Mmcf)	% of Total
MGS-Owned/Controlled Production	1,610	5.38%
Coral Energy Resources, L.P.	24,470	81.72%
Other Gulf Coast Producing Region Producers/Suppliers	3,228	10.77%
Other Appalachian Basin Producers/Suppliers	637	2.13%

	Twelve Months Ended 12/31/2001		Twelve Months Ended 12/31/2000
	Volume (Mmcf)	% of Total	Volume (Mmcf)	% of Total
WV Production Contracts	1,509	49.41%	1,635	50.42%
Cabot Oil and Gas Marketing	685	22.43%	1,225	37.77%
Other Supply Volumes	860	28.16%	383	11.81%
Annual Totals	3,054	100.00%	3,243	100.00%

The names of the executive officers of each company, their ages as of December 31, 2001, the positions they hold, or held during 2001, and their business experience during the past five years appears below:

Executive Officers of the Registrants Position (a) and Period of Service

The names of the executive officers of each company, their ages as of December 31, 2001, the positions they hold, or held during 2001, and their business experience during the past five years appears below:

Executive Officers of the Registrants (cont'd.) Position (a) and Period of Service

(a)	All officers and directors are elected annually, except the Board of AE, which is a staggered Board.
(b)	Prior to his appointment as Vice President of AE, Mr. Barbas was President, GE Capital Rental Services (3/97-2/99) and President, GE Capital Computer Rental Services (10/93-3/97).
(c)	Prior to his appointment as Vice President of AGC, Mr. Benson was Vice President, AESC (7/98); Vice President & Assistant Treasurer AESC (5/96-7/98); and Vice President AESC (6/95-5/96).
(d)	Prior to his appointment as Vice President and Treasurer of AE and Treasurer of Monongahela, Potomac Edison, West Penn and AGC, Mr. Binder was Executive Director, Regulation and Rates for AESC (1997-1998); General Manager, Industrial Marketing for AESC (1996-1997); and Director, Rates for AESC (1995-1996).
(e)	Prior to her appointment as Assistant Secretary, Ms. Brooks was Senior Attorney for AESC (2/99 - 4/00); and Attorney for AESC and Potomac Edison (7/81 - 2/99).
(f)	Prior to his appointment as Vice President of AGC, Mr. Garlick was Regional Manager of Potomac Edison, R. Paul Smith/Hydro Region (11/95 - 6/98); Regional Manager of West Penn, Armstrong/Springdale Region (6/98 - 10/98); and Director, Human Resources AE Supply (10/98 - 12/00).
(g)	Prior to his appointment as Vice President Customer Operations, Mr. Haney was Executive Director, Operating Business Unit (8/98-10/98); Director, Operations Services (5/96-8/98); Director, Transmission Projects (12/95-5/96); Manager, Construction (2/95-12/95).
(h)	Prior to his appointment as Vice President of Monongahela, Potomac Edison and West Penn, for AESC, Mr. Magnuson was Executive Director, Customer Affairs (4/99-7/99); Executive Director, Human Resources (10/98-4/99); and Director Human Resources (1/95-10/98).
(i)	Prior to his appointment as Senior Vice President of AE and Vice President of Monongahela, Potomac Edison, West Penn and AGC, Mr. Morrell was Vice.President. - Regulatory and Public Affairs, Jersey Central Power & Light Company (JCPP&L) (8/94-4/96).
(j)	Prior to his appointment as Vice President of Monongahela, Potomac Edison and West Penn, Mr. Pfirrmann was Vice President AESC (9/95-5/96); Vice President Monongahela, Potomac Edison and West Penn (5/96-8/98); and Vice President AESC (8/98-5/00).
(k)	Prior to her appointment as Vice President of AE, Ms.Schaff was a Vice President of AESC (1/96-1/97) and a Federal Affairs Representative with The Union Electric Company (4/88-12/95). Ms. Schaff died on March 8, 2002.
(l)	Mr. Skrgic resigned as an officer effective February 1, 2001.
(m)	Prior to his appointment as Senior Vice President and Chief Financial Officer of AE, Director and Vice President of Monongahela, Potomac Edison and West Penn, and Vice President of AGC, Mr. Walenczyk was Managing Director, Investment Banking Division, PaineWebber, Inc. (1996-1998); Vice President-Finance, PSEG Energy Holdings, Inc. (3/98-4/01).

