THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY ENERGY, INC., 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 owns, directly and indirectly, various regulated and non-regulated subsidiaries (collectively and generically, Allegheny). For the fiscal year ended December 31, 2000, AE had total revenues of $4,012 million, earnings before interest, income taxes, depreciation and amortization of $969 million, and operating income of $536 million.

    AE conducts its business through its direct and indirect wholly-owned subsidiaries. Monongahela Power Company (Monongahela), The Potomac Edison Company (Potomac Edison) and West Penn Power Company (West Penn) are electric distribution (or delivery) companies (the Distribution Companies). Allegheny Energy Supply Company, LLC (Allegheny Energy Supply) is an unregulated electric supply company that is expanding its electric generation fleet. Allegheny Ventures, Inc. (Allegheny Ventures) is an unregulated company that develops and operates telecommunications and energy-related businesses through its subsidiaries. Allegheny Generating Company (AGC) is an indirect subsidiary whose only asset is an undivided interest in a pumped-storage hydro-electric station. AE also owns exempt wholesale generation (EWG) subsidiaries. The properties of Allegheny Energy Supply are located in Maryland, Pennsylvania and West Virginia. The properties of the Distribution Companies and AGC are located in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia; are interconnected; and are located along transmission facilities owned in whole or part by the Distribution Companies, which are interconnected with all neighboring utility systems. The Distribution Companies are doing business under the trade name Allegheny Power.

     In August 2000, Monongahela acquired all of the outstanding stock of Mountaineer Gas Company (Mountaineer), a natural gas distribution company incorporated in West Virginia. Mountaineer serves approximately 205,000 retail natural gas customers in West Virginia. Mountaineer owns approximately 4,000 miles of natural gas distribution pipelines. During 2000, Mountaineer sold or transported 57 billion cubic feet (Bcf) of gas. The Mountaineer acquisition also included the acquisition of Mountaineer's unregulated subsidiary, Mountaineer Gas Services (MGS). MGS 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 electric distribution 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 402,000 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 its generation assets and its interest in AGC to Allegheny Energy Supply pursuant to state legislation and regulatory proceedings. See the discussion of the transfer below under Allegheny Energy Supply, and in ITEM 1. RATE MATTERS. The six largest communities served 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. There are four municipal electric distribution systems in its service area, all of which purchased power from Potomac Edison in 2000, and six rural electric cooperatives, one of which purchased power from Potomac Edison in 2000.

     West Penn, incorporated in Pennsylvania in 1916, operates its electric distribution system in southwestern and north and south-central Pennsylvania. West Penn is doing business under the trade name Allegheny Power. West Penn serves about 681,000 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 its generation assets and its interest in AGC to Allegheny Energy 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.

     AGC, organized in 1981 under the laws of Virginia, is jointly owned as follows: Monongahela, 27% and Allegheny Energy Supply, 73%. 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 840-megawatt (MW) share of 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 a wholly-owned non-regulated subsidiary of AE. Allegheny Ventures has three wholly-owned subsidiaries--AYP Energy, Inc. (AYP Energy), Allegheny Communications Connect, Inc. (ACC), and Allegheny Energy Solutions, Inc. (Allegheny Energy Solutions), all Delaware corporations. Allegheny Ventures recently filed with the Securities and Exchange Commission (SEC) to purchase Leasing Technologies International, Inc., a privately held leasing and financing company which provides financial services to entities engaged in telecommunications, software, internet, and other technologies. 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 part owner of APS Cogenex, a limited liability company formed with EUA Cogenex. APS Cogenex ceased its marketing activities in 1996 and is concluding existing projects. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Significant Events in 2000, 1999, and 1998 for a further description of Allegheny Ventures and its subsidiaries' activities.)

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, capital expenditures, earnings on assets, resolution and impact of litigation, regulatory matters, liquidity and capital resources, 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 other matters, electric utility restructuring, including ongoing state and federal activities; developments in the legislative, regulatory, and competitive environments in which Allegheny operates, including regulatory proceedings affecting rates charged by AE's subsidiaries; environmental, legislative, and regulatory changes; future economic conditions; earnings retention and dividend payout policies; Allegheny's ability to compete in unregulated energy markets; and other circumstances that could affect anticipated revenues and costs such as significant volatility in the market price of wholesale power and fuel for electric generation, unscheduled maintenance or repair requirements, weather, and compliance with laws and regulations. In addition, factors include significant volatility in the California energy market with respect to electricity and natural gas prices.

Electric Energy Competition

     The electricity supply segment of the electric utility industry in the United States continues to become more competitive. The Energy Policy Act of 1992 began the process of deregulating 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. Since 1992, the wholesale electricity market has become increasingly competitive. In addition, more states have taken active steps toward allowing retail customers the right to choose their electricity supplier. Allegheny has been an advocate of federal legislation to create competition in the retail electricity markets to avoid regional dislocations and ensure level playing fields.

Activities at the Federal Level

     Allegheny continues to seek enactment of federal legislation to bring choice to all retail electric customers, deregulate the generation and sale of electricity on a national level, and create a more liquid, free market for electric power. Fully meeting challenges in the emerging competitive environment will be difficult for Allegheny unless certain outmoded and anti-competitive laws, specifically the Public Utility Holding Company Act of 1935 (PUHCA) and Section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA) regarding mandatory power purchase provisions, are repealed or significantly revised. Allegheny continues to advocate the repeal of PUHCA and PURPA on the grounds that they are obsolete and anti-competitive, and that PURPA results in utility customers paying above-market prices for power. In the 106^th Congress, a number of electric utility restructuring bills were considered, many of which addressed PUHCA repeal and PURPA reform, among other issues. A stand-alone reliability bill was not taken up in the House after passage in the Senate. A comprehensive restructuring bill died in the House Commerce Committee upon adjournment late in 2000. It is uncertain whether legislation addressing electric utility restructuring will be forthcoming in the 107^th Congress.

Activities at the State Level

Maryland

     On April 8, 1999, Maryland Governor Glendening signed legislation that brought competition to Maryland's electric supply market.

     Allegheny Energy Supply will market the deregulated generation to the retail and wholesale markets, with the restriction that it may not market to retail customers within Potomac Edison's Maryland territory for various time frames, some of which terminate at the end of 2003. On April 5, 2000, the Maryland PSC granted Allegheny Energy Supply a license to operate as a provider of electric generation supply and services in Maryland.

     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 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 Allegheny Energy Supply. Asymetric pricing also does not apply to the generation supply contract between Potomac Edison and Allegheny Energy 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. The trial in this case was held on January 25, 2001. The petitioners are awaiting the Judge's order.

Ohio

     The Ohio General Assembly passed legislation in 1999 to restructure its electric utility industry. All of the state's customers became able to choose their electricity supplier on January 1, 2001, 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 determination of stranded cost recovery was left to the Ohio Public Utilities Commission (Ohio PUC).

