SECURITIES AND EXCHANGE COMMISSION
                                  Washington, D.C.  20549         
                                          FORM 10-K

                          ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                         THE SECURITIES EXCHANGE ACT OF 1934 (Fee Required)   
  
                           For the fiscal year ended December 31, 1994

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

  1-267                    ALLEGHENY POWER SYSTEM, INC.             13-5531602
                           (A Maryland Corporation)
                           12 East 49th Street
                           New York, New York  10017
                           Telephone (212) 752-2121

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

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

  1-255-2                  WEST PENN POWER COMPANY                   13-5480882
                           (A Pennsylvania Corporation)
                           800 Cabin Hill Drive
                           Greensburg, Pennsylvania  15601
                           Telephone (412) 837-3000

  0-14688                  ALLEGHENY GENERATING COMPANY              13-3079675
                           (A Virginia Corporation)
                           12 East 49th Street
                           New York, New York  10017
                           Telephone (212) 752-2121

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

Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K (Section 229.405 of this chapter) is
not contained herein, and will not be contained, to the best of
registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. [X]

Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Registrant Title of each class on which registered Allegheny Power Common Stock, New York Stock Exchange System, Inc. $1.25 par value Chicago Stock Exchange Pacific Stock Exchange Amsterdam Stock Exchange Monongahela Power Cumulative Preferred Company Stock, $100 par value: 4.40% American Stock Exchange 4.50%, Series C American Stock Exchange The Potomac Edison Cumulative Preferred Company Stock, $100 par value: 3.60% Philadelphia Stock Exchange, Inc. $5.88, Series C Philadelphia Stock Exchange, Inc. West Penn Power Cumulative Preferred Company Stock, $100 par value: 4-1/2% New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Allegheny Generating Common Stock Company $1.00 par value None Aggregate market value Number of shares of voting stock (common stock) of common stock held by nonaffiliates of of the registrants the registrants at outstanding at February 2, 1995 February 2, 1995 Allegheny Power System, Inc. $2,818,296,038 119,292,954 ($1.25 par value) Monongahela Power Company None. (a) 5,891,000 ($50 par value) The Potomac Edison Company None. (a) 22,385,000 (no par value) West Penn Power Company None. (a) 24,361,586 (no par value) Allegheny Generating Company None. (b) 1,000 ($1.00 par value) (a) All such common stock is held by Allegheny Power System, Inc., the parent Company. (b) All such common stock is held by its parents, Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company.

CONTENTS PART I: Page ITEM 1. Business 1 Competition 3 Sales 4 Electric Facilities 8 System Map 11 Research and Development 13 Construction and Financing 14 Fuel Supply 18 Rate Matters 19 Environmental Matters 22 Air Standards Water Standards Hazardous and Solid Wastes Emerging Environmental Issues Regulation ITEM 2. Properties ITEM 3. Legal Proceedings ITEM 4. Submission of Matters to a Vote of Security Holders Executive Officers of the Registrants PART II: ITEM 5. Market for the Registrants' Common Equity and Related Stockholder Matters ITEM 6. Selected Financial Data ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ITEM 8. Financial Statements and Supplementary Data

CONTENTS (Cont'd) Page ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure PART III: ITEM 10. Directors and Executive Officers of the Registrants ITEM 11. Executive Compensation ITEM 12. Security Ownership of Certain Beneficial Owners and Management ITEM 13. Certain Relationships and Related Transactions PART IV: ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY POWER SYSTEM, 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 Power System, Inc. (APS), incorporated in Maryland in 1925, is an electric utility holding company which owns various subsidiaries (collectively, the APS System). APS derives substantially all of its income from the electric utility operations of its direct and indirect subsidiaries, Monongahela Power Company (Monongahela), The Potomac Edison Company (Potomac Edison), West Penn Power Company (West Penn), and Allegheny Generating Company (AGC) (collectively, the Subsidiaries). The properties of the Subsidiaries are located in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia, are interconnected, and are operated as a single integrated electric utility system (System), which is interconnected with all neighboring utility systems. The three electric utility operating Subsidiaries are Monongahela, Potomac Edison, and West Penn (Operating Subsidiaries). APS has no employees. Its officers are employed by Allegheny Power Service Corporation (APSC), a wholly-owned subsidiary of APS. On December 31, 1994, the APS System had 6,061 employees. Monongahela, incorporated in Ohio in 1924, operates in northern West Virginia and an adjacent portion of Ohio. It also owns generating capacity in Pennsylvania. Monongahela serves about 343,900 customers in a service area of about 11,900 square miles with a population of about 710,000. The seven largest communities served have populations ranging from 10,900 to 33,900. On December 31, 1994, Monongahela had 1,982 employees. Its service area has navigable waterways and substantial deposits of bituminous coal, glass sand, natural gas, rock salt, and other natural resources. Its service area's principal industries produce coal, chemicals, iron and steel, fabricated products, wood products, and glass. There are two municipal electric distribution systems and two rural electric cooperative associations in its service area. Except for one of the cooperatives, they purchase all of their power from Monongahela. Potomac Edison, incorporated in Maryland in 1923 and in Virginia in 1974, operates in portions of Maryland, Virginia, and West Virginia. It also owns generating capacity in Pennsylvania. Potomac Edison serves about 361,400 customers in a service area of about 7,300 square miles with a population of about 782,000. The six largest communities served have populations ranging from 11,900 to 40,100. On December 31, 1994, Potomac Edison had 1,137 employees. Its service area is generally rural. Its 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 purchase power from Potomac Edison, and six rural electric

cooperatives, one of which purchases power from Potomac Edison. There are also several large federal government installations served by Potomac Edison. West Penn, incorporated in Pennsylvania in 1916, operates in southwestern and north and south central Pennsylvania. It also owns generating capacity in West Virginia. West Penn serves about 653,000 customers in a service area of about 9,900 square miles with a population of about 1,399,000. The 10 largest communities served have populations ranging from 11,200 to 38,900. On December 31, 1994, West Penn had 2,053 employees. Its 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. There are two municipal electric distribution systems in its service area, which purchase their power requirements from West Penn, and five rural electric cooperative associations, located partly within the area, which purchase virtually all of their power through a pool supplied by West Penn and other nonaffiliated utilities. AGC, organized in 1981 under the laws of Virginia, is jointly owned by the Operating Subsidiaries as follows: Monongahela, 27%; Potomac Edison, 28%; and West Penn, 45%. 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 three parents. The remaining 60% interest in the Bath County Station is owned by Virginia Electric and Power Company (Virginia Power). AYP Capital, Inc. (AYP Capital), incorporated in Delaware in 1994, is an unregulated, wholly-owned nonutility subsidiary of APS. AYP Capital was formed in an effort to meet the challenges of the new competitive environment in the industry. APS has been authorized by the Securities and Exchange Commission to purchase common stock of and make capital contributions to AYP Capital in the amount of $3 million. AYP Capital has no employees. Its officers are employed by APSC. APSC is providing certain services to AYP Capital pursuant to a service agreement. The Subsidiaries in the past have experienced and in the future may experience some of the more significant problems common to electric utilities in general. These include increases in operating and other expenses, difficulties in obtaining adequate and timely rate relief, restrictions on construction and operation of facilities due to regulatory requirements and environmental and health considerations, including the requirements of the Clean Air Act Amendments of 1990 (CAAA), which among other things, require a substantial annual reduction in emissions of sulfur dioxides (SO2) and nitrogen oxides (NOx). Additional concerns include proposals to restructure and, to some extent, deregulate portions of the industry and increase competition. (See ITEM 1. COMPETITION.) Further concerns of the industry include possible restrictions on carbon dioxide emissions, uncertainties in demand due to economic conditions, energy

conservation, market competition, weather, and interruptions in fuel supply because of weather. (See ITEM 1. CONSTRUCTION AND FINANCING, RATE MATTERS, and ENVIRONMENTAL MATTERS for information concerning the effect on the Subsidiaries of the CAAA.) COMPETITION Following the steps of other previously regulated industries such as airlines, telecommunications and gas, there is a movement to deregulate or at least allow competition, limited or otherwise, in the electric utility industry. The passage of the National Energy Policy Act of 1992 (EPACT) has permitted an increase in competition by allowing the formation of Exempt Wholesale Generators (EWGs), with the approval of the Federal Energy Regulatory Commission (FERC), and by providing for mandatory access to the interconnected electric grid for wholesale transactions. It further provides for expansion of the grid where constraints are determined to exist, providing necessary authority to construct such facilities can be obtained and the requestor's rate for such transmission service reflects expansion costs. EPACT permits utility generation facilities to qualify as EWGs and allows sales to nonaffiliated and to affiliated utilities provided state commissions approve such transactions. (See ITEM 1. SALES and REGULATION for a further discussion of the impact of EPACT.) Maryland, Ohio, and Pennsylvania have initiated investigations concerning competition in the retail electric utility industry and promoting increased competitive options. (See ITEM 1. REGULATION for a further discussion of the states' initiatives.) To meet the challenges of the new competitive environment in the industry, AYP Capital was formed in 1994. It is intended that AYP Capital operate as an innovative and flexible organization, pursuing and developing new opportunities in unregulated markets that will strengthen the long-term competitiveness and profitability of APS. The business opportunities which are pursued by AYP Capital will be directly related to the core utility business of APS. Management may consider establishing or acquiring its own EWGs or other nonregulated generation facilities, if feasible, and management continues to evaluate other nonregulated opportunities to meet the competitive challenge. To further meet the challenges of the new competitive environment in the industry, management has begun to simplify the structure of the APS System to increase efficient operation. In addition, APS, along with the other registered electric public utility holding companies under the Public Utility Holding Company Act of 1935 (PUHCA), is advocating repeal of PUHCA which is an impediment to allowing the APS System to compete on a level playing field in the new era of competition. In the alternative, restructuring of the APS System to reduce or eliminate the effect of PUHCA is being considered. In addition, management continues to explore methods of marketing and pricing its core product - electric energy and the transmission thereof - in new and competitive ways, such as bulk