	2001			2000
	Dividend	High	Low	Dividend	High	Low
1^st Quarter	43 cents	$49.00	$39.50	43 cents	$29.5625	$23.625
2^nd Quarter	43 cents	$55.90	$44.70	43 cents	$31.75	$26.6875
3^rd Quarter	43 cents	$49.25	$35.20	43 cents	$39.875	$27.75
4^th Quarter	43 cents	$40.01	$32.99	43 cents	$48.75	$36.6875

ALLEGHENY ENERGY, INC.			D-1
Condensed Financial Statements
Year ended December 31, 2001	Monongahela Power Company and Subsidiaries	The Potomac Edison Company and Subsidiaries		West Penn Power Company and Subsidiaries	Allegheny Ventures, Inc. and Subsidiaries	Allegheny Energy Supply Company, LLC and Subsidiaries



(Thousands of dollars)
Balance Sheets
Assets
Property, plant, and equipment*	$2,490,741	$1,447,027		$1,713,390	$ 43,800	$5,351,590
Accumulated depreciation	(1,139,904)	(538,301)		(585,417)	(2,624)	(1,958,613)
	1,350,837	908,726		1,127,973	41,176	3,392,977
Excess of cost over net assets acquired	195,033				26,218	367,287
Cash and temporary cash investments	4,439	1,608		6,257	4,364	20,909
Other current assets	318,825	130,356		201,123	102,953	681,243
Regulatory assets	100,750	54,081		429,502		9,849
Other	55,463	17,017		12,231	104,201	1,503,877
Total	$2,025,347	$1,111,788		$1,777,086	$278,912	$5,976,142
*Includes construction work in progress

Capitalization and liabilities
Common stock, other paid-in capital,
retained earnings, and accumulated other
comprehensive income	$ 629,594	$ 383,257		$ 423,313	$104,523	$1,524,686
Preferred stock	74,000
Long-term debt and QUIDS	784,261	415,797		574,647	10,500	1,130,041
Minority interest						30,476
Short-term debt	14,350	57,597			700	1,073,745
Other current liabilities	180,736	98,021		222,817	141,930	1,216,565
Unamortized investment credit	9,034	9,570		19,951		64,035
Deferred income taxes	238,751	109,748		243,456		412,707
Regulatory liabilities	49,509	20,377		15,255		22,914
Adverse power purchase commitments				253,499
Other	45,112	17,421		24,148	21,259	500,973
Total	$2,025,347	$1,111,788		$1,777,086	$278,912	$5,976,142

Statements of operations
Operating revenues	$ 937,723	$ 864,534		$1,114,504	$139,644	$8,611,555
Operating expenses	803,973	779,000		955,720	138,996	8,273,639
Operating income	133,750	85,534		158,784	648	337,916
Other income and deductions	8,224	(2,371)		2,034	(410)	5,453
Income before interest charges, preferred
dividends, minority interest, and
cumulative effect of accounting change	141,974	83,163		160,818	238	343,369
Interest charges and preferred dividends	52,517	35,128		50,973	440	103,485
Balance for common stock before minority
interest and cumulative effect of
accounting change	89,457	48,035		109,845	(202)	239,884
Minority interest						(5,049)
Cumulative effect of accounting change						(31,147)
Balance for common stock	$ 89,457	$ 48,035		$ 109,845	$ (202)	$ 203,688