     On November 7, 2000, the Ohio PUC granted Allegheny Energy Supply a certificate as a Competitive Retail Electric Service Provider 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, all electricity customers in Pennsylvania had the right to choose their electric suppliers. Over 100 electric suppliers have been licensed to sell to retail customers in Pennsylvania. Pursuant to the Customer Choice Act, in November 1999, West Penn transferred its generation assets to Allegheny Energy Supply. The transmission and distribution assets remain with West Penn and under regulated ratemaking.

     West Penn has responsibility as the electricity 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 contracts, Allegheny Energy Supply supplies West Penn with power during the Pennsylvania transition period. Under this contract, Allegheny Energy Supply provides West Penn with the amount of electricity, up to its retail load, that it may demand. These contracts (and those that Allegheny Energy Supply has with Potomac Edison) represent a significant portion of the normal operating capacity of Allegheny Energy Supply's generating assets that were previously owned by West Penn and Potomac Edison.

Virginia

     On July 11, 2000 the Virginia State Corporation Commission (Virginia SCC) issued an Order approving Potomac Edison's Phase I separation plan and permitting the transfer of Potomac Edison's generation assets to Allegheny Energy Supply. Potomac Edison transferred its generation assets to Allegheny Energy Supply on August 1, 2000. Potomac Edison will transfer four small Virginia hydroelectric facilities to a subsidiary of Allegheny Energy Supply in 2001. Consistent with Virginia SCC regulations, Potomac Edison filed Phase II of its functional separation plan on December 19, 2000.

     The Virginia SCC adopted regulations governing the transfer of ownership or control of transmission facilities to a Regional Transmission Organization. On October 16, 2000, Potomac Edison filed with the Virginia SCC a copy of the October 16 FERC Order 2000 RTO Compliance Filing regarding the PJM West proposal, which would become operational as required by FERC Order 2000 (currently December 15, 2001). See ITEM 1. REGULATORY FRAMEWORK AFFECTING ELECTRIC POWER SALES for more information regarding PJM West.

     On September 22, 2000, the Virginia SCC granted a competitive service provider license to Allegheny Energy Supply. The license permits Allegheny Energy Supply to provide competitive electric supply service to all classes of retail customers in conjunction with the ongoing retail access pilot programs of Dominion Virginia Power and American Electric Power-Va.

West Virginia

     On June 23, 2000 the West Virginia PSC approved Potomac Edison's request to transfer Potomac Edison's generating assets to Allegheny Energy Supply on or after July 1, 2000. On August 1, 2000, Potomac Edison transferred its West Virginia assets to Allegheny Energy Supply. Assets are being leased back to Potomac Edison in amounts sufficient to satisfy customers not yet able to shop for alternate suppliers in West Virginia. In accordance with the restructuring 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 establish safeguards with respect to the transactions and interactions between gas utilities, their affiliates and competitive gas suppliers; to avoid potential market-power abuses; to eliminate cross-subsidization between regulated and unregulated activities; and to promote effective competition in the natural gas market within West Virginia.

Allegheny's Competitive Actions

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

Allegheny Energy Supply

     Allegheny Energy Supply was formed in 1999 to consolidate AE's deregulated generating assets into a single company that is not subject to state regulation of sales prices. As of December 31, 2000, Allegheny Energy Supply owned 6,273 MW of generating assets.

     Allegheny Energy Supply is an unregulated energy company that markets competitive wholesale and retail electricity. Allegheny Energy Supply intends to become a national energy merchant company with an additional 4,131 MW of announced additions of generating capacity either through acquisitions or construction of facilities in Arizona, Illinois, Indiana, Tennessee, and Pennsylvania.

     Pursuant to contracts, Allegheny Energy Supply supplies West Penn and Potomac Edison with power during the Pennsylvania and Maryland transition periods. Under these contracts, Allegheny Energy Supply provides these regulated electricity distribution affiliates with the amount of electricity, up to their retail load, that they may demand. These contracts represent a significant portion of the normal operating capacity of Allegheny Energy Supply's generating assets that were previously owned by West Penn and Potomac Edison. Allegheny Energy Supply will enter into similar contracts with Monongahela.

     The Energy Trading Business is intended to help Allegheny Energy Supply become a major merchant in the national energy marketplace by combining its structured transactions, trading skills and market presence with Allegheny Energy Supply's low-cost generating fleet. The acquisition also includes support infrastructure necessary to conduct business immediately upon completion of the transaction. In addition, the purchase is expected to facilitate Allegheny Energy Supply's risk management efforts. (See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.)

     Starting in 2000, the energy market in California has been very volatile with respect to electricity and natural gas prices. Allegheny Energy Supply seeks to mitigate risks associated with the California market volatility by hedging its long or short positions, e.g. the CDWR contract discussed above. (See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK for a discussion of Allegheny's corporate energy risk control policy.)

     In January 2001, AE 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. Construction on the facility will begin in 2002 and will be completed in two stages. Two 44-MW simple-cycle combustion turbines will be constructed first in 2003, followed by the addition of 542 MW of combined-cycle capacity in 2005. When completed, the facility will allow Allegheny Energy Supply to sell additional generation into the East Central Area Reliability Region (ECAR), as well as give Allegheny Energy Supply greater access to other mid-west markets.

     In November 2000, AE announced the signing of a definitive agreement with Enron North America, a wholly-owned subsidiary of Enron Corporation, under which AE will purchase three natural gas-fired merchant generating facilities in the Midwest for approximately $1.0 billion. The purchase includes the following generating assets, all of which have been in service since June 2000: the Gleason plant (546 MW) in Gleason, Tennessee; the Wheatland plant (508 MW) in Wheatland, Indiana; and the Lincoln Energy Center plant (656 MW) in Manhattan, Illinois. AE anticipates the transfer of these generating assets to subsidiaries of Allegheny Energy Supply in 2001. These assets will provide Allegheny Energy Supply with additional natural gas-fired generating capacity within ECAR, the Mid-America Interconnected Network and the Southeastern Electric Reliability Council. The purchase is scheduled to close by May 31, 2001. AE anticipates the transfer of these generating assets to subsidiaries of Allegheny Energy Supply in 2001. These assets will provide Allegheny Energy Supply with additional natural gas-fired generating capacity within ECAR, the Mid-America Interconnected Network and the Southeastern Electric Reliability Council.

     In October 2000, AE announced that Allegheny Energy Supply plans to construct a 1,080-MW natural gas-fired merchant generating facility in La Paz County, Arizona, approximately 75 miles west of Phoenix. Construction is 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 served by the Western System Power Pool, including all or parts of California, western Canada, Colorado, Montana, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming.