sales to power marketers, incentive pricing to traditional utility customers, and repackaging of services in nontraditional ways. It is also attempting to reduce costs, particularly capital expenditures, in order to position the APS System in a more competitive mode. The feasibility of maintaining these reduced levels in the future will depend upon, among other things, (1) the ability to maintain adequate levels of reliable service, (2) the avoidance of unexpected major equipment failures and (3) no changes in the timing or requirements for regulatory compliance measures. SALES In 1994, consolidated kilowatt-hour (kWh) sales to the Operating Subsidiaries' retail customers increased 2.8% from those of 1993 as a result of increases of .9%, 2.2% and 4.4% in residential, commercial and industrial sales, respectively. The increased kWh sales in 1994 reflect both growth in number of customers and higher use. Consolidated revenues from residential, commercial, and industrial sales increased 5.5%, 6.8%, and 8.1%, respectively, primarily because of rate increases (See ITEM 1. RATE MATTERS), increases in fuel and energy cost adjustment clause revenues, and increased kWh sales. Consolidated kWh sales to and revenues from nonaffiliated utilities decreased 20.0% and 4.4%, respectively, due to increased native load, decreased demand, and price competition. The System's all-time peak load of 7,280 MW, which was higher than the forecast, occurred on February 6, 1995. The peak load in 1994 and 1993 was 7,153 MW and 6,678 MW, respectively. The increased 1994 peak would have been higher except for voluntary conservation efforts by the Operating Subsidiaries' customers. The average System load (yearly net power supply divided by number of hours in the year) was 4,776 MW and 4,674 MW in 1994 and 1993, respectively. More information concerning sales may be found in the statistical sections and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Consolidated electric operating revenues for 1994 were derived as follows: Pennsylvania, 44.5%; West Virginia, 28.0%; Maryland, 20.5%; Virginia, 5.4%; Ohio, 1.6% (residential, 35.2%; commercial, 18.8%; industrial, 29.7%; nonaffiliated utilities, 13.5%; and other, 2.8%). The following percentages of such revenues were derived from these industries: iron and steel, 6.0%; chemicals, 3.4%; fabricated products,3.4%; aluminum and other nonferrous metals, 3.3%; coal mines, 3.2%; cement, 1.9%; and all other industries, 8.5%. Revenues from each of 17 industrial customers exceeded $5 million, including one coal customer of both Monongahela and West Penn with total revenues exceeding $22 million, three steel customers with revenues exceeding $27 million each, and one aluminum customer with revenues exceeding $68 million. During 1994, Monongahela's kWh sales to retail customers increased 3.2% as a net result of increases of 1.2% and 6.1% in commercial and industrial sales, respectively, and a decrease of

.6% in residential sales. Revenues from residential, commercial and industrial customers increased 3.1%, 4.9% and 7.7%, respectively, and revenues from kWh sales to affiliated and nonaffiliated utilities increased 6.8%. Monongahela's all-time peak load of 1,694 MW occurred on July 20, 1994. Monongahela's electric operating revenues were derived as follows: West Virginia, 94.3% and Ohio, 5.7% (residential, 28.1%; commercial, 17.1%; industrial, 29.7%; nonaffiliated utilities, 11.7%; and other, 13.4%). Revenues from each of five industrial customers exceeded $10 million, including one coal customer with revenues exceeding $19 million and one steel customer with revenues exceeding $27 million. During 1994, Potomac Edison's kWh sales to retail customers increased 2.3% as a result of increases of 1.7%, 2.1%, and 2.8% in residential, commercial, and industrial sales, respectively. Revenues from such customers increased 7.9%, 9.0%, and 10.9%, respectively, and revenues from kWh sales to affiliated and nonaffiliated utilities decreased 1.0%. Potomac Edison's all-time peak load of 2,595 MW occurred on January 19, 1994. Potomac Edison's electric operating revenues were derived as follows: Maryland, 66.6%; Virginia 16.8% and West Virginia, 16.6%; (residential, 39.0%; commercial, 17.9%; industrial, 25.7%; nonaffiliated utilities, 14.1%; and other, 3.3%). Revenues from one industrial customer, the Eastalco aluminum reduction plant near Frederick, Maryland, amounted to $68 million (9.0% of total electric operating revenues). Minimum annual charges to Eastalco under an electric service agreement which continues through March 31, 2000, with automatic extensions thereafter unless terminated on notice by either party, were $19.7 million in 1994. Said agreement may be cancelled before the year 2000 upon 90 days notice of a governmental decision resulting in a material modification of the agreement. During 1994, West Penn's kWh sales to retail customers increased 2.9% as a result of increases of 1.1%, 2.9% and 4.4% in residential, commercial, and industrial sales, respectively. Revenues from residential, commercial, and industrial customers increased 5.0%, 6.4%, and 6.7%, respectively, and revenues from kWh sales to affiliated and nonaffiliated utilities decreased 5.7%. West Penn's all-time peak load of 3,179 MW occurred on February 6, 1995. West Penn's electric operating revenues were derived as follows: Pennsylvania, 100% (residential, 33.4%; commercial, 18.4%; industrial, 29.3%; nonaffiliated utilities, 12.8%; and other, 6.1%). Revenues from each of four industrial customers exceeded $10 million, including two steel customers with revenues exceeding $32 million each. On average, the Operating Subsidiaries are the lowest or among the lowest cost suppliers of electricity in their respective states with fixed costs being extremely low and incremental costs being about average. Therefore, the Operating Subsidiaries' delivered power prices should compete favorably with those of potential alternate suppliers who use cost-based pricing. However,

the Operating Subsidiaries face increased competition from utilities with excess generation that are willing to sell at prices intended only to cover variable costs. At the same time, the Operating Subsidiaries are experiencing cost increases due to compliance with the CAAA and purchases from Public Utility Regulatory Policies Act of 1978 (PURPA) projects. (See page 7 for a discussion of PURPA projects, and ITEM 3. LEGAL PROCEEDINGS for a description of litigation and regulatory proceedings concerning PURPA capacity.) In 1994, the Operating Subsidiaries provided approximately 10.5 billion kWh of energy to nonaffiliated utility companies, of which 1.1 billion kWh were generated by the Subsidiaries and the rest were transmitted from electric systems located primarily to the west. These sales included a long-term transaction under which the Operating Subsidiaries purchased 450 MW of firm capacity and its associated energy from Ohio Edison Company for resale to Potomac Electric Power Company, both nonaffiliated utilities. The transaction began in mid-1987 and will continue through 2005, unless terminated earlier. Sales to nonaffiliated utility companies vary with the needs of those companies for imported power; the availability of System generating facilities and excess power, fuel, and regional transmission facilities; and the availability and price of competitive sources of power. Sales of system generated power decreased in 1994 relative to 1993 primarily because of continued decreased demand, increased Operating Subsidiaries' native load, and increased willingness of other suppliers to make sales at lower prices. Further decreases in sales of system generated power to nonaffiliated utilities are expected in 1995 and beyond. Substantially all of the revenues from kWh sales to nonaffiliated utilities are passed on to retail customers and as a result have little effect on net income. Pursuant to a peak diversity exchange arrangement with Virginia Power which is projected to continue through February 2008, the Operating Subsidiaries annually supply Virginia Power with 200 MW during each June, July, and August and in return Virginia Power supplies the Operating Subsidiaries with 200 MW during each December, January, and February, at least through February 1998. Thereafter, specific amounts of annual diversity exchanges beyond those currently established are to be mutually determined no less than 34 months prior to each year for which an exchange is to take place. The total number of megawatt-hours (MWh) to be delivered by each utility to the other over the term of the arrangement is expected to be the same. Pursuant to an exchange arrangement with Duquesne Light Company (Duquesne) which will continue through February 1996 and may be extended through 1999 and beyond, the Operating Subsidiaries supply Duquesne with up to 200 MW for a specified number of weeks, generally during each March, April, May, September, October, and November. In return, Duquesne supplies the Operating Subsidiaries with up to 100 MW, generally during each December, January, and February. The total number of MWh to be delivered by each utility to the other over the term of the arrangement is expected to be the same.

West Penn supplies power to the Borough of Tarentum (Tarentum) using in part leased distribution facilities from Tarentum under a 30 year lease agreement terminating in 1996. In June 1993, Tarentum, which in that year had a load of 6.5 MW and revenues of $1.8 million, notified West Penn of its intention to exercise its option to end the lease agreement. The termination of the lease agreement and resulting transfer and sale of electric facilities will result in Tarentum becoming a municipal customer which will purchase electricity on a wholesale basis from West Penn or another supplier. The sale of electric facilities will require Pennsylvania Public Utility Commission (Pennsylvania PUC) approval. The Operating Subsidiaries provide wholesale transmission services under their FERC-approved Standard Transmission Service tariff. The tariff provides that such service is subordinate in priority to native load and reliability requirements of interconnected systems to avoid adverse effects on regional and Operating Subsidiaries' reliability. (See ITEM 1. ELECTRIC FACILITIES for a discussion of stress on the System's transmission system.) Transmission services requiring special arrangements or long-term commitments have been and continue to be negotiated through mutually acceptable bilateral agreements. Substantially all of the revenues from transmission service sales are passed on to retail customers and as a result have little effect on net income. In addition, the Operating Subsidiaries have pending before the FERC a Standard Generation Service Rate Schedule tariff under which the Operating Subsidiaries will make available bundled, non-firm generation services with associated System transmission services to any customer who executes an agreement under such tariff. Sales subject to refund under the proposed tariff have been initiated. EPACT permits wholesale generators, utility-owned and otherwise, and wholesale consumers to request from owners of bulk power transmission facilities a commitment to supply transmission services. The FERC recently completed a generic investigation into the pricing of such requested transmission services. The FERC has chosen to maintain existing methods while offering limited opportunities to implement new methodologies which transmitting companies may wish to use if they find those methods to be beneficial. The potential for FERC's new pricing guidelines to be beneficial or detrimental to the Operating Subsidiaries cannot be predicted at this time. In addition, the FERC is continuing to develop new policies and procedures to further implement EPACT, including seeking comments to a Notice of Proposed Rulemaking on stranded costs and an Inquiry concerning alternative power pooling arrangements and in a recent case, has expanded the definition of nondiscriminatory service to require a utility to provide transmission service comparable to the service it provides itself. (See ITEM 3. LEGAL PROCEEDINGS for a discussion of the FERC proceeding wherein Duquesne has requested firm transmission service over the System's transmission facilities). Under EPACT, consumers of wholesale power including small electric systems owned by municipalities and rural electric cooperative associations may purchase power from any available source and may seek an order from the FERC for transmission service from any utility. Small electric wholesale customers in the

