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

**Certain amounts have been reclassified for comparative purposes.

Unregulated sales revenues were $7,625.8 million, which represented 73.5% of AE's total operating revenues in 2001.

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

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

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

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

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

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

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

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

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

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

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

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

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

     The following table shows Allegheny's operational generating capacity as of December 31, 2001, based on the maximum operating capacity of each unit. Monongahela's owned capacity totaled 2,115 MW, of which 1,894 MW (89.6%) are coal-fired and 221 MW (10.4%) are pumped-storage. The term "pumped-storage" refers to the Bath County station, which stores energy for use principally during peak load hours by pumping water from a lower to an upper reservoir, using the most economic available electricity, generally during off-peak hours. During the generating cycle, power is produced by water falling from the upper to the lower reservoir through turbine generators.

     AE Supply's owned or contracted capacity as of December 31, 2001, totaled 9,895 MW (including 1,000 MW of gas-fired contractual capacity) of which 5,973 MW (60.4%) are coal-fired, 154 MW (1.6%) are oil-fired, 739 MW (7.5%) are pumped-storage, 2,974 MW (30.0%) are gas-fired, and 55 MW (.5%) are hydroelectric. See Item 1. BUSINESS Allegheny's Competitive Actions for a description of generating assets and generating capacity that AE Supply acquired in 2001.

     The following table sets forth the existing miles of tower and pole transmission and distribution lines and the number of substations of the Distribution Companies and AGC as of December 31, 2001:

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

(b) Total Bath County transmission lines, of which AGC owns an undivided 40% interest and Virginia Power owns the remainder.

     The Distribution Companies' transmission network has 12 extra-high-voltage (EHV - 345kV and above) and 31 lower-voltage interconnections with neighboring utility systems. The interregional EHV transmission system, which includes the Distribution Companies' network, continued in 2001 to operate near reliability limits during periods of heavy power flows that in the past have had a predominantly west-to-east orientation. In early 1997, North American Electric Reliability Council undertook the development of a national transmission security process. A representative from the Distribution Companies serves as one of 22 regional Security Coordinators. This security process includes a Transmission Loading Relief (TLR) procedure that identifies actual flow path consequences of all power transactions, and can be used to reduce loading on congested facilities. The new security process has provided a better exchange of operation planning information and has allowed more accurate evaluation of the transmission system. The TLR procedure has addressed congestion caused by parallel path flows, resulting in fewer congestion events on the Distribution Companies' transmission facilities.

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

     The Distribution Companies and AE Supply collectively spent $7.1 million and $6.4 million, in 2001 and 2000, respectively, for research programs. Of these amounts, $4.5 million and $4.8 million were for Electric Power Research Institute (EPRI) dues in 2001 and 2000, respectively. EPRI is an industry-sponsored research and development institution. The Distribution Companies and AE Supply plan to spend approximately $8.6 million for research in 2002 with EPRI dues representing $5.1 million of that total. In addition to EPRI support, in-house research conducted by Allegheny concentrates on technology-based issues that are important developments for each of Allegheny's lines of business. These technology drivers include products and services for environmental control, generating unit performance, alternative fuels, sustainable and clean coal technology developments, combustion turbine training, environmental effects and performance issues, future generation technologies, use of coal combustion products, transmission system performance, customer-related research, clean power technology (which includes both power quality technology and distributed generation technology for customers), delivery systems equipment and sustainable energy technologies.