     In September 2000, AE announced that its subsidiary Allegheny Energy Supply Hunlock Creek, LLC, along with partner UGI Development, a subsidiary of UGI Corporation (UGI), will market electricity 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, LLC installed a 44-MW natural gas-fired combustion turbine on property owned by UGI in the fourth quarter of 2000. UGI Development and Allegheny Energy Supply Hunlock Creek, LLC will jointly share in the combined output of the coal-fired and combustion turbine generating units. Allegheny Energy Supply Hunlock Creek, LLC, was responsible for construction of the Hunlock Creek combustion turbine, while UGI will operate the facilities. Allegheny Energy Supply Hunlock Creek, LLC is a subsidiary of AE, until approvals are obtained to transfer the subsidiary to Allegheny Energy Supply. Allegheny Energy Supply anticipates the transfer to be completed in 2001. The venture will give Allegheny Energy Supply access to 46 MW of generating capacity to sell into the PJM market.

     In January 2000, AE also announced that Allegheny Energy Supply will begin construction on a 540-MW combined-cycle generating plant at Springdale, Pennsylvania. The new facility will include two gas-fired combustion turbines and a steam turbine. The combined-cycle facility is expected to be operational and providing power for sale into competitive markets in 2003.

     Also, Allegheny Energy Supply plans to install two 44-MW simple-cycle combustion turbines in Pennsylvania during 2001.

     AE has petitioned the Securities and Exchange Commission (SEC) for approval to transfer 217-MW of exempt wholesale generating (EWG) facilities owned by its subsidiaries to Allegheny Energy Supply. SEC approval is required for Allegheny Energy Supply to own EWG facilities. SEC approval of the transfer is expected in 2001.

Allegheny Ventures

     Allegheny Ventures (formerly known as AYP Capital, Inc.) was formed in 1994 to engage in unregulated activities. In 1996, Allegheny Ventures formed two nonutility subsidiaries: AYP Energy and ACC. In 1997, Allegheny Ventures formed Allegheny Energy Solutions.

Telecommunications

     In March 2000, ACC, along with five other energy and telecommunications companies, formed a new, super-regional player in the telecommunications market, AFN Communications, formerly America's Fiber Network. ACC received an interest in AFN Communications by contributing a portion of its fiber optic network to this new venture.

     AFN Communications has an initial fiber footprint of 7,700 route miles and 140,000 fiber miles spanning 13 states and Washington, D.C. AFN reaches about 35 percent of the national wholesale communications capacity market, linking small and rural communities to major metropolitan areas. It provides high-capacity telecommunications transport services to internet service providers, competitive local exchange providers, long-distance providers, and wireless communications companies. AFN Communications plans to expand its reach by adding new partners and their fiber assets and offering advanced network services. Other founding partners include AEP Fiber Venture, LLC, a subsidiary of American Electric Power; GPU Telcom Services, Inc., a subsidiary of GPU, Inc.; Fiber Venture Equity, Inc., a subsidiary of FirstEnergy Corporation; CFW Network, Inc.; and R&B Network, Inc.

     ACC continues to expand its own fiber optic network. In 1999, there were 600 route miles in the growing network. It was expanded to more than 1,300 route miles in 2000. With much growth potential in this market, ACC plans to build nearly 1,400 additional route miles in 2001. ACC also provides value-added services to customers of the network, including advanced around-the-clock network monitoring through its alliance with and 5 percent ownership interest in Genosys Technology Management, Inc., an emerging network operation center services provider.

     ACC also is part of a consortium, led by Adelphia Business Solutions, which was selected by the Commonwealth of Pennsylvania to build an advanced information technology infrastructure and to provide state government with state-of-the-art voice, video, internet, and data telecommunications services. As part of this project, ACC is conducting wireless internet pilot programs in three Pennsylvania markets.

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

     In 1997, ACC, formed a limited liability company, Allegheny Hyperion Telecommunications, L.L.C with Hyperion Communications of Pennsylvania, Inc. (now Adelphia Business Solutions). During 2000, Adelphia Business Solutions exchanged ACC's 50 percent ownership in Allegheny Hyperion Telecommunications, L.L.C. for 330,000 shares of Adelphia Business Solutions' Class A Common Stock.

Investments and Other Activities

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

Distribution Companies

     On August 18, 2000, Monongahela acquired Mountaineer, a natural gas distribution company serving southern West Virginia and the northern and eastern panhandles of West Virginia, from Eastern Systems Corporation, a subsidiary of Energy Corporation of America. Mountaineer serves approximately 205,000 retail natural gas customers in West Virginia. Mountaineer owns approximately 4,000 miles of natural gas distribution pipelines. The acquisition also included the acquisition of Mountaineer's unregulated subsidiary, Mountaineer Gas Services (MGS).

     MGS 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 located throughout West Virginia and surrounding production areas and has active leaseholds that cover more than 86,000 acres. MGS also has a net revenue interest in about 100 wells of which it is not the operator.

SALES

Regulated Electric Sales

2000

1999

Increase/
(Decrease)

Regulated Utility Customers

Kilowatt-hour Sales

Residential

14,062

13,562

3.7%

Commercial

9,510

8,955

6.2%

Industrial

20,320

19,846

2.4%

Wholesale

1,531

1,478

3.6%

Kilowatt-hour Sales

45,423

43,841

3.6%

Regulated Revenue (Millions)

Residential

$967.2

$930.3

4.0%

Commercial

529.2

500.3

5.8%

Industrial

751.2

720.5

4.3%

Wholesale

55.8

42.4

31.6%

Total Regulated Revenue

$2,303.4

$2,193.5

5.0%

     In 2000, consolidated regulated kilowatt-hour (kWh) sales delivered to customers of retail and wholesale power increased 3.6% from those of 1999 as a result of increases of 3.7%, 6.2%, 2.4% and 3.6% in residential, commercial, industrial and wholesale sales, respectively. Consolidated regulated revenues increased 5.0% due to increases of 4.0%, 5.8%, 4.3%, and 31.6% 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 7,791 MW on January 27, 2000. (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.) The Regulated Peak Load in 2000 was 7,455 MW on December 22, 2000. This value is subject to a final reconciliation process. However, the final value is not expected to vary significantly from 7,455 MW. (Regulated Load refers to the electricity sales to customers of Allegheny Power (the Distribution Companies) who have not selected an alternate generation supplier. It does not include sales by Allegheny Energy Supply to nonaffiliated customers within the Allegheny Power service territory.)

     Consolidated regulated electric operating revenues for 2000 were derived as follows: Pennsylvania, 40.2%; West Virginia, 31.4%; Maryland, 20.4%; Virginia, 5.6%; and Ohio, 2.4% (residential, 38.2%; commercial, 20.8%; industrial, 29.7%; bulk power transactions, 8.3%; and other, 3.0%).

     Monongahela's electric operating revenues were derived as follows: West Virginia, 91.2%, and Ohio, 8.8% (residential, 31.9%; commercial, 19.9%; industrial, 30.4%; bulk power transactions, 2.0%; and other, 15.8%).