Operating Subsidiaries' service areas which do not have long term contracts may choose to avail themselves of this option. The Operating Subsidiaries will attempt to retain these customers. Under PURPA, certain municipalities and private developers have installed, are installing or are proposing to install hydroelectric and other generating facilities at various locations in or near the Operating Subsidiaries' service areas with the intent of selling some or all of the electric capacity and energy to the Operating Subsidiaries at rates provided under PURPA and ordered by appropriate state commissions. The System's total generation capacity includes a maximum 299 MW of on-line PURPA capacity. Payments for PURPA capacity and energy in 1994 totaled approximately $134 million at an average cost to the System of 5.8 cents/kWh as compared to System cost of about 3 cents/kWh. The Operating Subsidiaries anticipate an additional 260 MW of PURPA capacity to come on-line in future years, up from 180 MW. This increase is due to a litigated PURPA project which had lapsed being reincluded in the planning process although litigation is ongoing. In addition, lapsed purchase agreements totaling 123 MW and other PURPA complaints totaling 520 MW are the subject of ongoing litigation and are not included in the System's current planning strategy. (See ITEM 3. LEGAL PROCEEDINGS for a description of litigation and regulatory proceedings in Pennsylvania and West Virginia.) ELECTRIC FACILITIES The following table shows the System's December 31, 1994 generating capacity, based on the maximum monthly normal seasonal operating capacity of each unit. The System-owned capacity totaled 8,070 MW, of which 7,090 MW (88%) are coal-fired, 840 MW (10%) are pumped-storage, 82 MW (1%) are oil-fired, and 58 MW (1%) are hydroelectric. 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. The weighted average age of the System-owned coal-fired stations shown on the following page, based on generating capacity at December 31, 1994, was about 24.6 years. In 1994, their average heat rate was 9,927 Btu's/kWh, and their availability factor was 82.1%, down from 87% in 1993 due, in part, to planned outages for installation of pollution control equipment for compliance with the CAAA.

<TABLE> <CAPTION> System-Owned Stations Maximum Generating Capacity (Megawatts) (a) Dates When Station Monon- Potomac West Service Station Units Total gahela Edison Penn Commenced (b) Coal-fired: <S> <C> <C> <C> <C> <C> <C> Albright 3 292 216 76 1952-4 Armstrong 2 352 352 1958-9 Fort Martin 2 831 249 304 278 1967-8 Harrison 3 1,920 480 629 811 1972-4 Hatfield's Ferry 3 1,660 456 332 872 1969-71 Mitchell 1 284 284 1963 Pleasants 2 1,252 313 376 563 1979-80 Rivesville 2 142 142 1943-51 R. Paul Smith 2 114 114 1947-58 Willow Island 2 243 243 1949-60 Oil-Fired:(a) Mitchell 1 82 82 1948 Pumped-Storage and Hydro: Bath County 6 840 227(c) 235(c) 378(c) 1985 Lake Lynn(d) 4 52 52 1926 Potomac Edison(d) 21 6 6 Various Total System-Owned Capacity 54 8,070 2,326 2,072 3,672 Nonutility Generation Maximum Generating Capacity (Megawatts)(e) Contract Project Monon- Potomac West Commencement Project Total gahela Edison Penn Date Coal-fired AES Beaver Valley 125 125 1987 Grant Town 80 80 1993 West Virginia University 50 50 1992 Hydro Allegheny Lock and Dam 5 6 6 1988 Allegheny Lock and Dam 6 7 7 1989 Hannibal Lock and Dam 31 31 1988 Total Nonutility Capacity 299 161 0 138 Total Maximum System Generating Capacity (a) 8,369 2,487 2,072 3,810 (a) Excludes 207 MW of West Penn oil-fired capacity at Springdale Power Station and 77 MW of the total MW at Mitchell Power Station, which were placed on cold reserve status as of June 1, 1983. Current plans call for the reactivation of these units in about five years. On December 31, 1994, 82 MW of the total MW at Mitchell Power Station were reactivated. (b) Where more than one year is listed as a commencement date for a particular source, the dates refer to the years in which operations commenced for the different units at that source. (c) Capacity entitlement through percentage ownership of AGC. (d) The FERC issued a new license with a 30-year term for Lake Lynn on December 27, 1994. Certain terms of said license are being appealed but do not affect its validity. Potomac Edison's license for hydroelectric facilities Dam #4 and Dam #5 will expire in 2003. Potomac Edison has received 30-year licenses, effective January 1994, for the Shenandoah, Warren, Luray and Newport projects. The FERC accepted Potomac Edison's surrender of the license for the Harper's Ferry Dam No. 3 and issued an order effective October 1994. (e) Nonutility generating capacity available through contractual arrangements pursuant to PURPA. </TABLE>

SYSTEM MAP The Allegheny Power System Map (System Map), which has been omitted, provides a broad illustration of the names and approximate locations of the System's major generation and transmission facilities, both existing and under construction, in a five state region which includes portions of Pennsylvania, Ohio, West Virginia, Maryland and Virginia. Additionally, Extra High Voltage substations are displayed. By use of shading, the System Map also provides a general representation of the service areas of Monongahela (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 System 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, Springdale and Lake Lynn. The System Map also depicts transmission facilities which are (i) owned solely by the Operating Subsidiaries; (ii) owned by the Operating Subsidiaries in conjunction with other utilities; or (iii) owned solely by other utilities. The transmission facilities portrayed range in capacity from 138kV to 765kV. Additionally, interconnections with other utilities are displayed.

The following table sets forth the existing miles of tower and pole transmission and distribution lines and the number of substations of the Subsidiaries as of December 31, 1994: <TABLE> <CAPTION> Above Ground Transmission and Distribution Lines (a) and Substations Portion of Total Transmission and Representing Distribution Total 500-Kilovolt (kV) Lines Substations(b) <S> <C> <C> <C> Monongahela 19,794 283 225 Potomac Edison 17,296 202 203 West Penn 21,723 273 534 AGC(c) 85 85 1 Total System 58,898 843 963 (a) The System has a total of 5,506 miles of underground distribution lines. (b) The substations have an aggregate transformer capacity of 38,344,534 kilovoltamperes. (c) Total Bath County transmission lines, of which AGC owns an undivided 40% interest and Virginia Power owns the remainder. </TABLE> The System has 11 extra-high-voltage (345 kV and above) (EHV) and 29 lower-voltage interconnections with neighboring utility systems. The interregional EHV transmission system, including System facilities, historically has been negatively affected by frequent periods of heavy loading, predominantly in a west-to-east direction. In 1994, the west-to-east flows decreased from prior years due to lower interregional power transfers. However, increases in customer load, power transfers by the Operating Subsidiaries and nonaffiliated entities, and parallel flows may contribute to a possible resumption of the heavy west-to-east power flows. If power transfers return to the levels experienced during the late 1980s and early 1990s, the interregional EHV transmission facilities may operate at times at their reliability limit and therefore, despite recently installed reactive power sources, restrictions on transfers may again become necessary. Under certain provisions of EPACT, wholesale generators, and wholesale customers, may seek from owners of bulk power transmission facilities a commitment to supply transmission services. (See discussion under ITEM 1. SALES and REGULATION.) Such demand on the System's transmission facilities may add periodically to heavy power flows on the System's facilities. The Operating Subsidiaries have, to date, provided managed contractual access to the System's transmission facilities via the provisions of their Standard Transmission Service tariff, or the terms and conditions of bilateral contracts.

RESEARCH AND DEVELOPMENT The Operating Subsidiaries spent $7.7 million, $4.6 million, and $2.7 million in 1994, 1993 and 1992, respectively, for research programs. Of these amounts, $5.9 million, $3.2 million and $0.6 million were for Electric Power Research Institute (EPRI) dues in 1994, 1993 and 1992, respectively. EPRI is an industry-sponsored research and development institution. The Operating Subsidiaries plan to spend approximately $9.7 million for research in 1995, with EPRI dues representing $6.2 million of that total. Independent research conducted by Operating Subsidiaries concentrated on environmental protection (CAAA and permit mandates), generating unit performance, future generating technologies, delivery systems, and customer-related research. Clean power technology focused on power quality and load management devices and techniques for customer and delivery equipment. Two U.S. Department of Energy Clean Coal Technology NOx control projects, which the Operating Subsidiaries cofounded, have recently been completed. Based upon the results of one of the projects, retrofitting of low NOx cell burners on Hatfield Power Station units has been undertaken at much lower costs than would otherwise have been possible. Research is also being directed to help address major issues facing the Operating Subsidiaries including electric and magnetic field (EMF) assessment, waste disposal, greenhouse gas, client- server information system prospects, renewable resources, fuel cells, new combustion turbines and other cogeneration technologies. In addition, there is continuing evaluation of technical proposals from outside sources and monitoring of developments in literature, law, litigation and standards. Electric vehicle (EV) research included participation in the Ford Ecostar Demonstration Program, EV America and the Electric Transportation Coalition, as well as the development of appropriate wiring and building code standards to accommodate electric vehicles. With reference to alleged global climate change, a Memorandum of Understanding was signed on behalf of all Edison Electric Institute (EEI) companies by EEI and the Department of Energy (DOE) which contains Initiatives directed toward voluntary programs to reduce greenhouse gas emissions. In early February 1995, an individual agreement will be entered into on behalf of the Operating Subsidiaries and the DOE. The Operating Subsidiaries, in cooperation with the Pennsylvania Department of Environmental Resources and the West Virginia Division of Environmental Protection, are researching the feasibility and cost-effectiveness of injecting fly ash from the Operating Subsidiaries' power stations into abandoned underground

mine sites in Pennsylvania and West Virginia to reduce acid mine drainage and mine surface subsidence. The project cost is anticipated to be shared with EPRI as part of a Tailored Collaboration Agreement with the Institute. The Operating Subsidiaries also made research grants to regional colleges and universities to encourage the development of technical resources related to current and future utility problems. CONSTRUCTION AND FINANCING Construction expenditures by the Subsidiaries in 1994 amounted to $508 million and for 1995 and 1996 are expected to aggregate $341 million and $284 million, respectively. In 1994, these expenditures included $153 million for compliance with the CAAA. The 1995 and 1996 estimated expenditures include $61 million and $7 million, respectively, to cover the costs of compliance with the CAAA. Allowance for funds used during construction (AFUDC) (shown below) has been reduced for carrying charges on CAAA expenditures that are being collected through currently approved surcharges or in base rates.