     Research is also being directed to help address major issues for Allegheny and the entire electric industry. These include electric and magnetic field assessment of employee exposure within the work environment, global warming from greenhouse gas emissions, waste disposal and discharges to land, water and air resources, renewable resources, fuel cells, new combustion turbines, cogeneration technologies, transmission loading mitigation using Flexible AC Transmission System (FACTS) devices and new product development venture opportunities. The use of biomass for co-firing and gasification are being developed with two Allegheny stations directly firing sawdust. The use of biomass lowers production cost, and results in lower emissions of nitrogen oxides, sulfur oxides, particulate matter and carbon dioxide. It also reduces operation, maintenance and compliance costs. A new communication technology, patented by employees of AESC and employees of Shenandoah Electronics Intelligence, Inc., is expected to be purchased and marketed. This technology is designed to read meters and provide control to customer premises using distribution feeder lines and using digital and power electronic technology. The baud rate is low but very acceptable for metering and control services. Three AESC employees applied for and received patents in 2001 from the US Patent and Trademark Office for wastewater handling and plant optimization technology.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

     In 2001, generating stations owned by AE Supply and Monongahela burned approximately 18.4 million tons of local mid to high sulfur coal. Of that amount, 49% was used in stations equipped with scrubbers (9.1 million tons). The use of desulfurization equipment and the cleaning and blending of coal make burning local coal practical. In 2001, almost 100% of the coal received at these stations came from mines in West Virginia, Pennsylvania, Maryland and Ohio. None of the Allegheny companies mine or clean any coal. All raw, clean or washed coal from suppliers is purchased as necessary to meet station requirements.

     In 2001, AE Supply and Monongahela had long-term arrangements (i.e., terms of 12 months or longer) in place to purchase approximately 17.9 million tons of coal. AE Supply purchases coal from a

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

     The Distribution Companies own coal reserves estimated to contain about 125 million tons of higher sulfur coal recoverable by deep mining. There are no present plans to mine these reserves and, in view of economic conditions now prevailing in the coal market, the Distribution Companies plan to hold the reserves as a long-term resource.

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

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

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

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

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

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

     Gas purchased from producer/suppliers in the Gulf Coast producing basin/region is transported through the interstate pipeline systems of Columbia Gulf Transmission Company (Columbia Gulf) and Columbia Gas Transmission Corporation (Columbia Gas) to Mountaineer's and West Virginia Power's local distribution facilities in West Virginia.

     To ensure continuous, uninterrupted service to its customers, Mountaineer has in place long-term transportation and storage service agreements with Columbia Gas and Columbia Gulf. These contracts cover a wide range of transportation services and volumes, ranging from firm transportation service to no-

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

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

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

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

     On October 11, 2000, the West Virginia PSC approved an interim increase of the commodity rate for gas customers of Monongahela (formerly West Virginia Power customers) for gas service bills rendered on and after December 1, 2000. On December 11, 2000, the West Virginia PSC approved additional increases for bills rendered on and after January 1, 2001 through November 30, 2001 (total revenue

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

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

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

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

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

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

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

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

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     Effective with bills rendered on or after January 8, 2002, there was a decrease in Maryland distribution rates. This decrease or "Customer Choice Credit" is a result of implementing the rate reductions called for by a settlement agreement approved by the Maryland PSC in December 1999. Under the terms of this settlement agreement (covering stranded cost quantification mechanism, price protection mechanism and unbundled rates), Potomac Edison decreased its rates 7 percent for residential customers and .5 percent for the majority of commercial and industrial customers. The Customer Choice Credit will remain in effect until a total of $72.8 million (approximately $10.4 million annually) has been credited to residential customers and a total of $10.5 million (approximately $1.5 million annually) has been credited to commercial and industrial customers. Additionally, since the time the Maryland PSC approved the rate reductions outlined above, the environmental surcharge has increased and an electric universal service surcharge has been introduced, both of which must be recovered under Potomac Edison's distribution rate cap consistent with the 1999 settlement agreement. Accordingly, distribution rates have been further reduced by $3 million from the previously approved rates in the 1999 settlement agreement. The distribution rate cap for all customers is effective 2002 through 2004.

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

     The Pennsylvania Department of Revenue has increased the gross receipts tax rate from 4.4 percent to 5.9 percent for electric distribution companies in the state, including West Penn. The new rate is effective for calendar year 2002. State law directs West Penn to recover these increased tax charges by means of a State Tax Adjustment Surcharge (STAS) added to customer bills. On October 29, 2001, West Penn filed a request with the Pennsylvania PUC to recover the increased tax liability of approximately $16.8 million from ratepayers. By order entered December 21, 2001, the Pennsylvania PUC directed West Penn to include the STAS on customer bills rendered between January 1, 2002 and December 31, 2002. On January 8, 2002, the Office of Consumer Advocate (OCA) filed an appeal of the Commission order to the

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     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.