     During 2000, Potomac Edison's kWh sales to retail customers increased 3.4%. Residential, commercial, and industrial sales increased 4.5%, 4.6% and 2.1%, respectively. Revenues from residential increased .5% while commercial and industrial sales decreased 2.8% and 2.3%, respectively. The increase in residential revenues was due primarily to growth in the number of residential customers and colder than normal weather conditions in late 2000. Despite the ability of Maryland customers to shop for another energy supplier since July 1, 2000, at December 2000, no residential customers have elected to choose another energy supplier. The decreases in revenues for commercial and industrial customers were 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 Potomac Edison the ability to choose another energy supplier effective July 1, 2000. Revenues from bulk power transactions and sales to affiliates increased 155.4%. Potomac Edison's revenues represented 31.3% of Allegheny's total regulated sales revenues to customers. Potomac Edison's all-time Control Area Peak Load of 2,656 MW occurred on January 27, 2000. The Regulated Peak Load in 2000 was 2,656 MW on January 27, 2000.

     Adjusting for West Penn's 1999 unregulated activity, West Penn's 2000 regulated kWh sales and deliveries to retail customers increased 1.5%. Residential, commercial and industrial sales deliveries increased .4%, 3.4% and 1.4%, respectively. Regulated revenues from residential, commercial and industrial customers increased 3.8%, 9.6% and 11.3%, respectively. The increases in revenues for residential, commercial and industrial customers were due primarily to growth in the number of customers and increased customer usage, partially due to weather conditions in late 2000. Also, even though Pennsylvania deregulation gave all of West Penn's regulated customers the ability to choose another energy supplier in 2000 (as opposed to two-thirds of West Penn's regulated customers in 1999), electric energy supplied to West Penn customers by alternative energy suppliers declined in 2000 from 11% of total mWh sales to 7% of total mWh sales. Revenues from bulk power transactions and sales to affiliates decreased 88.4%. West Penn's regulated revenues represented 42.2% of Allegheny's total regulated sales to customers. West Penn's all-time Control Area Peak Load of 3,328 MW occurred on July 6, 1999. The Control Area Peak Load in 2000 was 3,311 MW on June 26, 2000. The Regulated Peak Load in 2000 was 3,112 MW on December 22, 2000.

     West Penn's regulated electric operating revenues were derived as follows: Pennsylvania, 100% (residential, 38.6%; commercial, 21.1%; industrial, 30.9%; bulk power transactions, 2.4%; and other, 7.0%).

     In 2000, the Distribution Companies provided approximately 0.8 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 $135.8 million.

Unregulated Electric Sales

2000

1999

Increase /
(Decrease)

Kilowatt-hour Sales*

Unregulated Generation

41,707

15,854

163.1%

Total Kilowatt-hour Sales

41,707

15,854

163.1%

Unregulated Revenue (Millions)*

Unregulated Generation

$2,281.6

$879.4

159.4%

Other

22.6

8.9

153.9%

Total Revenue

$2,304.2

$888.3

159.4%

*Unregulated generation sales include amounts for recording Allegheny Energy Supply's energy trading contracts at their fair value as of the balance sheet date.

Unregulated sales revenues, including energy sales to affiliates in total, were $2,304.2 million, of which approximately $799.2 million were the result of energy sales to affiliates. Excluding the effect of affiliated sales, unregulated revenues represented 37.5% of Allegheny's total operating revenues in 2000.

In 2000, the consolidated regulated million cubic feet (Mcf) of gas delivered to retail and wholesale power customers was 14,873,642 as a result of the acquisition of West Virginia Power and Mountaineer. Residential, commercial, industrial and wholesale sales were 58.0%, 8.8%, 31.8% and 1.4% of the total Mcf regulated sales, respectively. Consolidated regulated gas revenues for 2000 were $81.8 million. Residential, commercial, industrial and wholesale gas sales represented 62.8%, 9.0%, 26.2% and 2.0% of the total regulated gas revenues.

Regulatory Framework Affecting Electric Power Sales

     The 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. On March 4, 1997, the FERC issued Orders 888A and 889A reaffirming and clarifying the legal and policy determinations as originally adopted in the previous orders. The FERC also issued Orders 888B and 889B on November 25, 1997 in which the FERC presented explanations and minor revisions to specific sections of the orders.

     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. Accordingly, Allegheny formed discrete business units, including a delivery business unit (inclusive of transmission) and a supply business unit. The delivery business unit includes several sub-units, including the System Planning and Operations group, which provides transmission system operations and reliability functions. Each business unit has its own management, objectives, and facilities. 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. In October 1997, the Distribution Companies submitted a new wholesale tariff to the FERC, asking for authority to sell power at market-based rates. The Distribution Companies 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 Allegheny Energy Supply was filed and became effective August 15, 1999. Allegheny Energy Supply started serving customers under that tariff on November 19, 1999.

     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. This total includes 180 MW from the AES Warrior Run project, which came on-line in February 2000. Payments for PURPA capacity and energy in 2000 totaled approximately $204 million, before amortization of West Penn's adverse power purchase commitment, resulting in an average cost to the Distribution Companies of 5.5 cents/kWh.

ELECTRIC FACILITIES

     The following table shows Allegheny's operational generating capacity as of December 31, 2000, based on the maximum operating capacity of each unit. Monongahela's owned capacity totaled 2,113 MW, of which 1,886 MW (90%) are coal-fired and 227 MW (10%) 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.

     Allegheny Energy Supply's owned or contracted capacity as of December 31, 2000, totaled 6,273 MW of which 5,360 MW (85.4%) are coal-fired, 154 MW (2.5%) are oil-fired, 613 MW (9.8%) are pumped-storage, 88 MW (1.4%) are gas fired, and 58 MW (.9%) are hydroelectric.

ALLEGHENY MAP

     The Allegheny Map (Map), which has been filed with the SEC on Form SE, provides a broad illustration of the names and approximate locations of Allegheny's major generation and transmission facilities, both existing and under construction, in a five state region which includes portions of Maryland, Ohio, Pennsylvania, Virginia, and West Virginia. Additionally, Extra High Voltage substations are displayed. By use of shading, the map also provides a general representation of the service areas of Monongahela (both gas and electric, including Mountaineer) (portions of West Virginia and Ohio), Potomac Edison (portions of Maryland, Virginia, and West Virginia), and West Penn (portions of Pennsylvania).

     Power Stations shown on the map which appear within the Monongahela service area are Willow Island, Pleasants, Harrison, Rivesville, Albright, and Fort Martin. The single power station appearing within the Potomac Edison service area is R. Paul Smith. The Bath County Power Station appears on the map just south of the westernmost portion of Potomac Edison's service area formed by the borders of Virginia and West Virginia. Power stations appearing within the West Penn service area are Armstrong, Mitchell, Hatfield's Ferry, Gans, Allegheny Energy Unit No. 1 and Unit No. 2 and Lake Lynn. The Hunlock Creek Energy Ventures and Allegheny Energy Supply Conemaugh, LLC generating facilities are not depicted.