ALLEGHENY ENERGY, INC.							D-2
Consolidated Statistics

Year ended December 31	2001	2000	1999	1998	1997	1996	1991
Summary of operations (Millions of dollars)
Operating revenues	$10,378.9	$4,011.9	$2,808.4	$2,576.4	$2,369.5	$2,327.6	$1,948.6
Operation expense	8,613.1	2,602.4	1,498.1	1,286.0	1,065.9	1,013.0	918.6
Maintenance	287.9	230.3	223.5	217.5	230.6	243.3	204.2
Restructuring charges and asset write-offs						103.9
Depreciation	301.5	247.9	257.5	270.4	265.7	263.2	189.7
Taxes other than income	216.3	210.2	190.3	194.6	187.0	185.4	167.5
Taxes on income	245.1	184.8	164.4	168.4	168.1	128.0	119.1
Allowance for funds used during construction	(11.5)	(7.2)	(6.9)	(5.0)	(8.3)	(5.9)	(7.9)
Other income and deductions	(13.0)	(4.5)	(1.6)	(8.2)	(18.0)	(4.4)	(1.6)
Interest charges, preferred dividends, and preferred
redemption premiums	288.3	234.4	197.7	189.7	197.2	191.1	165.0
Minority interest	2.3
Consolidated income before extraordinary charge
and cumulative effect of accounting change	448.9	313.6	285.4	263.0	281.3	210.0	194.0
Extraordinary charge, net (a)		(77.0)	(27.0)	(275.4)
Cumulative effect of accounting change, net (b)	(31.1)
Consolidated net income (loss)	$ 417.8	$236.6	$258.4	$(12.4)	$281.3	$210.0	$ 194.0
Common stock data (c)
Shares issued (thousands)	125,276	122,436	122,436	122,436	122,436	121,840	108,452
Treasury shares (thousands)		(12,000)	(12,000)
Shares outstanding (thousands)	125,276	110,436	110,436	122,436	122,436	121,840	108,452
Average shares outstanding (thousands)	120,104	110,436	116,237	122,436	122,208	121,141	107,548
Earnings per average share: (d)
Consolidated income before extraordinary charge
and cumulative effect of accounting change	$ 3.74	$ 2.84	$ 2.45	$ 2.15	$ 2.30	$ 1.73	$ 1.80
Extraordinary charge, net (a)		(.70)	(.23)	(2.25)
Cumulative effect of accounting change, net (b)	(.26)
Consolidated net income (loss)	$ 3.48	$ 2.14	$ 2.22	$ (.10)	$ 2.30	$ 1.73	$ 1.80
Dividends paid per share	$ 1.72	$ 1.72	$ 1.72	$ 1.72	$ 1.72	$ 1.69	$ 1.58
Dividend payout ratio (e)	46.5%	60.6%	64.6%	73.5%	74.7%	97.5%	87.8%
Shareholders	37,644	40,589	44,873	48,869	53,389	58,677	62,095
Market price per share:
High	$ 55.900	$ 48.750	$ 35.188	$ 34.938	$ 32.594	$ 31.125	$ 23.250
Low	$ 32.990	$ 23.625	$ 26.188	$ 26.625	$ 25.500	$ 28.000	$ 17.440
Close	$ 36.220	$ 48.188	$ 26.938	$ 34.500	$ 32.500	$ 30.375	$ 22.250
Book value per share	$ 21.630	$ 15.760	$ 15.350	$ 16.610	$ 18.430	$ 17.800	$ 15.540
Return on average common equity (e)	19.40%	18.28%	16.16%	13.26%	12.63%	9.69%	11.70%
Capitalization data (Millions of dollars)
Common stock	$ 2,710.0	$1,740.7	$1,695.3	$2,033.9	$2,256.9	$2,169.1	$1,685.6
Preferred stock:
Not subject to mandatory redemption	74.0	74.0	74.0	170.1	170.1	170.1	235.1
Subject to mandatory redemption							29.3
Long-term debt and QUIDS	3,200.4	2,559.5	2,254.5	2,179.3	2,193.1	2,397.1	1,747.6
Total capitalization	$ 5,984.4	$4,374.2	$4,023.8	$4,383.3	$4,620.1	$4,736.3	$3,697.6
Capitalization ratios:
Common stock	45.3%	39.8%	42.1%	46.4%	48.8%	45.8%	45.6%
Preferred stock:
Not subject to mandatory redemption	1.2	1.7	1.9	3.9	3.7	3.6	6.3
Subject to mandatory redemption							.8
Long-term debt and QUIDS	53.5	58.5	56.0	49.7	47.5	50.6	47.3
Total assets (Millions of dollars)	$11,167.6	$7,697.0	$6,852.4	$6,535.2	$6,654.1	$6,618.5	$4,855.0

ALLEGHENY ENERGY, INC.							D-3
Consolidated Statistics (continued)

Year ended December 31	2001	2000	1999	1998	1997	1996	1991
Property data (Millions of dollars)
Gross property	$11,086.9	$9,507.0	$8,839.7	$8,395.3	$8,451.4	$8,206.2	$6,255.7
Accumulated depreciation	(4,233.9)	(3,967.6)	(3,632.6)	(3,395.6)	(3,155.2)	(2,910.0)	(2,093.7)
Net property	$ 6,853.0	$5,539.4	$5,207.1	$4,999.7	$5,296.2	$5,296.2	$4,162.0
Gross additions during year:
Regulated	$ 230.8	$ 207.6	$ 266.2	$ 229.4	$ 284.7	$ 289.5	$ 337.7
Unregulated and other	$ 233.3	$ 195.6	$ 141.3	$ 1.8	$ 1.4	$ 178.5
Ratio of provisions for depreciation to
depreciable property	2.62%	2.85%	3.23%	3.28%	3.34%	3.47%	3.28%
Revenues (Millions of dollars) (f)
Residential	$ 1,141.3	$1,018.6	$ 930.3	$ 880.6	$ 892.9	$ 932.2	$ 708.3
Commercial	633.7	536.5	500.3	501.4	490.5	492.7	375.4
Industrial	776.4	772.8	720.5	753.5	748.1	752.9	600.2
Wholesale and street lighting	70.7	57.4	42.4	69.0	65.1	66.6	50.0
Revenues from regular utility customers	2,622.1	2,385.3	2,193.5	2,204.5	2,196.6	2,244.4	1,733.9
Other non-gWh	35.8	40.7	9.8	9.9	6.4	7.7	8.7
Bulk power	160.5	135.8	45.7	69.8	39.6	22.4	158.5
Transmission and other energy services	70.8	73.2	61.0	45.2	41.1	52.4	47.5
Total regulated revenues	$ 2,889.2	$2,635.0	$2,310.0	$2,329.4	$2,283.7	$2,326.9	$1,948.6
Total unregulated revenues	$ 8,644.4	$2,281.6	$ 879.4	$ 247.0	$ 85.8	$ .7
Other	$ 139.6	$ 22.6	$ 8.9
Sales volumes - gWh
Residential	14,454	14,062	13,562	12,939	12,832	13,328	11,755
Commercial	9,616	9,510	8,955	8,626	8,176	8,132	7,003
Industrial	19,884	20,320	19,846	19,675	19,040	18,568	16,430
Wholesale and street lighting	1,502	1,531	1,478	1,409	1,422	1,456	1,146
Regular utility transactions	45,456	45,423	43,841	42,649	41,470	41,484	36,334
Bulk power	1,421	750	571	3,037	1,667	966	5,800
Transmission and other energy services	10,630	10,851	8,450	7,345g	12,367	17,402	13,962
Total regulated transactions	57,507	57,024	52,862	53,031	55,504	59,852	56,096
Total unregulated transactions	114,507	41,707	15,854	8,278	3,734	109
Output and delivery - gWh
Steam generation	46,101	46,773	44,776	44,323	43,463	40,067	42,307
Hydro and pumped-storage generation	2,158	1,969	1,648	1,326	1,171	1,348	1,654
Pumped-storage input	(2,600)	(2,327)	(1,963)	(1,498)	(1,298)	(1,405)	(1,907)
Purchased power	118,345	43,917	17,365	11,505	6,485	5,518	2,910
Transmission and other energy services	10,630	10,851	8,450	7,777	12,367	17,402	13,962
Combustion turbines	493	56	7
Losses and system uses	(3,189)	(3,075)	(3,066)	(2,124)	(2,950)	(2,969)	(2,830)
Total transactions as above	171,938h	98,164h	67,217h	61,309	59,238	59,961	56,096