<TABLE> <CAPTION> Construction Expenditures 1994 1995 1996 Millions of Dollars (Actual) (Estimated) Monongahela <S> <C> <C> <C> Generation $ 55.1 $ 28.3 $ 34.4 Transmission and Distribution 47.7 44.8 34.9 Other 1.2 1.3 1.2 Total* $ 104.0 $ 74.4 $ 70.5 Potomac Edison Generation $ 55.6 $ 31.3 $ 29.7 Transmission and Distribution 81.3 58.4 64.9 Other 5.9 2.6 3.6 Total* $ 142.8 $ 92.3 $ 98.2 West Penn Generation $ 169.6 $ 108.6 $ 58.1 Transmission and Distribution 74.4 57.7 50.0 Other 16.4 6.1 7.2 Total* $ 260.4 $ 172.4 $ 115.3 AGC Generation $ 1.0 $ 2.1 $ .5 Transmission and Distribution Other .1 - - Total $ 1.1 $ 2.1 $ .5 Total Construction Expenditures $ 508.3 $ 341.2 $ 284.5 * Includes allowance for funds used during construction for 1994, 1995 and 1996 of: Monongahela $2.9, $1.4 and $1.1; Potomac Edison $5.9, $2.1 and $1.8; and West Penn $10.8, $4.3 and $1.9. </TABLE> These construction expenditures include major capital projects at existing generating stations, including the construction of flue-gas desulfurization equipment (scrubbers) at the Harrison Power Station, upgrading distribution lines and substations, and the strengthening of the transmission and subtransmission systems. The Harrison scrubber project was completed on schedule and the scrubbers were declared available for service on November 16, 1994. The final cost is expected to be $555 million, which is approximately 24% below the original budget. Primary factors that contributed to the reduced cost were: a) the absence of any major construction problems; b) financing and material and equipment costs lower than expected; and c) favorable rulings of state commissions allowing the inclusion of carrying costs of construction in rates in lieu of AFUDC. On a collective basis for the Operating Subsidiaries, total expenditures for 1994, 1995, and 1996 include $190 million, $101

million, and $52 million, respectively, for construction of environmental control technology. Outages for construction, CAAA compliance work and other environmental work is and will continue to be coordinated with planned outages. The Operating Subsidiaries continue to study ways to reduce or meet future increases in customer demand, including aggressive demand- side management programs, new and efficient electric technologies, construction of various types and sizes of generating units and increasing the efficiency and availability of System generating facilities, reducing company electrical use and transmission and distribution losses, and where feasible and economical, acquisition of reliable, long-term capacity from other electric systems and from nonutility developers. The Operating Subsidiaries are implementing demand-side management activities. Potomac Edison and West Penn are engaged in state commission supported or ordered evaluations of demand-side management programs. (See ITEM 1. REGULATION for a further discussion of these programs.) Several jurisdictions have adopted mechanisms which provide for recovery of the costs of such activities, some return on the related investment, the associated revenue reductions and a performance incentive, either on a current basis or through deferral to a base rate case. Current forecasts, which reflect demand-side management efforts and other considerations and assume normal weather conditions, project both average annual winter and summer peak load growth rates of 1.59% in the period 1995-2005. After considering the reactivation of West Penn capacity in cold reserve (see page 10), peak diversity exchange arrangements described in ITEM 1. SALES above, demand-side management and conservation programs, and contracted PURPA capacity, it is anticipated that new System-owned generating capacity will not be required until the year 2000 or beyond. If future customer demand materially exceeds that forecast, anticipated supply-side resources do not become available, demand-side management efforts do not succeed, or in the event of extremely adverse weather conditions, the Operating Subsidiaries may be unable at times to meet all of their customers' requirements for electric service. In connection with their construction and demand-side management programs, the Operating Subsidiaries must make estimates of the availability and cost of capital as well as the future demands of their 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. As a result, future plans of the Operating Subsidiaries are subject to continuing review and substantial change. The Subsidiaries have financed their construction programs through internally generated funds, first mortgage bond, debenture,

medium-term note and preferred stock issues, pollution control and solid waste disposal notes, installment loans, long-term lease arrangements, equity investments by APS (or, in the case of AGC, by the Operating Subsidiaries), and, where necessary, interim short-term debt. Effective January 1994, the Operating Subsidiaries also have available a $300 million multi-year credit facility. The future ability of the Subsidiaries to finance their construction programs by these means depends on many factors, including creditworthiness, rate levels sufficient to provide internally generated funds and adequate revenues to produce a satisfactory return on the common equity portion of the Subsidiaries' capital structures and to support their issuance of senior and other securities. The creditworthiness of the Operating Subsidiaries in the future may be affected by increased concern of rating agencies that purchased power contracts are a risk factor deserving consideration. APS obtains most of the funds for equity investments in the Operating Subsidiaries through the issuance and sale of its common stock publicly and through its Dividend Reinvestment and Stock Purchase Plan and its Employee Stock Ownership and Savings Plan. In 1994, the Subsidiaries issued $225.3 million of securities having interest rates between 6.75% and 8.125%. In May 1994, Monongahela issued 500,000 shares of cumulative preferred stock (par value $100 per share) with a dividend rate of $7.73. In June 1994, Potomac Edison issued $75 million of 8% first mortgage bonds due 2024. In August 1994, West Penn issued $65 million of 8.125% first mortgage bonds due 2024, and Monongahela, Potomac Edison, and West Penn issued $8.825 million, $11.560 million, and $14.910 million, respectively, in solid waste disposal notes to Harrison County, West Virginia. Harrison County in turn issued $35.295 million of 6-3/4% tax-exempt 30-year solid waste disposal revenue bonds. The Operating Subsidiaries are using the proceeds from the issuance of their solid waste disposal notes to finance certain solid waste disposal facilities which comprise a portion of the scrubbers located at the Harrison Power Station. In 1994, APS sold 1,629,372 shares of its common stock for $35 million through its Dividend Reinvestment and Stock Purchase Plan and its Employee Stock Ownership and Savings Plan. In October 1994, West Penn issued and sold to APS 2,000,000 additional shares of common stock at a price of $20 per share. During 1994, the rate for West Penn's 400,000 shares of market auction preferred stock, par value $100 per share, reset approximately every 90 days at 2.52%, 3.09%, 3.59% and 4.28%. The rate set at auction on January 13, 1995, was 4.75%. At December 31, 1994, APS had $90.25 million outstanding in short-term debt, Monongahela had $39.5 million outstanding in short- term debt and notes payable to affiliates, and AGC had $41.74 million outstanding in commercial paper, while Potomac Edison and West Penn had notes receivable from an affiliate of $1.9 million and $1.0 million, respectively.

The Subsidiaries' ratios of earnings to fixed charges for the year ended December 31, 1994, were as follows: Monongahela, 3.33; Potomac Edison, 3.46; West Penn, 3.40; and AGC, 3.50. APS and the Subsidiaries' consolidated capitalization ratios as of December 31, 1994, were: common equity, 45.1%; preferred stock, 7.2%; and long-term debt, 47.7%. APS and the Subsidiaries' long-term objective is to maintain the common equity portion above 45%, reduce the long-term debt portion toward 45%, and maintain the preferred stock ratio for the balance of the capital structure. In January 1994, the Operating Subsidiaries jointly entered into an aggregate $300 million multi-year credit agreement with eighteen lenders. Each Operating Subsidiary's borrowings under the agreement are limited to its pro rata share of the stock of AGC, which stock was pledged to secure the credit agreement. The Operating Subsidiaries' percentage ownership of AGC and resulting borrowing limitations are: Monongahela 27%, $81,000,000; Potomac Edison 28%, $84,000,000; and West Penn 45%, $135,000,000. The agreement may be used as a supplement to or in lieu of public financings and short-term debt programs. During 1995, the Operating Subsidiaries anticipate meeting their capital requirements through a combination of internally generated funds, cash on hand, and short-term borrowing as necessary. The Operating Subsidiaries may engage in tax-exempt solid waste disposal financings during 1995 to the extent funds are available to Harrison County from the West Virginia cap allocation. APS plans to sell common stock through its Dividend Reinvestment and Stock Purchase Plan and Employee Stock Ownership and Savings Plan. The Operating Subsidiaries, if economic and market conditions make it desirable, may refund during 1995 up to $565 million of first mortgage bonds, up to $140 million of preferred stock, and up to $78 million of pollution control revenue notes through optional redemptions. FUEL SUPPLY System-operated stations burned approximately 15.8 million tons of coal in 1994. Of that amount, 69% was either cleaned (7.2 million tons) or used in stations equipped with scrubbers (3.6 million tons). Use of desulfurization equipment and cleaning and blending of coal make burning local higher-sulfur coal practical, and in 1994 about 97% of the coal received at System stations came from mines in West Virginia, Pennsylvania, Maryland, and Ohio. The Operating Subsidiaries do not mine or clean any coal. All raw, clean or washed coal is purchased from various suppliers as necessary to meet station requirements. Long-term arrangements, subject to price change, are in effect and will provide for approximately 12 million tons of coal in 1995. The Operating Subsidiaries will depend on short-term arrangements and spot purchases for their remaining requirements. Through the year 1999, the total coal requirements of present System-operated stations

are expected to be met with coal acquired under existing contracts or from known suppliers. The Operating Subsidiaries signed two 10-year lime supply agreements during 1994 which will provide for the long-term lime requirements of the System's scrubbers. The Operating Subsidiaries renegotiated several long-term coal contracts with Consolidation Coal Company effective January 1, 1995, resulting in reduced prices, the benefit of which will, for the most part, accrue to the Operating Subsidiaries' customers. For each of the years 1990 through 1993, the average cost per ton of coal burned was $35.97, $36.74, $36.31 and $36.19, respectively. For the year 1994, the cost per ton decreased to $35.88. In addition to using ash in various power plant applications such as sludge stabilization at Harrison and Mitchell Power Stations, the Operating Subsidiaries continue their efforts to market fly ash and bottom ash for beneficial uses and thereby reduce landfill requirements. (See ITEM 1. RESEARCH AND DEVELOPMENT.) In 1994, the Operating Subsidiaries received approximately $236,000 for the sale of 85,998 tons of fly ash and 64,511 tons of bottom ash for various uses including cement replacement, mine grouting, oil well grouting, soil extenders and anti-skid material. The Operating Subsidiaries own coal reserves estimated to contain about 125 million tons of high-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 Operating Subsidiaries plan to hold the reserves as a long-term resource. RATE MATTERS Rate case decisions in almost all jurisdictions were issued for the Operating Subsidiaries in 1994. West Penn On March 31, 1994, West Penn filed an application with the Pennsylvania PUC for a base rate increase designed to produce $80.1 million in additional annual revenues from its retail customers. This request included recovery of the remaining carrying charges on investment, depreciation, and all operating costs required to comply with Phase I of the CAAA, and other increasing levels of expense. West Penn filed a petition on January 12, 1994 with the Pennsylvania PUC requesting authorization to accrue post in-service carrying charges on the Harrison scrubbers and to defer related depreciation and operating and maintenance expenses until they were recognized in rates. This request was approved by the Pennsylvania PUC on May 4, 1994. By Pennsylvania PUC order adopted December 15, 1994, an annual increase of $55.5 million for West Penn's retail customers was authorized to become effective December 31, 1994. Included in this amount was an authorized return on equity (ROE) of 11.5%.