Distribution Lines (a) and Number of Substations

Total Miles

Portion of Total Miles Representing 500-Kilovolt (kV) Lines

Monongahela

21,140

283

Potomac Edison

18,316

202

West Penn

24,223

273

AGC(b)

85

85

Total

63,764

843

(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 2000 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. The Distribution Companies serve 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 the congested facilities. The new security process has provided a better exchange of operation planning information. It also has allowed more accurate evaluation of the transmission system and conditions in the Midwest that occasionally caused the predominant west-to-east power flow pattern across the Distribution Companies' network to reverse. The TLR procedure has been effective in addressing congestion caused by parallel path flows. Careful use of TLR, mainly by others, has resulted in fewer constraints on the Distribution Companies' transmission facilities. If TLR had not been available, many of those transmission congestion events would have required action in the form of transmission service curtailments.

     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, managed access is also governed by the provisions of the Distribution Companies' Open Access Transmission Tariff mandated by and filed with the FERC.

RESEARCH AND DEVELOPMENT

     The Distribution Companies and Allegheny Energy Supply spent $6.4 million and $7.0 million, in 2000 and 1999, respectively, for research programs. Of these amounts, $5.2 million and $5.5 million were for Electric Power Research Institute (EPRI) dues in 2000 and 1999, respectively. EPRI is an industry-sponsored research and development institution. The Distribution Companies and Allegheny Energy Supply plan to spend approximately $6.6 million for research in 2001, 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 businesses. These technology drivers include products and services for environmental control, generating unit performance, future generation technologies, use of coal combustion by-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 (EMF) assessment of employee exposure within the work environment, Global Warming from Green House Gases (GHG) 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 ventures.

     The use of biomass for cofiring 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 (NO_x), sulfur oxides, particulate matter (PM), and carbon dioxide. It also reduces operation, maintenance and compliance costs.

CAPITAL REQUIREMENTS AND FINANCING

Construction Expenditures

Allegheny Energy Supply and AGC

     Construction expenditures of Allegheny Energy Supply were $176.1 million and $50.8 million for 2000 and 1999, respectively. Total capital expenditures in 2000, including construction expenditures, for all generating assets operated or to be acquired by Allegheny Energy Supply (excluding generating assets currently owned by Monongahela) were $182.0 million and, for 2001 and 2002, are estimated at $1,947.4 million and $313.6 million, respectively. The 2001 and 2002 estimated expenditures include $148 million and $169 million, respectively, for environmental control technology. Outages for construction, 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. Allegheny Energy Supply could potentially face significant mandated increases in capital expenditures and operating costs related to environmental issues. Allegheny Energy Supply also has additional capital requirements for debt maturities.

     Construction expenditures by AGC in 2000 amounted to $1.0 million and for 2001 and 2002 are expected to be $.8 million, and $.2 million, respectively.

Distribution Companies

     Construction expenditures by the Distribution Companies in 2000 amounted to $207.6 million. Construction expenditures for 2001 and 2002 are expected to aggregate $233.3 million and $214.3 million, respectively. The 2001 and 2002 estimated regulated expenditures include $33.5 million and $41.7 million, respectively, to cover the costs of compliance with the Clean Air Act Amendments of 1990 (CAAA). 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 2001.

      Regulated generation-related expenditures by Monongahela for 2000, 2001, and 2002 include $43.8 million, $40.8 million, and $55.7 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.

     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 transmission and distribution (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 plant since provision of delivery service remains within the authority of each Distribution Company.

Allegheny Ventures

*Includes allowance for funds used during construction (AFUDC), or capitalized interest in the case of the generation business of West Penn and Allegheny Energy Supply, for 1999, 2000, and 2001 of: Monongahela $0.1, $0.1, and $0.1; Potomac Edison $0.6, $0.3, and $0.5; West Penn $0.1, $0.2, and $0.2; and Allegheny Energy Supply $0.0, 22.0, and 54.9.

Financing Programs

Allegheny Energy Supply

     To meet cash needs for operating expenses, the payment of interest, retirement of debt, and for Allegheny Energy Supply's acquisition and construction programs, Allegheny Energy Supply has used internally generated funds, member contributions, and external financings, such as debt instruments, installment loans, and lease arrangements. The availability and cost of external financings depend upon the financial condition of Allegheny Energy Supply and market conditions.

     Short-term debt increased to $198 million in 2000 and consists of commercial paper borrowings of $166 million and notes payable to AE of $53 million. At December 31, 2000, unused lines of credit with banks were $180 million.

     In November 2000, Allegheny Energy Supply consummated an operating lease transaction relating to the construction of a 540-MW combined-cycle generating plant located in Springdale, Pennsylvania. This transaction was structured to finance the construction of the plant with a maximum commitment amount of $318.4 million. Upon completion of the plant, a special purpose entity will lease the plant 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 2005. Subsequently, Allegheny Energy Supply has the right to negotiate up to two five-year renewal terms or purchase the plant for the lessor's investment, or sell the plant and pay the difference between the proceeds and the lessor's investment up to a maximum recourse amount of approximately $275 million.

    Allegheny Energy Supply anticipates meeting its 2001 cash needs through internal cash generation, cash on hand, short-term borrowings as necessary, external financings, lease arrangements, and by issuing debt and equity.

Distribution Companies and AGC

     The Distribution Companies and AGC have financed their construction programs through internally generated funds, first mortgage bonds, debentures, medium-term notes, subordinated debt and preferred stock issues, pollution control and solid waste disposal notes, installment loans, long-term lease arrangements, equity investments by AE (or, in the case of AGC, by its parent companies), and, where necessary, interim short-term debt. Their future ability to finance their construction programs by these means depends on many factors, including effects of competition and creditworthiness, and adequate revenues to produce satisfactory internally generated funds and return on the common equity portion of the Distribution Companies' capital structures and to support their issuance of senior and other securities.

     During 2001, Monongahela, Potomac Edison and West Penn anticipate meeting their capital requirements through a combination of internally generated funds, cash on hand, issuance of debt, short-term borrowing and leasing arrangements, as necessary.

     The Distribution Companies' and AGC's ratios of earnings to fixed charges for the year ended December 31, 2000 were as follows: Monongahela, 4.04, Potomac Edison, 3.70, West Penn, 3.30 and AGC, 3.18.

AE

     In August 2000, AE issued $165 million of unsecured notes at an interest rate of 7.75%, due August 1, 2005. In November 2000, AE issued an additional $135 million of unsecured notes at an interest rate of 7.75%, due August 1, 2005.

     During 2001, to finance the purchase of additional generating assets, AE plans to issue $500 million of common stock and enter into $550 million of debt, as a short-term bridge borrowing.

     Beginning in the third quarter of 1997, AE began buying shares in the open market for its Dividend Reinvestment and Stock Purchase Plan and its Employee Stock Ownership and Savings Plan, and in 1998 AE began buying shares in the open market for the Performance Share Plan. In addition, in 1999, AE began buying shares in the open market for the common stock portion of the Outside Directors' annual retainer.