Consolidated Statistics (continued)							D-4
Energy Supply
Generating capability - MW
Regulated - owned	2,115	2,356	4,451	8,121	8,071	8,070	7,992
Unregulated - owned	9,944	6,407	4,142	276	276
Unregulated contracts(i)	479	479	299	299	299	299	162
Maximum hour peak - MW	8,265j	7,791j	7,788j	7,314j	7,423	7,500	6,238
Load factor regulated	66.3%k	70.2%k	70.5%k	69.1%k	68.3%	67.5%	71.7%
Heat rate - Btus per kWh	9,945l	9,919l	9,963	9,939	9,936	9,910	9,956
Fuel costs - cents per million Btus	125.59m	118.57m	119.61	128.92	130.05	129.22	143.19

a Write-off in connection with deregulation proceedings in West Virginia, Virginia, Ohio, Maryland, and Pennsylvania and costs associated with the reacquisition of first mortgage bonds. b Reflects the adoption of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. c Reflects a two-for-one common stock split, effective November 4, 1993. d Basic earnings per average share. e Excludes the extraordinary charge, net, and Pennsylvania restructuring activities in 1998; the extraordinary charge and other charges for merger-related costs; a long dormant pumped-storage generation project in 1999; the extraordinary charge in 2000; and the cumulative effect of the accounting change in 2001. Includes the effect of internal restructuring in 1995 and 1996. f Eliminations between regulated and unregulated are shown on page M-12. g Excludes 432 gWh delivered to customers participating in the Pennsylvania pilot program that are included in regulated utility transactions sales volumes. h Net of 76, 566, and 1,499 gWh eliminated between regulated and unregulated in 2001, 2000, and 1999, respectively. i Capability available through contractual arrangements with unregulated generators. j Peak coincident load of all customers provided delivery service within the Company's service territory irrespective of the generation service chosen by the customers therein. k Based on peak coincident load. l Includes the combustion turbines' heat rate. m Includes the combustion turbines' fuel costs.

Regulated Statistics							D-5

Year ended December 31	2001	2000	1999	1998	1997	1996	1991
Customers (thousands)(a)
Residential	1,507.1	1,495.1	1,250.6	1,236.9	1,224.9	1,213.7	1,146.6
Commercial	190.8	187.9	158.1	154.7	151.5	148.5	134.7
Industrial	26.5	26.3	25.9	25.5	25.2	25.0	23.1
Other	1.3	1.3	1.3	1.3	1.3	1.3	1.3
Total customers	1,725.7	1,710.6	1,435.9	1,418.4	1,402.9	1,388.5	1,305.7
Average annual use (kWh per customer)(b)
Residential	11,200	10,993	10,913	10,486	10,521	11,042	10,316
All retail service	29,521	28,847	28,285	28,174	28,647	29,085	27,205
Average rate (cents per kWh)(b)
Residential	6.94	6.89	7.03	6.90	6.96	6.99	6.03
All retail service	5.34	5.30	5.45	5.32	5.36	5.46	4.80

a Electric and gas customers in the Company's regulated franchised service territory receiving delivery service.
b Use and rate statistics are calculated based on full-service customers (customers receiving both generation and delivery from the Company).