Monongahela On January 18, 1994, Monongahela filed an application with the Public Service Commission of West Virginia (West Virginia PSC) for a base rate increase designed to produce $61.3 million in additional annual revenues which includes recovery of the remaining carrying charges on investment, depreciation, and all operating costs required to comply with Phase I of the CAAA, and other increasing levels of expense. The West Virginia PSC, on November 9, 1994 affirmed the recommended decision of the Administrative Law Judge (ALJ) providing for a rate increase to be effective November 16, 1994 of $23.5 million of new money. This amount was in addition to $6.9 million of CAAA recovery granted effective July 1, 1994 to be transferred from fuel clause recovery to base rates. The $6.9 million was included in Monongahela's $61.3 million request. The decision reflects an ROE of 10.85%. The West Virginia PSC's order stated that it was affirming the ALJ's recommendation because of time constraints and invited all parties to file petitions for reconsideration. All parties have filed petitions and a decision from the West Virginia PSC is pending. In the meantime, Monongahela is collecting the new rates, which are not subject to refund. Monongahela cannot predict the outcome of the request for reconsideration. Because of procedural requirements of Ohio law, a rate case in Ohio in 1994 to request recovery of the cost of the Harrison scrubbers was not deemed practical. On January 31, 1995, Monongahela filed an application with the Public Utilities Commission of Ohio (Ohio PUC) for a base rate increase designed to produce $7.0 million in additional annual revenues which includes recovery of carrying charges on investment, depreciation, and all operating costs required to comply with Phase I of the CAAA, and other increasing levels of expense. The Ohio PUC approved Monongahela's petition of January 11, 1994 requesting authorization to accrue post in-service carrying charges on the Harrison scrubbers until its investment in such scrubbers is recognized in rates. That order also allows Monongahela to defer depreciation and operating and maintenance expenses, including property taxes (but not including fuel costs), with respect to the scrubbers. This accrual is included in the rate case filing. It is expected that the new rates will become effective in late 1995. Potomac Edison The Maryland Public Service Commission (Maryland PSC) issued a final order on September 20, 1994 approving a settlement agreement in Potomac Edison's base rate case authorizing an annual increase of $19.6 million effective November 11, 1994. The rate case filed by Potomac Edison on April 15, 1994 originally requested a $30.9 million increase. The authorized $19.6 million increase is in addition to $2.7 million of demand-side management costs which were included in Potomac Edison's original request but which were granted as a separate surcharge. The rate case increase includes recovery of the remaining carrying charges

on investment, depreciation, and all operating costs required to comply with Phase I of the CAAA, and other increasing levels of expense. On April 30, 1993 and June 22, 1994, Potomac Edison filed two rate cases with the Virginia State Corporation Commission (Virginia SCC) seeking a total increase of $12.5 million. The Virginia SCC granted an increase of $4.5 million effective September 28, 1993, based on the case filed April 30, 1993. In the case filed June 22, 1994, a settlement agreement was filed with the Hearing Examiner reflecting an additional increase of $3 million effective November 20, 1994. The settlement agreement has been accepted by the now pending before the Virginia SCC. On November 9, 1994, the West Virginia PSC affirmed the recommended decision of the ALJ providing for a rate increase effective November 11, 1994. The increase of $1.5 million is in addition to $1.9 million of CAAA recovery granted effective July 1, 1994 which was included in Potomac Edison's original request for $12.2 million filed January 14, 1994. The request included recovery of the appropriate costs to comply with Phase I of the CAAA as well as other increasing levels of expense. The decision reflects an ROE of 10.85%. The West Virginia PSC's order stated that it was affirming the ALJ's recommendation because of time constraints and invited all parties to file petitions for reconsideration. All parties have filed petitions and a decision from the West Virginia PSC is pending. In the meantime, Potomac Edison is collecting the new rates, which are not subject to refund. Potomac Edison cannot predict the outcome of the request for reconsideration. AGC Through February 29, 1992, AGC's ROE was adjusted annually pursuant to a settlement agreement approved by the FERC. In December 1991, AGC filed for a continuation of the existing ROE of 11.53% and other parties filed to reduce the ROE to 10%. Hearings were completed in June 1992, and a recommendation was issued by an ALJ on December 21, 1993, for an ROE of 10.83%, which the other parties argued should be further adjusted to reflect changes in capital market conditions since the hearings. Exceptions to this recommendation were filed by all parties for consideration by the FERC. On January 28, 1994, the Consumer Advocate Division of the West Virginia PSC, Maryland People's Counsel, and Pennsylvania Office of Consumer Advocate filed a joint complaint with the FERC against AGC claiming that both the existing ROE of 11.53% and the ROE recommended by the ALJ of 10.83% were unjust and unreasonable. This new complaint requested an ROE of 8.53% with rates subject to refund beginning April 1, 1994. Hearings were completed in November 1994 and a recommendation was issued by an ALJ on December 22, 1994 dismissing the Joint Consumer Advocates' complaint. A settlement agreement for both cases is currently pending, which would reduce AGC's ROE to 11.13% for the period from March 1, 1992 through December 31, 1994, and increase AGC's ROE to 11.20% for the period from January 1, 1995 through December 31, 1995. During 1995, the parties have agreed

to negotiate in good faith to approve a mechanism for setting ROE in the future. This settlement is subject to FERC approval. If approved, this settlement will require a refund to customers for the period through December 31, 1994, of about $4.42 million for which adequate reserves have been provided. Through a filing completed on October 31, 1994, AGC sought to add a prior tax payment of approximately $12 million to rate base which will produce about $1.4 million in additional annual revenues. On December 30, 1994, the FERC accepted AGC's filing, ordered that the increase in rates go into effect on June 1, 1995, subject to refund, and set AGC's ROE for hearing in 1995. A settlement agreement is currently pending. This settlement is subject to FERC approval. FERC In 1994, West Penn and Monongahela implemented settlement agreements covering wholesale rates in effect for their municipal, co- op, and borderline agreement customers subject to the jurisdiction of the FERC. Each included recovery of the remaining carrying charges on investment, depreciation, as well as all operating costs required to comply with Phase I of the CAAA, and other increasing levels of expense. The amounts of the increases were $2.1 million for West Penn and $300,000 for Monongahela, both effective December 1, 1994. On October 14, 1994, as supplemented on November 25, 1994, Potomac Edison filed a petition for a $3.8 million increase with the FERC. The request includes recovery of the remaining carrying charges on investment, depreciation, and all operating costs required to comply with Phase I of the CAAA, and other increasing levels of expense. By order dated January 18, 1995, the FERC accepted Potomac Edison's filing and set the matter for hearing. FERC also granted a request for summary disposition of one item which reduced Potomac Edison's request to $3.65 million. These new rates will go into effect on June 25, 1995, subject to refund. Potomac Edison cannot predict the outcome of this proceeding. ENVIRONMENTAL MATTERS The operations of the Subsidiaries 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. Meeting known environmental standards is estimated to cost the Subsidiaries about $217 million in capital expenditures over the next three years. Additional legislation or regulatory control requirements, if enacted, may require modifying, supplementing, or replacing equipment at existing stations at substantial additional cost.

Air Standards The Operating Subsidiaries meet applicable standards as to particulates and opacity at major stations with high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, and, at times, reduction of output. From time to time minor excursions of opacity normal to fossil fuel operations are experienced and are accommodated by the regulatory process. The West Virginia Division of Environmental Protection (WVDEP), Office of Air Quality (OAQ), issued Notices of Violation (NOVs) for opacity exceedances for the fourth quarter of 1993 and first quarter of 1994 at the Albright, Fort Martin, and Harrison Power Stations. An NOV was issued by OAQ for visual opacity exceedances on March 23, 1994 at Pleasants Power Station. The Operating Subsidiaries have submitted written responses to OAQ regarding the opacity exceedances and are awaiting a response. Because of the stringent 10% opacity limit in West Virginia which led to the above-mentioned NOVs, Monongahela and other West Virginia electric utilities petitioned the OAQ in 1994 to revise the opacity limit from 10% to 20% in order to be consistent with surrounding states and the federal New Source Performance Standards (NSPS). The OAQ on October 21, 1994 published a proposed revision to Title 45, Regulation 2 to increase the opacity limit to 20%. The final rule should be submitted to the state legislature in West Virginia for approval in 1995. The Operating Subsidiaries meet current emission standards as to 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 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 NOx from 1980 emission levels, to be completed in two phases, Phase I and Phase II. Five coal-fired System plants are affected in Phase I and the remaining plants or units reactivated in the future will be affected in Phase II. Installation of scrubbers at the Harrison Power Station was the strategy undertaken by the Operating Subsidiaries to meet the required SO2 emission reductions for Phase I (1995-1999). Continuing studies will determine the compliance strategy for Phase II (2000 and beyond). It is expected that burner modifications at possibly all System stations will satisfy the NOx emission reduction requirements for the acid rain (Title IV) provisions of the CAAA. Additional post-combustion controls may be mandated in Maryland and Pennsylvania for ozone nonattainment (Title I) reasons. Continuous emission monitoring equipment has been installed on all Phase I and Phase II units. Studies to evaluate cost effective options to comply with Phase II, including those which may be available from the use of Operating Subsidiaries' banked emission allowances and from the emission allowance trading market, are continuing. In a case brought by the electric utility industry which disputed the EPA's inclusion of overfire air equipment as well as low NOx burners