     At December 31, 2000, Allegheny companies had short-term debt of $722 million outstanding. The borrowing positions of the individual companies were: AE $486 million, Monongahela $37 million, Potomac Edison $33 million, and Allegheny Energy Supply $166 million.

     In the event of an initial public offering of and/or spin-off of Allegheny Energy Supply or other similar strategy, AE's board of directors may elect to establish dividend policies for each business unit that would be consistent with its earnings prospects, growth rate, need for capital and other factors that would be different from and likely lower than the current policy for the integrated company.

FUEL SUPPLY

ELECTRIC GENERATION

     In 2000, generating stations owned by Allegheny Energy Supply, Monongahela and Potomac Edison burned approximately 18.5 million tons of local mid to high sulfur coal. Of that amount, 38% was used in stations equipped with scrubbers (7.0 million tons). The use of desulfurization equipment and the cleaning and blending of coal make burning local coal practical. In 2000, 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 2000, Allegheny Energy Supply, Monongahela and Potomac Edison had long-term arrangements (i.e., terms of 12 months or longer) in place to purchase approximately 16.5 million tons of coal or 90.0% of the coal consumed in 2000. In 2000, Allegheny Energy Supply, Monongahela and Potomac Edison purchased approximately 11 million tons of coal from various local mines owned by subsidiary companies of one company. Long-term arrangements are in effect to provide for up to approximately 18.0 million tons of coal in 2001. Monongahela and Allegheny Energy Supply will depend on short-term arrangements and spot purchases for their remaining requirements. Through the year 2005, the total coal requirements of present Allegheny-operated stations are expected to be met with coal acquired under existing contracts or from known suppliers.

     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 Allegheny Energy Supply's fuel mix from the current predominantly coal-fired generation facilities. This change in fuel mix and diversification is expected to assist Allegheny Energy 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 (Supply 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 Supply Agreement coincides with the three-year West Virginia Rate Moratorium. The Rate Moratorium froze rates (fuel and base) until October 31, 2001. Mountaineer has filed a rate case requesting permission to increase rates beginning November 1, 2001.

     The Supply Agreement provides that Coral will be responsible for supplying in excess of 90% of Mountaineer's total annual gas requirements for the three-year term. The balance of Mountaineer's gas supply requirements will be purchased from local producers, including MGS-owned/operated production adding up to approximately 2.7 Bcf/year. Coral supplies the gas at a fixed price per decatherm (Dth) at the city gate up to approximately 24.4 Bcf annually. Any volumes in excess of 24.4 Bcf on an annual basis are priced at the lesser of a specified index or a previously agreed upon maximum cost.

     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 year ended June 30, 2000:

     The West Virginia PSC regulates MGS sales to Mountaineer, which accounts for the majority of MGS sales. The contract period runs concurrently with the current moratorium. The price for these sales is calculated by adding the Inside FERC's Gas Market Report Columbia Gas-Appalachia Index and the Columbia Gas ITS rate (approximately 18 cents April - October; and 25 cents November - March). MGS production makes up in excess of 90% 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 years ended June 30:

2000

1999

1998

Volume

% of

Volume

% of

Volume

% of

(Mmcf)

Total

(Mmcf)

Total

(Mmcf)

Total

WV Production Contracts

1,894

61.08%

2,044

60.08%

2,479

69.44%

Cabot Oil and Gas Marketing

772

24.90%

722

21.22%

1,061

29.72%

Other Supply Volumes

435

14.02%

636

18.70%

30

0.84%

GAS TRANSPORTATION AND STORAGE CAPACITY

     The gas purchased from producer/suppliers in the Gulf Coast 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 local distribution facilities in West Virginia. During the calendar year 2000, Columbia Gas transported approximately 83% of the gas purchased by Mountaineer in the Appalachian region, with the balance transported by Tennessee Gas Pipeline Company or directly delivered into Mountaineer's gas utility distribution system.

     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 who are capable of utilizing alternate fuels an energy source at their respective business facilities. In 2000, 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 WV 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 2,004 MW) of its generation assets to Allegheny Energy Supply.

     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 Monongahela consistent. Under the terms of the settlement, several tariff schedules, notably those available to residential and small commercial customers, will require incremental steps to reach the agreed-upon rate level. The settlement rates resulted in a revenue reduction for Monongahela of approximately $.5 million for 2000, increasing over 8 years to an annual reduction of approximately $6.0 million. Offsetting the decrease in rates, the settlement approved by the West Virginia PSC directs Monongahela to amortize the existing overcollected deferred fuel balance as of June 30, 2000 (a total of approximately $6.0 million) as a reduction of expenses over a four and one-half year period beginning July 1, 2000. Also, on July 1, 2000, Potomac Edison and Monongahela ceased their expanded net energy cost (fuel clause) as part of the settlement.

     Monongahela expanded its service territory with the acquisition of West Virginia Power in December 1999. Also, Monongahela acquired Mountaineer in August 2000. The acquisition of Mountaineer included Mountaineer Gas Services (MGS), a wholly-owned subsidiary of Mountaineer.

     Sales of MGS production (both owned and purchased from third parties) are by and large made to Mountaineer. With regard to MGS-owned production, the rate is regulated by the WV PSC for the period that runs concurrently with the West Virginia current rate moratorium and is indexed at the Inside FERC's Gas Market Report Columbia Gas-Appalachia Index, plus the Columbia Gas ITS rate (approximately 18 cents April - October; and 25 cents November - March). MGS-owned production accounts for in excess of 90% of the system supply purchased by Mountaineer that is not purchased under the Supply Agreement with Coral.

     On October 11, 2000, the West Virginia PSC approved an interim increase on 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 increase for the twelve-month period of $5.1 million or 22.6%). The commodity rate is the portion of the bill that reflects the cost of gas, which increased significantly during 2000. The West Virginia PSC has 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 allows Monongahela full recovery of these costs but eases the increase on the average customer. These increases have no effect on earnings because they were implemented via the Purchased Gas Adjustment mechanism. Under the Purchased Gas Adjustment 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 overrecoveries or underrecoveries, respectively.

      In October 2000, the Ohio PUC 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 is permitted to transfer the Ohio portion (approximately 352 MW) of its generation assets to Allegheny Energy Supply at net book value on or after January 1, 2001. Monongahela expects to transfer these assets in April, 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 beginning 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 may collect from shopping customers a regulatory transition charge of $0.0008 per kilowatt-hour (kWh) for the market development period; Allegheny Energy Supply is permitted to offer competitive generation service throughout Ohio; and, that additional taxes resulting from competition legislation will be deferred for up to two years as a regulatory asset.