Dividends Paid - Range of Common Stock Prices Per Share
	2001				2000
	2001				2000
NYSE Composite Transactions	Dividend	High	Low	Close	Dividend	High	Low	Close
1^st Quarter	.43	$49.000	$39.500	$46.260	.43	$29.563	$23.625	$27.750
2^nd Quarter	43	55.900	44.700	48.250	43	31.750	26.688	27.563
3^rd Quarter	43	49.250	35.200	36.700	43	39.875	27.750	38.000
4^th Quarter	43	40.010	32.990	36.220	43	48.750	36.688	48.188

The high and low prices in 2002 were $36.190 and $31.890 through February 7, 2002. The last reported sale on that date was $33.370.

ALLEGHENY ENERGY, INC.				D-6
Quarterly Financial Information (Unaudited)
(Millions of dollars)
	December 2001	September 2001	June 2001		March 2001*	December 2000**	September 2000	June 2000	March 2000***
Operating revenues	$2,055.1	$3,690.0	$2,940.4		$1,693.4	$1,221.3	$1,058.5	$865.3	$866.8
Operating Income	124.7	241.3	185.8		163.2	149.2	128.0	118.9	140.1
Consolidated income before extraordinary charge and cumulative effect of accounting change	64.6	165.7	115.8		102.8	79.7	76.1	71.5	86.4
Extraordinary charge, net						(6.5)			(70.5)
Cumulative effect of accounting change, net					(31.1)
Consolidated net income	64.6	165.7	115.8		71.7	73.2	76.1	71.5	15.9
Basic earnings per average share:****
Consolidated income before extraordinary charge and cumulative effect of accounting change	.50	1.33	.97		.93	.72	.69	.65	.78
Extraordinary charge, net						(.06)			(.64)
Cumulative effect of accounting change, net					(.27)
Consolidated net income	.50	1.33	.97		.66	.66	.69	.65	.14
* Results for the first quarter of 2001 reflect charges for the adoption of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. Results for the fourth quarter of 2000 reflect charges for Ohio and Virginia restructuring. * Results for the first quarter of 2000 reflect charges for West Virginia restructuring. **** Basic earnings per average share was calculated using the average common shares outstanding at the end of each respective quarter.

	D-7 Allegheny Energy, Inc.

Investor Information

Dividend Declarations

Dividends are normally declared on the first Thursday of March, June, September, and December. Record dates are normally the second Monday after the dividend is declared, with payment dates the last business day of March, June, September, and December.

Dividend Reinvestment and Stock Purchase Plan

Our Dividend Reinvestment and Stock Purchase Plan provides shareholders with a convenient way to purchase additional shares of the Company's stock. Participants may at the time of each cash dividend payment on the stock have all or part of their dividends automatically invested in additional shares or invest any additional amount they wish between $50 and $10,000 in such shares or do both. The offering of shares under the Plan is made only by Prospectus. To get the Prospectus and an Authorization Form to enroll in the Plan, contact Mellon Investor Services, L.L.C., at 1-800-648-8389 or write to Gregory L. Fries, General Manager, Investor Relations, Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740-1766, or e-mail: investorinfo@alleghenyenergy.com.

Annual Meeting

The Annual Meeting of Shareholders will be held in the Basildon Room on the third floor of The Waldorf-Astoria, 301 Park Ave., New York, NY, on Thursday, May 9, 2002, at 9:30 a.m.

Form 10-K

The Company will provide without charge to each beneficial holder of its common stock, on the written request of such person, a copy of Allegheny Energy's combined Annual Report to the Securities and Exchange Commission on Form 10-K for 2001. Any such request should be directed to Cynthia A. Shoop, Vice President, Corporate Communications, Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740-1766, or investorinfo@alleghenyenergy.com.

Duplicate Mailings/Direct Deposit of Dividends

If you receive duplicate mailings of the Annual Report or wish to have your dividends deposited directly to your banking institution, please notify Mellon Investor Services, L.L.C., P.O. Box 3316, South Hackensack, NJ 07606. To speak to a representative responsible for Allegheny Energy shareholder accounts, call 1-800-648-8389.