in its definition of "low NOx burner technology," the District of Columbia Circuit Court of Appeals on November 29, 1994 vacated and remanded to the EPA the Title IV NOx rule. As a result, the January 1, 1995 Phase I NOx compliance deadline under Title IV is no longer applicable. It is uncertain when a revised rule will be issued, whether the emission limits will be revised, and what the compliance deadline will be. Pursuant to an option in the CAAA and in order to avoid the potential for more stringent NOx limits in Phase II, the Operating Subsidiaries chose to treat Phase II Group 1 boilers (tangential and wall-fired) as Phase I affected units as of January 1, 1995. This was accomplished by activation of substitution unit plans for the seven Phase II Group 1 boilers. As a result of being Phase I affected, these units will also be required to comply with the Phase I SO2 limits. Phase I NOx and SO2 compliance for these units should not require additional capital or operating expenditures. Title I of the CAAA established an ozone transport region consisting of the District of Columbia and 11 northeast states including Maryland and Pennsylvania. Sources within the region will be required to reduce NOx emissions, a precursor of ozone, to a level conducive to attainment of the ozone national ambient air quality standard (NAAQS). The installation of reasonably available control technology (RACT) (overfire air equipment and/or low NOx burners) at all Pennsylvania and Maryland stations is expected to be completed by May 31, 1995. This is essentially compatible with Title IV NOx reduction requirements, prior to their remand. The Ozone Transport Commission (OTC) has determined that the Operating Subsidiaries may be required to make additional NOx reductions beyond RACT in order for the ozone transport region to meet the ozone NAAQS. Under terms of a Memorandum of Understanding (MOU), the Operating Subsidiaries' power stations located in Maryland and Pennsylvania will be required to reduce NOx emissions by 55% from the 1990 baseline emissions, with a compliance date of May 1999. Further reductions of 75% from the 1990 baseline may be required by May 2003, unless the results of modeling studies due to be completed by 1998, indicate otherwise. Both Maryland and Pennsylvania must promulgate regulations to implement the terms of the MOU. 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 (including bonus and extension allowances) may be sold or "banked" for future use or sale. Through an industry allowance pooling agreement, the Operating Subsidiaries will receive a total of approximately 554,000 bonus and extension allowances during Phase I. These allowances are in addition to the Table A allowances of approximately 356,000 per year during the Phase I years. Ownership of these allowances permits the Operating Subsidiaries to operate in compliance with Phase I, as well as postpone a decision on their compliance strategy for Phase II. As part of their compliance strategy, the Operating Subsidiaries continue to study the allowance

market to determine whether sales or purchases of allowances are appropriate. 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 status of Monongahela's Rivesville Station with the NAAQS 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 WVDEP in June 1993. Costs associated with the GEP stack are approximately $20 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 over $13 million with the expectation that 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, 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 EPA. In 1988, the Court dismissed West Penn's appeal stating it could not decide a case while West Penn's request for reconsideration before EPA was pending. West Penn cannot predict the outcome of this proceeding. Water Standards Under the National Pollutant Discharge Elimination System (NPDES), permits for all System-owned stations and disposal sites are in place. However, NPDES permit renewals for several West Virginia disposal sites contain what the Operating Subsidiaries believe are overly stringent discharge limitations. The WVDEP has temporarily stayed the stringent permit limitations while the Operating Subsidiaries continue to work with WVDEP and EPA in order to scientifically justify less stringent limits. Where this is not possible, installation of wastewater treatment facilities may become necessary. The cost of such facilities, if required, cannot be predicted at this time. The EPA and state agencies have implemented stormwater runoff regulations for controlling discharges from industrial and municipal sources as well as construction sites. Stormwater discharges have been identified and included in NPDES permit renewals, but controls have not yet been required. Since the current round of permit renewals began in 1993, monitoring requirements have been imposed, with pollution reduction plans and additional control of some discharges anticipated. The Clean Water Act deadline of October 1, 1994 for compliance with Phase II of the stormwater program passed without EPA promulgating

regulations specifying which additional stormwater sources require NPDES permits. Affected System-owned facilities could include office buildings, parking lots, substations and rights-of-way. In the interim, the EPA has issued a policy memorandum specifying that its stormwater compliance enforcement strategy does not apply to Phase II sources. The Subsidiaries cannot predict the effect of EPA's regulations when promulgated. Pursuant to the National Groundwater Protection Strategy, West Virginia adopted a Groundwater Protection Act in 1991. This law establishes a statewide antidegradation policy which could require the Operating Subsidiaries to undertake reconstruction of existing landfills and surface impoundments as well as groundwater remediation, and may affect herbicide use for right-of-way maintenance in West Virginia. Groundwater protection standards were approved and implemented in 1993 (based on EPA drinking water criteria) which established compliance limits. Pursuant to the groundwater protection standards variance provision, on October 26, 1994 the Operating Subsidiaries jointly filed with American Electric Power and Virginia Power, a Notice of Intent (NOI) to request class or source variances from the groundwater standards for steam electric operating facilities in West Virginia. Additionally, each of the companies filed individual NOIs. Technical and socio-economic justification to support the variance requests are being developed and the costs shared by the Operating Subsidiaries under a contract with EPRI. While the justification for the variance requests is being developed, the Operating Subsidiaries are protected from any enforcement action. Because variance requests must ultimately be approved by the West Virginia legislature, it is not possible to predict the outcome. The Pennsylvania Department of Environmental Resources (PADER) developed a Groundwater Quality Protection Strategy which established a goal of nondegradation of groundwater quality. However, the strategy recognizes that there are technical and economic limitations to immediately achieving the goal and further recognizes that some groundwaters need greater protection than others. PADER is beginning to implement the strategy by promulgating changes to the existing rules that heretofore did not consider the nondegradation goal. The full extent of the impact of the strategy on the Operating Subsidiaries cannot be predicted. In 1994, the Operating Subsidiaries received two NOVs from PADER and one NOV from WVDEP, all of which have been resolved. A chronic NPDES compliance problem at the closed Springdale Ash Area was resolved recently with the negotiation of a compliance agreement with PADER. The agreement specified the payment of a penalty for past permit exceedances, required payment of additional penalties for any future exceedances and provided for the installation of innovative constructed wetland treatment technology. The first stage has been installed and is operating in compliance with current NPDES permit effluent limitations.

Hazardous and Solid Wastes Pursuant to the Resource Conservation and Recovery Act of 1976 (RCRA) and the Hazardous and Solid Waste Management Amendments of 1984, EPA regulates the disposal of hazardous and solid waste materials. Maryland, Pennsylvania, Ohio, 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. The Operating Subsidiaries are in a continual process of either permitting new or re-permitting existing disposal capacity to meet future disposal needs. All disposal areas are currently operating in compliance with their permits. It is anticipated that additional disposal capacity will be required for Armstrong Power Station. A small extension to the existing permitted disposal site and the permitting of a new site, are being actively pursued with PADER. A permit for an extension of the existing disposal site is anticipated to be granted by the end of 1995 for construction and use in 1996. Siting of a new disposal area will be a much longer process. If the Operating Subsidiaries fail to obtain either disposal permit, it could have an adverse impact on the operation of the Armstrong Power Station. Significant costs were incurred during 1994 for expansion of existing coal combustion by-product disposal sites due to requirements for installation of liners on new sites and assessment of groundwater impacts through routine groundwater monitoring and specific hydrogeological studies. Existing sites may not meet the current regulatory criteria and groundwater remediation may be required at some of the Operating Subsidiaries' facilities. The Operating Subsidiaries continue to work with regulatory agencies to resolve outstanding issues. Additional and substantial costs may be incurred by the Operating Subsidiaries if remediation of existing sites is necessary. 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. On March 4, 1994, the Operating Subsidiaries received notice that the EPA had identified them as potentially responsible parties under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, with respect to the Jack's Creek/Sitkin Smelting Superfund Site. (See ITEM 3. LITIGATION for a further discussion of this case.)

Emerging Environmental Issues Title III of the CAAA requires EPA to conduct studies of toxic air pollutants from electric utility plants to determine if emission controls are necessary. EPA's reports are expected to be submitted to Congress in late 1995. If air toxic emission controls are recommended by EPA, final regulations are not likely to be promulgated prior to the year 2000. The impact of Title III on the Operating Subsidiaries is unknown at this time. Reauthorization of the Clean Water Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980 and the RCRA are currently pending. When reauthorization does occur, it is anticipated that EPA will likely continue to regulate coal combustion by-product wastes and their leachates as nonhazardous. Pursuant to RCRA, EPA will begin reviewing the electric utility industry's disposal practices of pyrites and pyritic material in 1995. Concerns over the production of low pH waters from pyrites may cause reclassification of ash or flue-gas desulfurization sludge disposal areas containing pyrites to that of special handling waste, or even possibly hazardous waste. Any change in classification would result in substantially increased costs for either retrofitting existing disposal sites or designing new disposal sites. A final determination is scheduled for 1998. An additional issue which could impact the Operating Subsidiaries and which is undergoing intense study, is the health effect, if any, of electric and magnetic fields. The financial impact of this issue on the Operating Subsidiaries, if any, cannot be assessed at this time. In connection with President Clinton's Climate Change Action Plan concerning greenhouse gases, the Operating Subsidiaries expressed by letter to the Department of Energy (DOE) in August 1993, their willingness to work with the DOE on implementing voluntary, cost- effective courses of action that reduce or avoid emission of greenhouse gases. Such courses of action must take into account the unique circumstances of each participating company, such as growth requirements, fuel mix and other circumstances. Furthermore, they must be consistent with the Operating Subsidiaries' integrated resource planning process and must not have an adverse effect on competitive position in terms of costs and rates or be unacceptable to their regulators. Some 63 other electric utility systems submitted similar letters. On April 27, 1994, the DOE and the Edison Electric Institute, on behalf of member utilities, signed the Climate Challenge Program Memorandum of Understanding which establishes the principles DOE and utilities will operate under to reduce or avoid emission of greenhouse gases. A company-specific agreement is to be entered into on behalf of the Operating Subsidiaries and DOE in early February 1995.