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 generation assets to Allegheny Energy Supply on or after July 1, 2000. Potomac Edison also obtained the necessary approvals from the Virginia SCC and the WV PSC to transfer the Virginia and West Virginia portions of Potomac Edison's generation assets to Allegheny Energy Supply in conjunction with the transfer of the Maryland portion of those assets. In August 2000, Potomac Edison transferred approximately 2,100 MW of its Maryland, Virginia, and West Virginia generation assets to Allegheny Energy Supply. Certain small hydroelectric facilities located in Virginia are to be transferred to a subsidiary of Allegheny Energy Supply during 2001. On December 14, 2000, the VA SCC approved the transfer of these hydro facilities to Green Valley Hydro, LLC (a subsidiary of Potomac Edison).

     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 Green Valley Hydro, LLC (a wholly-owned subsidiary of Potomac Edison). On December 14, 2000, the Virginia SCC approved the transfer. Potomac Edison anticipates the transfer will occur during the second quarter of 2001, after receiving final approval from the SEC. In 2001, Green Valley Hydro, LLC will become a subsidiary of Allegheny Energy 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 the Functional Separation Plan with the Virginia SCC on December 19, 2000.

     Potomac Edison decreased the fuel portion of Maryland customers' bills by about $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 Potomac Edison'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 rates were rolled into base rates.

     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 twelve months beginning April 30, 2000. The refund of the overrecovered balance does not affect Potomac Edison's earnings since the overrecovered amounts had been deferred.

     On October 4, 2000, the Maryland PSC approved Potomac Edison's filing which represents the final reconciliation of its deferred fuel balance. Potomac Edison is refunding to customers the $3.2 million overrecovery balance existing in the Maryland deferred fuel account as of September 30, 2000. The deferred fuel credit to customers began in October 2000 and will be effective until the balance falls to zero, which is projected to take twelve months. The refund of the overrecovered balance does not affect Potomac Edison's earnings since the overrecovered amounts had been deferred.

     On November 29, 2000, the Maryland PSC approved the Power Sales Agreement between Potomac Edison, d/b/a Allegheny Power, and PG&E Energy Trading-Power, L.P. covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2001 through December 31, 2001. 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 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 is a result of the phase-in of the rate increase approved by the Maryland PSC on October 27, 1998. A settlement agreement, which includes recognition and dollar-for-dollar recovery of costs to be incurred from the AES Warrior Run PURPA project, was filed with the Maryland PSC on July 30, 1998 and was approved on October 27, 1998. 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 4% in each of the years 1999 and 2000, and will increase rates by about 4% in 2001 (a $79 million total revenue increase during 1999 through 2001). The increases are 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 agreement also requires 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, is being distributed to customers in the form of an Earnings Sharing Credit effective June 7, 2000 through April 30, 2001. Any sharing of earnings required for 2000 will be reflected as a credit on customers' bills starting in May 2001.

West Penn

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 Allegheny Energy 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.

     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. 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 allowances will allow it to economically comply with Phase II SO₂ limits through at least 2005 and 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.

     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. 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 receives 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.

     Title I of the CAAA established an Ozone Transport Region (OTR) consisting of the District of Columbia, the northern part of Virginia, and 11 northeastern states including Maryland and Pennsylvania. Sources within the OTR were required to reduce NO_x emissions, a precursor of ozone, to a level conducive to attainment of the one-hour ozone National Ambient Air Quality Standard (NAAQS). The installation of Reasonably Available Control Technology (RACT) (overfire air equipment and/or low NO _x burners) at all Pennsylvania and Maryland stations was completed by 1995. The installation of RACT also satisfied Title IV NO_x reduction requirements.

     In October 1998, the EPA issued a NO_x 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 NOx 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 NOx SIP call from May 2003 to May 2004. An appeal of the March 3, 2000 court decision is pending before the U.S. Supreme Court. During 2000, Pennsylvania and Maryland promulgated final rules to implement the EPA's NOx 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. Also in 2000, West Virginia issued a proposed rule to implement the EPA's NOx SIP call requirements beginning May 2005. However, the EPA has indicated they are unlikely to approve the West Virginia rule unless it is revised to conform to the NOx SIP call requirements, including an initial compliance date of May 2004. 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 Section 126 petitions 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 is also under litigation, with a decision expected Spring 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.

     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, the EPA did make a determination for regulatory controls in December 2000. 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.

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 being applied. Thus far Allegheny has successfully developed and scientifically justified, to the satisfaction of the regulatory agencies, alternate site-specific water quality criteria and thus avoided incurring the capital costs and potential liabilities of advanced wastewater treatment.

     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 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 implement the TMDL provisions of the CWA. The rule has drawn widespread bipartisan 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. Although the final rule is not as onerous as the proposal, it still carries objectionable provisions, particularly those that require preparation of TMDLs for water bodies that are impaired in whole or in part by air emissions (particularly NOx and mercury). A number of petitions for review have been filed by various industry, agricultural, forestry and environmental groups with briefing likely to occur in 2001.

     In anticipation of the potentially adverse impact of the TMDL program, 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:

     The Phase 1 new facility rule proposes strict uniform minimum technology requirements along with extensive site-specific study and monitoring requirements. If the proposal stands, new facilities will suffer severe siting restrictions, and will be subjected to costly environmental studies and time delays to accomplish the studies. In some situations, the new facilities could be required to apply dry cooling at significant additional cost. Moreover, the precedent-setting impact the new facility rule would have on existing facilities could be significant. It likely will require 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.

Hazardous and Solid Wastes

     Allegheny is in a continual process of either permitting new or re-permitting existing disposal capacity to meet future disposal needs. All disposal areas are currently operated to be in compliance with their permits.

     In addition to using coal combustion by-products (CCB's) in various power plant applications such as scrubber by-product stabilization at Harrison and Mitchell Power Stations, Allegheny Energy Supply on its own behalf and on behalf of Monongahela Power (the only Distribution Company still owning generation) continues to expand its efforts to market CCB's for beneficial applications and thereby reduce landfill requirements. In 2000, Allegheny received approximately $1,100,000 from the external sale and utilization of approximately 435,000 tons of fly ash, 225,000 tons of bottom ash and 28,000 tons of boiler slag. These CCB's were beneficially used in applications such as cement replacement, anti-skid materials, grit blasting material, mine reclamation, mine subsidence, structural fills, and grouting of mines and oil wells.

     Allegheny completed the construction of a processing plant, which will convert 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. The processing plant went into commercial production in 2000 and is expected to produce between 400,000 and 600,000 tons of gypsum per year for a wallboard manufacturing facility. This process will significantly reduce the amount of by-product going to an impoundment.

     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.)