     The operations of the Allegheny-owned facilities, including generating stations, are subject to regulation as to air and water quality, hazardous and solid waste disposal, and other environmental matters by various federal, state, and local authorities. The generating units now owned by AE Supply are subject to the same environmental regulations as they were when owned by the Distribution Companies.

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

     Allegheny meets current emission standards as to sulfur dioxide (SO₂) by the use of scrubbers, the burning of low-sulfur coal, the purchase of cleaned coal to lower the sulfur content, and the blending of low-sulfur with higher sulfur coal.

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

     In an effort to introduce market forces into pollution control, the CAAA created SO₂ emission allowances. An allowance is defined as an authorization to emit one ton of SO₂ into the atmosphere.

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     Installation of scrubbers at the Harrison Power Station was the strategy undertaken by Allegheny to meet the required SO₂ emission reductions for Phase I (1995-1999). Allegheny estimates that its banked allowances will allow it to economically comply with Phase II SO₂ limits through 2005, and possibly beyond. Studies are ongoing to evaluate cost-effective options to comply with Phase II SO₂ limits, including those available in connection with the emission allowance trading market. Burner modifications at most of the Allegheny-operated stations satisfy the NO_x emission reduction requirements for the acid rain (Title IV) provisions of the CAAA. Additional NO_x reductions, which will require some Selective Catalytic Reduction (SCR) or other post-combustion control technologies, are being mandated in Maryland, Pennsylvania, and West Virginia for ozone nonattainment (Title I) reasons. Continuous emission monitoring equipment has been installed on all Phase I and Phase II units.

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

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

     In August 1997, eight northeastern states filed petitions in connection with Section 126 of the CAAA with the EPA requesting the immediate imposition of up to an 85% NO_x reduction from utilities located in the Midwest and Southeast (West Virginia included). The petitions claim NO_x emissions from these upwind sources are preventing their attainment of the ozone standard. In May 1999, the EPA issued a technical approval of the petitions and in December 1999, granted final approval of four of the petitions. The Section 126 petition rulemaking was also under litigation, but a court decision in May 2001, basically

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     The EPA is required by law to regularly review the NAAQS for criteria pollutants including ozone, particulate, SO₂, and No_x. Previous court orders in litigation by the American Lung Association have expedited these reviews. The EPA in 1996 decided not to revise the SO₂ and NO_x standards. Revisions to particulate matter (PM) and ozone standards were promulgated by the EPA in July 1997. Litigation over the revised particulate matter and ozone standards has recently been resolved and these requirements could impose substantial costs on Allegheny. Also, in May 1999, the EPA promulgated final regional haze regulations to improve visibility in Class I federal areas (national parks and wilderness areas). The EPA regional haze regulation is under litigation. The effect on Allegheny of these standards or regulations is unknown at this time, but could be substantial.

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

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

     In March 1998, the EPA released its Utility Air Toxics Report to Congress. The report itself did not recommend regulatory controls. However, in December 2000, the EPA did make a determination for the regulatory controls of power plant mercury emissions. The regulatory determination did not include any recommendations regarding the level or timing of reductions. However, the EPA plans to issue a proposed rule by December 2003, and a final rule by December 2004. Based on this schedule, it is unlikely implementation of mercury controls would be required before 2007-08.

     The Kyoto Protocol, signed by the Clinton Administration but not ratified by the U.S. Senate, would require drastic reductions in greenhouse gas emissions in the United States in response to the threat of "global warming". If ratified and implemented, this treaty likely would require extensive mitigation efforts on the part of Allegheny to reduce greenhouse gas emissions at electric generation plants and would raise considerable uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation facilities. While the Bush Administration has rejected the Kyoto Protocol, other developed countries in the world are expected to ratify it and abide by its terms beginning in 2008. The pressure on the US to join the rest of the world in reducing greenhouse gas emissions is expected to continue and increase both internationally and domestically.