REGULATION APS and the Subsidiaries are subject to the broad jurisdiction of the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA). APS is also subject to the jurisdiction of the Maryland PSC as to certain of its activities. The Subsidiaries are regulated as to substantially all of their operations by regulatory commissions in the states in which they operate and also by the DOE and the FERC. In addition, they are subject to numerous other city, county, state, and federal laws, regulations, and rules. In November 1994, the SEC published a release requesting comments from regulated public utility holding company systems and other interested parties on modernizing PUHCA by internal changes in rules and regulations. Comments are due in early February 1995. APS, along with all of the other registered electric public utility holding companies, is advocating repeal of PUHCA. However, APS cannot predict what changes, if any, will be made to PUHCA. The National Energy Policy Act of 1992 (EPACT), among other things, amends PUHCA to permit utilities subject to PUHCA to compete in the wholesale generation business with other wholesale generators not subject to PUHCA; to ease restrictions on financing for that purpose; and to permit investment in foreign utilities. EPACT also amends the Federal Power Act to permit the FERC to order, under specified circumstances, access to transmission systems (including those of the System) so long as it would not unreasonably impair reliability nor adversely affect its existing wholesale, retail and transmission customers. It also amends PURPA to encourage states to study and regulate various matters, including the capital structures of EWGs, integrated resource planning, and the amount of purchased power that electric utilities should have in their generation mix. In addition it sets forth waste disposal standards, new nuclear licensing procedures, and contains provisions promoting alternate transportation fuels, research on environmental issues, and increased energy from renewables (See discussion of EPACT in ITEM 1. BUSINESS, SALES and ELECTRIC FACILITIES). Section 111 of EPACT requires the state utility commissions to institute proceedings to investigate and determine the feasibility of adopting proposed federal standards regarding three regulatory policy issues related to integrated resource planning, rate recovery methods for investments in demand-side management programs, and rates to encourage investments in cost-effective energy efficiency improvements to generation, transmission and distribution facilities. Maryland, Pennsylvania, Virginia, and West Virginia initiated investigations to determine whether to adopt the federal standards, while Ohio summarily issued a final order without an investigation. The Operating Subsidiaries submitted comments in the Maryland, Pennsylvania, and West Virginia proceedings and will file comments in 1995 in Virginia. To date, Maryland, Ohio, and West Virginia have issued final orders. All three states declined to adopt the federal standards, concluding that existing state regulations adequately address the issues. The outcome in the remaining jurisdictions cannot be predicted. The Operating Subsidiaries founded and continue to participate in, along with other utilities, an organization whose primary purpose

is to develop a mutually acceptable method of resolving the inequities imposed on transmission network owners by parallel power flows. In July 1993, the Pennsylvania PUC directed the Bureau of Conservation, Economics and Energy Planning to develop competitive bidding regulations to replace, at least in part, the existing state PURPA regulations. The Pennsylvania PUC has instituted a proposed rulemaking regarding competitive bidding regulations. In collaboration with other Pennsylvania Electric Association companies, West Penn filed comments to the proposed competitive bidding rulemaking in October 1994. The Pennsylvania PUC has not issued a final order in connection with the proposed competitive bidding rulemaking. West Penn cannot predict the outcome of this proceeding. In November 1993, while awaiting the new competitive bidding regulations, West Penn filed a petition with the Pennsylvania PUC requesting an order that, pending the adoption of new state regulations requiring competitive bidding for PURPA, any proceedings or orders regarding purchase by West Penn of capacity from a qualifying facility under PURPA shall be based on competitive bidding. On June 3, 1994, the Pennsylvania PUC granted the West Penn petition. However, the Pennsylvania PUC reserved judgment on the applicability of the competitive bidding process to the South River project and provided that the question would be addressed in the South River complaint proceeding. Various aspects of the Pennsylvania PUC's decision have been appealed to the Pennsylvania Commonwealth Court by South River, West Penn, and Shannopin. This proceeding has been stayed pending the outcome of an appeal in an unrelated case. (See ITEM 3. LEGAL PROCEEDINGS for a description of the South River complaint, the Shannopin Project, and events that have taken place in Pennsylvania Commonwealth Court.) On October 8, 1993, the West Virginia PSC issued proposed regulations concerning bidding procedures for capacity additions for electric utilities and invited comment by December 7, 1993. A number of interested parties, including Monongahela and Potomac Edison, filed comments. In May 1994, the West Virginia PSC held hearings on the proposed regulations. The West Virginia PSC has yet to issue an opinion. On December 17, 1992, the Ohio PUC issued proposed rules concerning competitive bidding for supply-side resources, transmission access for winning bidders and incentives for the recovery of the cost of purchased power. The Ohio PUC invited comments by March 3, 1993 and reply comments by March 24, 1993. A number of interested parties, including Monongahela, submitted comments. The Ohio PUC has taken no further action following the filing of comments. Maryland and Virginia have not mandated compulsory competitive bidding as of this date. On September 20, 1994, the Maryland PSC issued an order which instituted a proceeding for the purpose of examining regulatory and competitive issues affecting electric service in Maryland. On November 1, 1994, the Maryland PSC staff distributed a discussion paper describing the issues which they believe warrant analysis and comment by the utilities and interested persons. Potomac Edison submitted initial comments in response to the staff paper in January 1995. Legislative hearings are currently scheduled for March 1995.

The Ohio PUC has initiated informal roundtable discussions "on issues concerning competition in the electric utility industry and promoting increased competitive options for Ohio businesses that do not unduly harm the interests of utility company shareholders or ratepayers". These discussions are being undertaken pursuant to an Ohio Energy Strategy issued in April 1994. The first two roundtable discussions, attended by representatives of electric utilities, including Monongahela, businesses, residential consumers, environmental groups, and other interested persons or organizations were held on October 17 and December 8, 1994. The Ohio PUC will continue to hold roundtable meetings at approximately six-week intervals. The Pennsylvania PUC instituted an investigation into electric power competition on May 10, 1994, requesting responses from interested persons on several broad areas of inquiry, such as retail wheeling, treatment of stranded investments, consumer protection and utility financial health. Comments were filed on November 10, 1994 and reply comments were filed on January 10, 1995. The Pennsylvania PUC has set a deadline of May 10, 1995 to conclude the investigation. In August 1994, the Pennsylvania PUC instituted a proposed rulemaking relating to Pennsylvania PUC review of siting and construction of electric transmission lines. In an order in connection with the proposed rulemaking, the Pennsylvania PUC propounded a list of questions, including questions regarding electric and magnetic fields. In December 1994, West Penn filed responses to the questions. West Penn cannot predict the outcome of this proposed rulemaking. In October 1990, the Pennsylvania PUC ordered Pennsylvania's major electric utilities, including West Penn, to file programs for demand-side management designed to reduce customer demand for electricity and to reduce the need for additional generating capacity. The Pennsylvania PUC also instituted a proceeding to formalize incentive ratemaking treatment for successful demand-side management activities. On December 13, 1993 the Pennsylvania PUC entered an order allowing Pennsylvania utilities to recover the costs of demand-side management activities, to recover revenues lost as a result of the activities, and to recover a performance incentive for successful activities. A group of industrial customers appealed the order of the Pennsylvania PUC to the Pennsylvania Commonwealth Court. On January 9, 1995, the Court held that utilities could recover demand-side management expenditures, but held that the Pennsylvania PUC had incorrectly allowed recovery of lost revenues and performance incentives. On January 23, 1995, the Pennsylvania PUC requested reargument of the case before the Commonwealth Court, and that request is pending. During 1994, Potomac Edison continued its participation in the Collaborative Process for demand-side management in Maryland with the Maryland PSC Staff, Office of People's Counsel, the Department of Natural Resources, Maryland Energy Administration, and Potomac Edison's largest industrial customer. Potomac Edison had received the Maryland PSC's approval to implement the Commercial and Industrial Lighting Rebate Program and the Power Saver/Comfort Home Program for new residential construction as of July 1, 1993. Through December 31, 1994 Potomac Edison had approved applications for $16.1 million in rebates related to the commercial lighting program and $1.2 million in rebates related to the residential new construction program. The peak demand

reductions from these two programs through the end of 1994 should reduce future generation requirements by about 26.0 and 1.9 MW, respectively. Program costs (including rebates) which are being amortized over a seven-year period, lost revenues, and a performance- based shared savings incentive (shareholder bonus) are being recovered through an Energy Conservation Surcharge. West Penn implemented a Low Income Payment and Usage Reduction Program in 1994. This pilot program will run for two years and will assist up to 2,000 low income customers. The program allows a customer to enter into a payment agreement with West Penn which results in a reduced monthly payment based on income. The difference between the amount of the actual bill and the customer's payment is paid by Federal Assistance Grants and West Penn. The program is administered by the Dollar Energy Fund, a non-profit, charitable organization. West Penn also implemented a Customer Assistance and Referral Evaluation Service Program in 1994 for customers with special needs. West Penn representatives work with customers who are experiencing temporary hardship in an attempt to solve their problems and maximize their ability to pay their bills. West Penn representatives utilize a variety of internal and external resources to address the needs of such customers. ITEM 2. PROPERTIES Substantially all of the properties of the Operating Subsidiaries are held subject to the lien securing each Operating Subsidiary's first mortgage bonds and, in many cases, subject to certain reservations, minor encumbrances, and title defects which do not materially interfere with their use. Some 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, 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 Operating Subsidiaries possesses the power of eminent domain with respect to its public utility operations. (See also ITEM 1. BUSINESS and SYSTEM MAP.) ITEM 3. LEGAL PROCEEDINGS On September 16, 1994, Duquesne initiated a proceeding before the FERC by filing a request for an order requiring the System to provide 300 MW of transmission service at parity with native load customers from interconnection points within the System to the System's points of interconnection with the Pennsylvania-New Jersey-Maryland Interconnection (PJM). Duquesne is seeking to transmit primarily its