Stock Transfer Agent and Registrar

Mellon Investor Services, L.L.C., Overpeck Centre, 85 Challenger Road, Ridgefield Park, NJ 07660. The internet address is www.mellon-investor.com.investor information

(Thousands of Dollars)	Quarter Ended
	2001				2000
	Mar	June	Sept	Dec	Mar	June	Sept	Dec

Operating revenues	$297,409	$207,955	$202,426	$229,933	$193,477	$176,734	$194,942	$262,894
Operating income	41,556	29,226	30,050	32,918	32,718	25,543	37,633	39,473
Consolidated net income (loss)	30,089	19,337	18,032	21,999	(33,809)	17,275	28,390	19,599

SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
	2001	2000 *	1999	1998	1997	1996
Revenues
Electric retail revenues
Residential	$232,807	$230,924	$210,757	$200,896	$199,931	$206,033
Commercial	144,035	144,345	130,052	126,464	118,825	121,631
Industrial	214,979	220,593	217,792	208,613	196,716	200,970
Electric retail revenues	591,821	595,862	558,601	535,973	515,472	528,634
Other electric revenues
Affiliated	85,624	101,975	84,747	77,314	83,600	74,825
Wholesale and street lighting	7,324	7,468	7,138	7,656	7,600	7,513
Other non-kWh	4,982	4,832	4,299	4,426	4,379	4,136
Bulk power and
Transmission services	12,902	14,330	18,550	19,753	17,260	17,363
Total electric revenues	702,653	724,467	673,335	645,122	628,311	632,471
Gas retail revenues
Residential	139,109	67,431
Commercial	79,748	32,693
Industrial	4,083	856
Gas retail revenues	222,940	100,980
Other gas revenues
Wholesale	4,113	1,601
Gas transportation and other	8,017	999
Total gas revenues	235,070	103,580
Total revenues	937,723	828,047	673,335	645,122	628,311	632,471
Operation expense	541,094	444,696	345,565	313,795	305,487	310,480
Maintenance	83,075	70,850	63,993	67,033	70,561	74,735
Internal restructuring charges and
Asset write-off						24,299
Depreciation and amortization	79,011	72,704	60,905	58,610	56,593	55,490
Taxes other than income taxes	63,815	55,987	43,395	44,742	38,776	40,418
Federal and state income taxes	36,978	50,639	40,440	49,456	47,519	34,496
Allowance for funds used during
Construction	(2,794)	(902)	(1,774)	(1,043)	(1,386)	(672)
Interest charges	54,830	45,738	34,603	36,153	38,730	38,604
Other income, net	(7,743)	(6,244 )	(6,119)	(6,049)	(8,498)	(6,831 )
Consolidated income before
Extraordinary charge	89,457	94,579	92,327	82,425	80,529	61,452
Extraordinary charge, net (a)		(63,124 )
Consolidated net income	$ 89,457	$ 31,455	$ 92,327	$ 82,425	$ 80,529	$ 61,452

Return on average common equity (b)	12.13%	14.43%	15.29%	13.62%	13.99%	11.00%
(a)Write-off in connection with Ohio and West Virginia deregulation proceedings.
(b)Excludes a charge for a long dormant pumped-storage generation project in 1999. Includes the effect of internal restructuring in 1996.
*Certain amounts have been reclassified for comparative purposes.
D-9
Monongahela Power Company and Subsidiaries

CONSOLIDATED FINANCIAL AND OPERATING STATISTICS
	2001	2000	1999	1998	1997	1996
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross	$2,490,741	$2,545,764	$2,173,603	$2,007,876	$1,950,478	$1,879,622
Accumulated depreciation	(1,139,904 )	(1,152,953 )	(958,867 )	(883,915 )	(840,525 )	(790,649 )
Net	$1,350,837	$1,392,811	$1,214,736	$1,123,961	$1,109,953	$1,088,973

GROSS ADDITIONS TO PROPERTY
(Thousands):	$ 104,931	$ 82,243	$ 82,483	$ 72,795	$ 78,139	$ 72,577

TOTAL ASSETS at Dec. 31
(Thousands):	$2,025,347	$2,005,668	$1,626,406	$1,519,764	$1,497,756	$1,486,742

CAPITALIZATION at Dec. 31
(Thousands)
Common stock	$ 629,594	$ 707,899	$ 578,951	$ 570,188	$ 540,930	$ 512,212
Preferred stock	74,000	74,000	74,000	74,000	74,000	74,000
Long-term debt and QUIDS	784,261	606,734	503,741	453,917	455,088	474,841
	$1,487,855	$1,388,633	$1,156,692	$1,098,105	$1,070,018	$1,061,053

Ratios:
Common stock	42.3%	51.0%	50.0%	51.9%	50.6%	48.3%
Preferred stock	5.0	5.3	6.4	6.8	6.9	7.0
Long-term debt and QUIDS	52.7	43.7	43.6	41.3	42.5	44.7
	100.0%	100.0%	100.0%	100.0%	100.0%	100.0%

GENERATING CAPABILITY-
kw at Dec. 31:
Company-owned	2,115,000	2,356,000	2,352,250	2,326,300	2,326,300	2,326,300
Nonutility contracts (a)	161,000	161,000	161,000	161,000	161,000	161,000