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     Allegheny has taken numerous voluntary, precautionary steps to address the issue of global climate change. Many uncertainties remain in the global climate change debate, including the relative contributions of human activities and natural processes, the extremely high potential costs of extensive mitigation efforts, and the significant economic and social disruptions, which may result from a large-scale reduction in the use of fossil fuels. Still, Allegheny has taken the initiative to move forward by undertaking its own voluntary program and will continue to explore cost-effective opportunities to improve efficiency and performance. Allegheny signed a Memorandum of Understanding with the DOE in 1995 to participate in the Climate Challenge. As part of this agreement, Allegheny supports the Climate Challenge Initiatives in cooperation with other companies through EEI. The ultimate outcome of the global climate change debate and the Kyoto Protocol could have a significant effect on the industry in general and on Allegheny in particular.

     Allegheny also participates in an active climate-related research program and is responsive to the voluntary guidelines suggested in the national Energy Policy Act of 1992, under Section 1605(b) directed toward reducing, controlling, avoiding and sequestering greenhouse gases. Allegheny has taken steps to reduce greenhouse gases and help stimulate a business climate that encourages improved efficiency, performance, electrical loss reductions and cost effectiveness.

     Under the National Pollutant Discharge Elimination System (NPDES), permits for all of Allegheny's stations and disposal sites are in place and all facilities are compliant with all permit terms, conditions and effluent limitations. However, as permits are renewed, more stringent permit limitations are often applied. Thus far Allegheny has either successfully developed and scientifically justified, to the satisfaction of the regulatory agencies, alternate site-specific water quality criteria or has installed passive constructed wetland treatment technology, thus avoiding significant capital costs and potential liabilities of advanced wastewater treatment.

     However, there is significant activity at the Federal level on Clean Water Act (CWA) issues. There are pending rulemakings, for example, regarding the Total Maximum Daily Load (TMDL) program, water quality standards, antidegradation review, human health and aquatic life water quality criteria, and mixing zones and CWA Section 316(b) Cooling Water Intake Structure. In addition, the EPA is developing new policies concerning protection of endangered species under the CWA and imposition of new CWA requirements to address sediment and biological water quality criteria contamination. The outcome of these rulemakings will fundamentally change the traditional water quality management program from a chemical specific control of point sources to comprehensive and integrated watershed management. This regulatory shift will result in more restrictions on facility discharges as well as nonpoint source runoff resulting from land use practices such as agriculture and forestry and will ultimately address water quality impairment caused by atmospheric deposition.

     Over the past several years TMDLs have become a significant issue because of successful legal challenges to the EPA's treatment of TMDLs under the CWA in various states. Resulting consent orders in West Virginia and Pennsylvania require development and implementation of waste loads for point sources and load allocations for nonpoint sources on numerous water bodies not currently meeting water quality standards within a relatively short time frame (twelve years). Because of the scientific complexity of the issue, paucity of water quality data, the resource limitations of the state agencies as well as political considerations, it is likely that resulting TMDLs will require a disproportionate reduction in point source versus nonpoint source discharges. The direct result of the TMDLs will be further reductions in the amount of pollutants permitted to be discharged by Allegheny-owned power stations located on water

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

     In January 2001 the Bush Administration remanded the rule to EPA for reconsideration. On June 15, 2001 the National Academy of Sciences released a report requested by Congress that recommended a number of changes to EPA's TMDL program. As a result, the EPA has proposed to delay by 18 months the effective date of the rule (April 2003) and to revise the date on which the states are required to submit their next list of impaired waters from April 1, 2002 to October 1, 2002. In the interim, the EPA has undertaken an open and active solicitation of stakeholder input and plans to re-propose the TMDL rule in October, 2002. It is likely that water quality trading provisions will be incorporated into the rule as an innovative means to assist states in more cost-effectively implementing TMDLs. The full effect of the rule on Allegheny and its customers will not be known until the final rule is promulgated and the states complete TMDL development and implementation on impaired waters over the next 15 years. In the meantime the states continue to develop TMDLs under the existing rule and in response Allegheny is proactively working with a number of watershed TMDL stakeholder groups, state agencies and the EPA to ensure development of sound and equitable TMDLs.