Toxic Release Inventory (TRI)

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. Allegheny is responding appropriately and will continue to explore cost-effective opportunities to improve efficiency and performance. The scientific debate is continuing; however the Clinton Administration signed an international treaty called the Kyoto Protocol, which would require the U.S. to reduce emissions of Green House Gases (GHG) by 7% from 1990 levels in the 2008-2012 time period. With normal economic growth this requirement could mean as much as a 40% reduction of GHG by 2012. The U.S. Senate must ratify the Kyoto Protocol before it can be of any effect domestically, as must other nations subject to the treaty's provisions. The Senate passed a resolution in 1997 (S.R. 98) by a vote of 95-0 that placed two conditions on entering into any international climate change treaty. First, any treaty must include all nations, and, second, any treaty must not cause serious harm to the U.S. economy. The Kyoto Protocol does not appear to satisfy either of these conditions and, therefore, the previous Administration withheld it from consideration by the Senate. The U.S. electric utility industry generates about one third of the GHG emitted, with other Industries, Transportation and Agriculture the rest, or two thirds. Implementation of the Kyoto Protocol would raise considerable uncertainty about the future viability of fossil fuels as an energy source for new and existing power plants.

     If and when the need for reducing GHG emissions has been identified and scientifically supported, Allegheny believes that a global solution involving all nations will be needed and must give credit for voluntary actions taken; precipitous and urgent action under strict limits and timetables will result in severe economic dislocation and is not warranted based on the ongoing scientific debate; and that appropriate results can be achieved domestically by continuing to build upon Allegheny's corporate awareness and the notable progress of existing voluntary programs.

     The Distribution Companies and Allegheny Energy Supply maintain an active climate-related research program and are responsive to the GHG guidelines suggested in the national Energy Policy Act of 1992. As a result, Allegheny Energy Supply and the Distribution Companies have voluntarily reduced their total annual emissions of GHG by about 1,650,000 tons, as described in the latest filing with the Department of Energy .

     The Distribution Companies and Allegheny Energy Supply support EPRI whose climate research is funded at around $7 to $10 million per year and also support Edison Electric Institute's Climate Challenge Initiative; and have committed to invest $3.11 million in an electro technology and renewable energy venture capital fund.

     The Distribution Companies' and Allegheny Energy Supply's in-house research program has contributed to applications of new technology, operating efficiencies, reduced electrical losses and pollution emission reductions.

     West Penn, as part of its restructuring settlement approved by the Pennsylvania PUC in 1998, agreed to support five important climate related initiatives: 1) Renewable Energy Development, 2) Sustainable Energy Fund ($11,425,721 paid on December 31, 1998), 3) Renewable Energy Pilot Program ($300,000 each year), 4) Energy Cooperative Association of Pennsylvania (contribution of $4 million) and 5) Universal Service and Energy Conservation Program ($8.082 million per year).

     In response to environmental issues over the past 30 years, the Distribution Companies and Allegheny Energy Supply spent over $1.6 billion in capital expenditures and approximately $200 million annually in operations and maintenance. Allegheny is committed to environmental stewardship and the research needed to provide answers to difficult compliance problems. These actions will mitigate the impact of the Distribution Companies' and Allegheny Energy Supply's operations on the environment and ameliorate any alleged climate change impacts.

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 Allegheny Energy 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.

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 Allegheny Energy 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 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 and ALLEGHENY 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

     On December 17, 1999, AES/Beaver Valley, Inc., (AES/BV) filed a demand for arbitration with the American Arbitration Association. AES/BV requested a declaratory judgment that the Electric Energy Purchase Agreement (EEPA) approved by the PaPUC in 1986 continues to govern the transaction between West Penn and AES/BV for the sale of up to 125 MWH per hour of power as set forth in the EEPA, even if AES/BV's proposed improvements to the plant to comply with the more rigorous NOx standards result in an increase in the amount of energy the plant produces annually. AES/BV also requested an award of its attorneys fees and costs. On April 4, 2000, an arbitrator granted the declaratory judgment request of AES/BV, but denied its request for attorneys fees and costs.

     As of February 16, 2001, Monongahela has been named as a defendant along with multiple other defendants in a total of 7,825 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 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 1,465 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 March 4, 1994, the Distribution Companies received notice that the EPA had identified them as 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 1977-8. 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.

     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. These electric generating stations are owned by Allegheny Energy Supply and Monongahela Power. 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 the facility, which would require compliance with the new source performance standards. 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 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 clean-up and remediation. Monongahela continues to cooperate with EPA and DOJ toward resolution of the agencies' concerns. At this time, Monongahela cannot predict the outcome of this matter but reasonably believes it will not have a material impact on Monongahela.

      In connection with litigation concerning DQE, Inc.'s unilateral termination of the Agreement and Plan of Merger dated April 5, 1997 with AE, on May 17, 2000, the Third Circuit Court of Appeals affirmed the District Court's decision that DQE did not breach the merger agreement. No request for reconsideration or other appeal has been filed.

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

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, 2000, there were 40,589 holders of record of AE's common stock.

2000

1999

Dividend

High

Low

Dividend

High

Low

1^st Quarter

43 cents

$29.5625

$23.625

43 cents

$34.5

$28.6875

2^nd Quarter

43 cents

$31.75

$26.6875

43 cents

$35.1875

$29.50

3^rd Quarter

43 cents

$39.875

$27.75

43 cents

$34.875

$31.0

4^th Quarter

43 cents

$48.75

$36.6875

43 cents

$33.125

$26.1875

     The high and low prices through March 10, 2001 were $49.00 and $39.5625 The last reported sale on that date was at $47.34.

     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.

ITEM 6. SELECTED FINANCIAL DATA

Page No.

AE

D-1

Monongahela

D-6

Potomac Edison

D-9

West Penn

D-12

AGC

D-15

The information required by this Item was furnished in the copy of the Form 10-K filed with the Securities and Exchange Commission and is also found in AE's Annual Report to Stockholders for 2000. You may obtain an Annual Report to Stockholders 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.

Condensed Financial Statements

Year ended December 31, 2000

and Subsidiaries

and Subsidiaries

and Subsidiaries

and Subsidiaries

and Subsidiary

(Thousands of dollars)

Balance Sheets

Assets

Property, plant, and equipment*

$2,545,764

$1,410,382

$1,654,283

$25,341

$3,807,691

Accumulated depreciation

(1,152,953)

(514,167)

(543,000)

(1,040)

(1,754,823)

1,392,811

896,215

1,111,283

24,301

2,052,868

Excess of cost over net assets acquired

200,183

1,152

Cash and temporary cash investments

3,658

4,685

6,116

2,422

420

Other current assets

282,525

139,891

282,428

11,145

535,478

Regulatory assets

90,004

53,712

428,953

Other

60,387

14,258

10,856

25,072

18,806

Total

$2,029,568

$1,108,761

$1,839,636

$64,092

$2,607,572

*Includes construction work in progress

$ 33,476

$ 14,122

$ 25,459

$107,284

Capitalization and liabilities

Common stock, other paid-in capital,

retained earnings, and accumulated other

comprehensive income

$ 707,899

$ 412,753

$ 422,121

$58,741

$759,643

Preferred stock

74,000

Long-term debt and QUIDS

606,734

410,011

678,284

563,433