KILOWATT-HOURS (Thousands):
Sales Volumes:
Residential	3,190,702	3,148,565	2,884,144	2,757,067	2,764,630	2,815,414
Commercial	2,449,275	2,439,764	2,148,361	2,102,604	1,987,147	2,007,116
Industrial	5,846,404	5,975,983	5,736,718	5,510,925	5,224,364	5,024,257
Wholesale and street
Lighting	155,834	158,303	152,476	142,797	142,827	142,198
Sales to retail
Customers	11,642,215	11,722,615	10,921,699	10,513,393	10,118,968	9,988,985
Affiliated	3,112,483	3,489,689	2,746,111	1,950,803	2,080,542	1,694,722
Bulk power	1,827	29,966	191,784	301,656	249,505	196,843
Transmission and other
Energy services	2,611,737	2,698,380	2,138,247	1,932,160	3,007,439	4,218,150
Total sales volumes	17,368,262	17,940,650	15,997,841	14,698,012	15,456,454	16,098,700
Output and Delivery:
Steam generation	11,249,555	12,723,425	12,146,537	11,251,721	10,936,469	10,678,491
Pumped-storage generation	492,339	479,128	372,658	288,266	241,958	263,640
Pumped-storage input	(634,179)	(612,800)	(481,872)	(370,822)	(310,565)	(337,451)
Purchased power	4,316,258	3,358,567	2,562,752	2,283,055	2,294,059	2,040,136
Transmission and other
Energy services	2,611,737	2,698,380	2,138,247	1,932,160	3,007,439	4,218,150
Losses and system uses	(667,448 )	(706,050 )	(740,481 )	(686,368 )	(712,906 )	(764,266 )
Total transactions as
Above	17,368,262	17,940,650	15,997,841	14,698,012	15,456,454	16,098,700

CUSTOMERS at Dec. 31:
Residential	548,416	312,180	309,760	307,920	305,579	303,568
Commercial	66,049	38,654	37,929	37,168	36,323	35,793
Industrial	8,045	8,014	7,992	7,996	8,019	8,085
Other	182	176	218	199	182	170
Total customers	622,692	359,024	355,899	353,283	350,103	347,616

RESIDENTIAL SERVICE:
Average use-kWh per
customer	9,447	9,283	8,938	9,023	9,256	9,306
Average revenue-dollars
per customer	689.32	678.38	651.29	652.53	677.37	693.11
Average rate-cents per
kWh	7.30	7.31	7.29	7.23	7.32	7.45

(a) Capability available through contractual arrangements with nontuility generator

QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)	Quarter Ended
	2001				2000
	Mar	June	Sept	Dec	Mar*	June	Sept	Dec*

Operating revenues	$235,621	$197,458	$221,682	$209,773	$214,734	$188,604	$206,699	$217,782
Operating income	28,085	17,963	24,121	15,365	40,231	30,273	24,465	25,821
Income before extra-
ordinary charge, net	19,195	9,105	14,619	5,116	31,111	20,047	16,014	17,213
Extraordinary charge,
net					(12,278)			(1,621)
Consolidated net income	19,195	9,105	14,619	5,116	18,833	20,047	16,014	15,592


D-13
The Potomac Edison Company
and Subsidiaries
CONSOLIDATED FINANCIAL AND OPERATING STATISTICS (continued)
	2001	2000	1999	1998	1997	1996
CUSTOMERS at Dec. 31:
Residential	361,661	353,721	346,821	339,584	333,224	327,344
Commercial	48,592	47,336	45,968	44,828	43,794	42,670
Industrial	5,587	5,382	5,235	5,122	5,010	4,887
Other	640	632	620	641	598	571
Total customers	416,480	407,071	398,644	390,175	382,626	375,472

RESIDENTIAL SERVICE :
Average use-kWh per customer	13,887	13,861	13,523	13,093	13,003	14,179
Average revenue-dollars per customer	968.55	948.77	961.92	919.42	908.87	999.10
Average rate-cents per kWh	6.97	6.84	7.11	7.02	6.99	7.05
(a) Capability available through contract arrangements with non-utility generators.

QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)
	Quarter Ended
	2001				2000
	Mar	June	Sept	Dec	Mar	June	Sept	Dec
Operating revenues	$292,826	$268,331	$272,801	$280,546	$257,544	$250,563	$266,528	$270,992
Operating income	45,469	38,658	37,335	37,322	36,047	44,377	42,919	40,973
Consolidated net
Income	33,083	26,019	25,446	25,297	20,053	33,589	29,972	18,789

D-17
QUARTERLY FINANCIAL INFORMATION				Allegheny Generating Company
(Thousands of Dollars)
	Quarter Ended
	2001					2000
	Dec	Sept	June		March	Dec	Sept	June	March

Operating revenues	$18,563	$15,451	$16,738		$17,772	$18,256	$17,257	$17,359	$17,155
Operating income	8,998	7,132	7,848		8,797	8,535	9,032	8,939	8,583
Net income	6,105	4,012	4,673		5,510	5,095	5,914	5,593	5,278