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

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

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

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

     The Phase 1 new facility rule applies to all new generation that begins construction after January 18, 2002. It requires cooling towers for all new power plants in addition to limits on intake velocity, percentage of the waterbody used, and, in most cases, additional intake screens or other protective measures largely unspecified but probably including fine-mesh screens, wedgewire screens or fabric barriers along with extensive site-specific study and monitoring requirements. If the proposal stands, new facilities will suffer severe siting restrictions, and will be subject to costly environmental studies and time delays to accomplish the studies. Moreover, the precedent-setting impact the new facility rule would

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

     After significant political debate the EPA lowered the maximum contaminant level (MCL) drinking water standard for arsenic from 50 to 10 ug/l to become effective February 2002. Because arsenic is a naturally occurring trace element present in the earth's crust as well as in coal and coal combustion products and because MCL's are used in other regulatory programs (such as groundwater protection, hazardous waste classification and brownfield cleanup programs) there is potential that Allegheny may incur increased compliance costs as these regulatory programs adopt the new standard. The full effect of this action on Allegheny will not be known until it is determined how the various federal and or state regulatory programs implement the new standard.

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

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

     In addition to using coal combustion by-products (CCBs) in various power plant applications such as scrubber by-product stabilization at the Harrison and Mitchell Power Stations, AE Supply on its own behalf and on behalf of Monongahela (the only Distribution Company still owning generation), continues to expand its efforts to market CCBs for beneficial applications and thereby reduce landfill requirements. In 2001, AE Supply and Monongahela received approximately $1,150,000 from the external sale and utilization of approximately 650,000 tons of fly ash, 260,000 tons of bottom ash and 23,000 tons of boiler slag, and 510,000 tons of flue-gas desulfurization (FGD) material. These CCBs were beneficially used in applications such as cement replacement in ready-mix concrete, anti-skid materials, grit blasting material, mine reclamation, mine subsidence, structural fills, synthetic gypsum for wallboard production, and grouting of mines and oil wells.

     AE Supply and Monongahela completed the construction of a processing plant that converts the flue-gas desulfurization by-product from the Pleasants Power Station into a commercial grade synthetic gypsum material to be used in the manufacture of wallboard. This process has significantly reduced the amount of the by-product going to an impoundment. The processing plant went into commercial production in 2000. Production problems have limited the quantity of gypsum produced to well below

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     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.)

     Allegheny is subject to the broad jurisdiction of the SEC under PUHCA. The Distribution Companies are regulated as to substantially all of their operations by regulatory commissions in the states in which they operate. These companies and AE Supply's unregulated generation are also regulated as to various aspects of their business by the FERC. In addition, they are subject to numerous other local, state, and federal laws, regulations, and rules.

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

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

     Substantially all of the properties of Monongahela and Potomac Edison are held subject to the lien of indentures securing their first mortgage bonds. In many cases, the properties of Monongahela, Potomac Edison, West Penn and AE Supply may be subject to certain reservations, minor encumbrances, and title defects which do not materially interfere with their use. Some of the properties are also subject to a second lien securing certain solid waste disposal and pollution control notes. The indenture under which AGC's unsecured debentures and medium-term notes are issued prohibits AGC, with certain limited exceptions, from incurring or permitting liens to exist on any of its properties or assets unless the debentures and medium-term notes are contemporaneously secured equally and ratably with all other

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     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.

     As of February 15, 2002, Monongahela has been named as a defendant along with multiple other defendants in a total of 8,266 pending asbestos cases involving one or more plaintiffs. Potomac Edison and West Penn have been named as defendants along with multiple other defendants in approximately one-half of those cases. Because these cases are filed in a "shotgun" format wherein multiple plaintiffs file claims against multiple defendants in the same case, it is presently impossible to determine the actual number of cases in which plaintiffs make claims against the Distribution Companies. However, based upon past experience and available data, it may be estimated that about one-third of the total number of cases filed actually involve claims against any or all of the Distribution Companies. All complaints allege that the plaintiffs sustained unspecified injuries resulting from claimed exposure to asbestos in various generating plants and other industrial facilities operated by the various defendants, although all plaintiffs do not claim exposure at facilities operated by all defendants. With very few exceptions, plaintiffs claiming exposure at stations operated by the Distribution Companies were employed by third-party contractors, not by the Distribution Companies. Three plaintiffs are known to be either present or former employees of Monongahela. Each plaintiff generally seeks compensatory and punitive damages against all defendants in amounts of up to $1 million and $3 million, respectively; in those cases which include a spousal claim for loss of consortium damages are generally sought against all defendants in an amount of up to an additional $1 million. A total of 1,475 cases have been previously settled and/or dismissed against Monongahela for an amount substantially less than the anticipated cost of defense. While the Distribution Companies believe that all of the cases are without merit, they cannot predict the outcome nor are they able to determine whether additional cases will be filed.

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

     On March 4, 1994, the Distribution Companies received notice that the EPA had identified them as

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     On October 1, 1996, Potomac Edison received a questionnaire from the EPA concerning a release or threat of release of hazardous substances, pollutants, or contaminants into the environment at the Butler Tunnel Site located in Luzerne County, Pa. Potomac Edison notified the EPA that it has no records or recollection of any business relations with the site or any of the companies identified in the questionnaire. It is not possible to determine at this time what effect, if any, this matter may have on Potomac Edison.

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

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

     On August 2, 2000, AE received a letter from the EPA requiring it to provide certain information on the following ten electric generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and Monongahela own these electric generating stations. The letter requested information under Section 114 of the federal Clean Air Act to determine compliance with federal Clean Air Act and state implementation plan requirements, including potential application of the new source performance standards, which can require the installation of additional air pollution control equipment upon the major modification of an existing facility. Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in some cases. AE believes its subsidiaries' generating facilities have been operated in accordance with the Clean Air Act and the rules implementing that Act. The experience of other utilities, however, suggests that in recent years, the EPA may have revised its interpretation of the rules regarding the determination of whether an action at a facility constitutes routine maintenance, which would not trigger the requirements of the new source performance standards, or a major modification of

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     In June 2000, Monongahela was contacted by the U.S. Environmental Protection Agency (EPA) and the Environmental Enforcement Section of the Department of Justice (DOJ) concerning the release of approximately 19,000 gallons of non-PCB oil to the environment, following the catastrophic failure of a 500 MVA, 265 kV transformer on April 11, 1998, at Monongahela's Belmont substation. Monongahela informed the EPA and the DOJ that it responded to this release immediately, thereby preventing any of the oil from reaching major waterways. Monongahela also informed the federal agencies that it has been working in conjunction with West Virginia Division of Environmental Protection regarding site cleanup and remediation. Monongahela reached an agreement with the EPA through the DOJ resolving the agency's concerns in November of 2001, and the United States District Court for the Northern District of West Virginia accepted the consent decree, which the parties entered in February 2002. Monongahela agreed to install additional piping, automatic valves and pumps at the substation to prevent any oil which may leak from the equipment from leaving the property. In addition, Monongahela agreed to pay a civil penalty in the amount of $252,000.

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

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

     On March 19, 2002, the Attorney General of the State of California filed a complaint with the FERC alleging that various named and unnamed sellers of electric energy in California violated the Federal Power Act by failing properly to file with the FERC the terms of their short-term power sales to the California Independent System Operator, the California Power Exchange and the CDWR. The complaint

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