Quarter Ended	Operating Revenues	Cost of Fuel, Purchased Energy, and Transmission, and Operating Expenses	Operating Income	Consolidated Income Before Income Taxes, Minority Interest, and Cumulative Effect of Accounting Change	Cumulative Effect of Accounting Change	Consolidated Net Income
	(Thousands of dollars)
March 2000	$ 376,020	$ 343,947	$ 32,073	$ 27,571		$ 18,155
June 2000	410,350	394,796	15,554	12,104		9,949
September 2000*	689,229	657,114	32,115	23,042		14,759
December 2000*	783,973	719,722	64,251	51,360		32,625
March 2001**	1,203,808	1,126,840	76,968	67,223	$(31,147)	10,673
June 2001	2,556,966	2,417,609	139,357	112,197		71,744
September 2001	3,312,206	3,095,520	216,686	184,481		117,647
December 2001	1,538,575	1,508,717	29,858	936		3,624
* Includes earnings associated with assets transferred on August 1, 2000, from Potomac Edison.
** Results for the first quarter of 2001 reflect charges for the adoption of Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities' on January 1, 2001.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS______________

	Page No.
AE Monongahela Potomac Edison West Penn AGC AE Supply	M- 1 M-34 M-53 M-70 M-88 M-99

The information required by this Item was furnished in the copy of the Form 10-K filed with the Securities and Exchange Commission. You may obtain a complete copy of Form 10-K upon making a written or an oral request directed to: Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740, Attention: Marleen L. Brooks, Secretary (tel. 301-790-3400).

	Capacity in Megawatts
In operation:
Unregulated generation	9,944
Regulated utility	2,115
Announced construction and development, contractual control, and planned expansions:
Unregulated generation	2,643
Total	14,702

Earnings Summary
	Earnings			Basic Earnings Per Average Share
(Millions of dollars except per share data)	Earnings			Basic Earnings Per Average Share
	2001	2000	1999	2001	2000	1999
Operations:
Regulated utility	$203.3	$227.7	$236.5	$1.69	$2.06	$2.03
Unregulated generation	245.8	83.7	49.1	2.05	.76	.42
Other unregulated	(.2)	2.2	(.2)		.02
Consolidated income before extraordinary charges and cumulative effect of accounting change	448.9	313.6	285.4	3.74	2.84	2.45
Extraordinary charges, net (Notes B, C, and F to consolidated financial statements)		(77.0)	(27.0)		(.70)	(.23)
Cumulative effect of accounting change, net (Note J to consolidated financial statements)	(31.1)			(.26)
Consolidated net income	$417.8	$236.6	$258.4	$3.48	$2.14	$2.22

	Fair value of contracts at December 31, 2001
Classifications of contracts by source of fair value	Delivery less than 1 year	Delivery 2 - 3 years	Delivery 4 - 5 years		Delivery in excess of 5 years	Total fair value
	(Millions of dollars)
Prices actively quoted	$(239.7)	$(75.6)		$ (.5)	$ 5.1	$ (310.7)
Prices provided by other external sources				(12.8)	(1.9)	(14.7)
Prices based on models	24.8	134.0		364.3	562.7	1,085.8
Total	$(214.9)	$ 58.4		$351.0	$565.9	$ 760.4

(Millions of dollars)	Amount
Net fair value of commodity contract assets and liabilities at December 31, 2000	$ 9.9
Net fair value of commodity contracts acquired with the energy trading business	218.3
Subtotal	228.2
Adoption of SFAS No. 133	(52.3)
Fair value of structured transactions when entered into during 2001	45.0
Net options paid and received	(23.8)
Unrealized gains on commodity contracts, net	563.3
Net fair value of commodity contract assets and liabilities at December 31, 2001	$760.4

Fuel Expenses
(Millions of dollars)	2001	2000	1999
Regulated utility	$127.8	$232.7	$355.5
Unregulated generation	454.1	319.5	180.2
Total fuel expenses	$581.9	$552.2	$535.7

Purchased Power and Exchanges, Net
(Millions of dollars)	2001	2000	1999
Regulated utility:
Purchased power:
From PURPA generation*	$ 191.6	$ 191.0	$ 104.1
Other purchased power	1,043.8	745.0	395.8
Total purchased power for regulated utility	1,235.4	936.0	499.9
Power exchanges, net	.1	6.9	(2.6)
Unregulated generation purchased power	7,183.9	1,520.9	390.1
Eliminations	(1,181.9)	(871.1)	(356.0)
Purchased power and exchanges, net	$ 7,237.5	$1,592.7	$ 531.4
*PURPA cost (cents per kWh)	5.4	5.5	4.8

POTOMAC EDISON CO 10-K