own baseload generation for sales within and beyond the PJM system. The Operating Subsidiaries responded on October 24, 1994 requesting that the FERC order the parties back to negotiations to resolve, through a bilateral contract, outstanding issues concerning the transmission services. The FERC has yet to issue an order in this proceeding. In 1979, National Steel Corporation (National Steel) filed suit against certain Subsidiaries in the Circuit Court of Hancock County, West Virginia, 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 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. The Subsidiaries believe the motion is without merit; however, they cannot predict the outcome of this case. In 1987, West Penn entered into separate agreements with developers of three PURPA projects: Milesburg (43 MW), Burgettstown (80 MW), and Shannopin (80 MW). The agreements provided for the purchase of each project's power over 30 years or more at rates generally approximating West Penn's avoided cost at the time the agreements were negotiated. Each agreement was subject to prior Pennsylvania PUC approval. In 1987 and 1988, West Penn filed a separate petition with the Pennsylvania PUC for approval of each agreement. Since that time, all three agreements have been, in varying degrees, the subject of complex and continuing regulatory and judicial proceedings. On various dates in 1994, West Penn and its two largest industrial customers, ARMCO and Allegheny Ludlum, filed joint petitions with the U.S. Supreme Court for writs of certiorari (Cert) in the Milesburg, Burgettstown, and Shannopin cases. On October 11, 1994, the U.S. Supreme Court denied these requests for appeal. After denial of Cert, the Pennsylvania PUC acted upon a pending petition of Shannopin and on December 1, 1994 refused to answer termination issues regarding Shannopin and ordered that the project be paid capacity costs. West Penn and its two largest industrial customers have appealed this order to the Pennsylvania Commonwealth Court. West Penn cannot predict the outcome of this proceeding. There has been no further action on the Milesburg case since the denial of Cert. West Penn cannot predict the outcome of this matter. As a result of the denial of Cert by the U.S. Supreme Court, the Pennsylvania PUC orders that recalculated rates and adjusted milestone dates for Burgettstown became final and non-appealable as of November 8, 1994. In November 1994, West Penn filed a complaint with the Pennsylvania PUC regarding Burgettstown, Shannopin, and Milesburg, requesting the Pennsylvania PUC to cancel its orders regarding these projects because they are no longer in the public interest. On December 16, 1994, the Pennsylvania PUC dismissed the complaint. West Penn has appealed the order to the Pennsylvania Commonwealth Court. West Penn cannot predict the outcome of this proceeding.

In November 1994, Burgettstown filed a complaint against West Penn in the Court of Common Pleas of Washington County, Pennsylvania. The complaint requests equitable relief in the form of specific performance, declaratory and injunctive relief, and also seeks monetary damages for breach of contract and for tortious interference with Burgettstown's contractual relations with others. The Court has set April 3, 1995 as the trial date for the specific performance remedy only. West Penn cannot predict the outcome of this proceeding. On March 19, 1995, West Penn filed a petition for issuance of a declaratory order with FERC (Petition). This Petition seeks a declaration that the orders of the Pennsylvania PUC requiring West Penn to purchase capacity from Burgettstown violate PURPA and FERC's PURPA regulations and thus West Penn has no obligation to purchase capacity from Burgettstown. West Penn cannot predict the outcome of this proceeding. In October 1993, South River Power Partners, L.P. (South River) filed a complaint against West Penn with the Pennsylvania PUC. The complaint seeks to require West Penn to purchase 240 MW from a proposed coal-fired PURPA project to be built in Fayette County, Pennsylvania. West Penn is opposing this complaint as the power is not needed and the price proposed by South River is in excess of avoided cost. The Pennsylvania Consumer Advocate, the Small Business Advocate, the Pennsylvania PUC Trial Staff and various industrial customers intervened in opposition to the complaint. In August 1994, the Pennsylvania PUC granted West Penn's request to stay proceedings pending resolution of issues in a related matter concerning competitive bidding currently on appeal to the Pennsylvania Commonwealth Court. (See ITEM 1. REGULATION for a discussion of West Penn's competitive bidding petition.) West Penn cannot predict the outcome of this proceeding. Two previously reported complaints had been filed with the West Virginia PSC by developers of cogeneration projects pursuant to PURPA in Marshall and Barbour Counties, West Virginia, seeking to require Monongahela and Potomac Edison to purchase capacity from the projects. These two cases were consolidated. The West Virginia PSC on March 5, 1993 found that: Monongahela had no need for additional capacity; Potomac Edison will need new combustion turbine generating capacity beginning in 1996; and Potomac Edison's avoided cost estimate, which is substantially below the costs sought by the developers of the projects, is reasonable. The developers subsequently asked the West Virginia PSC to consider issues which were not resolved in the March 5, 1993 order. On June 25, 1993 the West Virginia PSC found that Potomac Edison had a PURPA obligation to purchase power from qualifying facilities properly interconnected to the System in Monongahela's service territory and ordered negotiations by Monongahela and Potomac Edison with the two PURPA developers. On August 9, 1993, the West Virginia PSC deconsolidated the two cases. Following the West Virginia Supreme Court's denial of a petition for review of the June 25, 1993 order, both developers requested the start of negotiations. In February 1994, Potomac Edison and Monongahela met with the developer of the Barbour County Project to begin negotiation of issues not resolved in the March 1993 order. There have been no further developments in the Barbour County project since that time. In September 1994, Potomac Edison received a new proposal concerning the Marshall County site from its developer, pursuant to which the developer proposes to sell capacity to Potomac Edison. Potomac Edison replied to the proposal in October 1994. On January 10, 1995, the developer filed a motion with the West Virginia PSC to compel Potomac Edison to enter into an Electric Energy Purchase Agreement. Monongahela and Potomac Edison cannot predict the outcome of these proceedings. As previously reported, effective March 1, 1989, West Virginia enacted a new method for calculating the Business and Occupation Tax

(B & O Tax) on electricity generated in that state, which disproportionately increased the B & O Tax on shipments of electricity to other states. In 1989, West Penn, the Pennsylvania Consumer Advocate, and several West Penn industrial customers filed a joint complaint in the Circuit Court of Kanawha County, West Virginia seeking to have the B & O Tax declared illegal and unconstitutional on the grounds that it violates the Interstate Commerce Clause and the Equal Protection Clause of the federal Constitution and certain provisions of federal law that bar the states from imposing or assessing taxes on the generation or transmission of electricity that discriminate against out-of-state entities. In 1991, West Penn amended the complaint to include a 1990 increase in the rate of the B & O Tax. The trial was held in July 1993 and briefs have been filed. West Penn cannot predict the outcome of this litigation. As of December 1994, Monongahela has been named as a defendant along with multiple other defendants in 1,625 pending asbestos cases involving one or more plaintiffs and Monongahela, Potomac Edison and West Penn have been named as defendants along with multiple other defendants in an additional 716 cases by one or more plaintiffs. Because these cases are filed by "shot-gun" complaints naming many plaintiffs and many defendants, it is presently impossible to determine the actual number of claims against the Operating Subsidiaries. However, based on past experience and data available to date, it is estimated that less than 500 cases actually involve claims against any or all of the Operating Subsidiaries. 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. All plaintiffs claiming exposure at stations operated by the Operating Subsidiaries were employed by third-party contractors, with the exception of three known plaintiffs who claim to have been 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 that 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. Therefore, because of the multiple defendants, the Operating Subsidiaries believe their potential liability is a very small percentage of the total amount of the damages sought. A total of 94 cases have been previously settled by Monongahela for an amount substantially less than the anticipated cost of defense. While the Operating Subsidiaries believe that all of these cases are without merit, they cannot predict the outcome of these cases or whether other cases will be filed. On June 10, 1994, APS and all of its subsidiaries filed a declaratory judgment action in the Superior Court of New Jersey against their historic comprehensive general liability (CGL) insurers. This suit seeks a declaration that the CGL insurers have a duty to defend and indemnify the Operating Subsidiaries in the asbestos cases, as well as in certain environmental actions. To date, one insurer has settled. All other parties have answered the complaint. On January 27, 1995, the Court granted the CGL insurers' motion which dismissed the complaint, without prejudice, on procedural grounds. On the same day, APS and all of its subsidiaries recommenced the action in the Court of Common Pleas of Westmoreland County, Pennsylvania. The outcome of this proceeding cannot be predicted.

On March 4, 1994, the Operating Subsidiaries 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 875 other PRPs involved. A Remedial Investigation/Feasibility Study prepared by the EPA indicates remedial alternatives which range as high as $113 million, to be shared by all responsible parties. The EPA has not yet selected which remedial alternatives it will use, nor has it issued a Proposed Plan and Record of Decision. The Operating Subsidiaries believe they have defenses to allegations of liability and intend to vigorously defend this matter. The Operating Subsidiaries cannot predict the outcome of this proceeding. After protracted litigation concerning the Operating Subsidiaries' application for a license to build a 1,000-MW energy- storage facility near Davis, West Virginia, in 1988 the U.S. District Court reversed the U.S. Army Corps of Engineers' (Corps) denial of a dredge and fill permit on the grounds that, among other things, the Operating Subsidiaries were denied an opportunity to review and comment upon written materials and other communications used by the Corps in making its decision. As a result, the Court remanded the matter to the Corps for further proceedings. This decision has been appealed and negotiations are ongoing to settle this matter. The Operating Subsidiaries cannot predict the outcome of this proceeding. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Neither APS, Monongahela, Potomac Edison, West Penn nor AGC submitted any matters to a vote of shareholders during the fourth quarter of 1994.

<TABLE> <CAPTION> Executive Officers of the Registrants The names of the executive officers of each company, their ages, the positions they hold and their business experience during the past five years appears below: Position (a) and Period of Service Name Age APS APSC MP PE WP AGC <S> <C> <C> <C> <C> <C> <C> <C> Charles S. Ault 56 V.P. (1990- ) Previously, Dir., Per. (1986-90) Thomas A. Barlow 60 V.P. (1987- ) Eileen M. Beck 53 Sec. Sec. Secretary Asst. Sec. Asst. Sec. Sec. (1982- ) (1988- ) (1988- ) (1995- ) (1988- ) (1988- ) Asst. Treas. Asst. Treas. Asst. Treas. (1979- ) (1979- ) (1981- ) Previously, Asst. Sec. (1988-94) Klaus Bergman 63 CEO, CEO, Chrm., CEO Chrm., CEO Chrm., CEO Dir. (1982- ) & Dir. & Dir. & Dir. & Dir. & Dir. & Pres. & CEO (1985- ) (1985- ) (1985- ) (1985- ) (1985- ) (1985- ) Chairman Chairman (1994- ) (1994- ) Previously, Previously, Pres. Pres. (1985-94) (1985-94) Charles V. Burkley 63 Comptroller (1984- ) Nancy L. Campbell 55 V.P. V.P. Treas. Asst. Treas. Treas. & (1994- ) (1993- ) (1995- ) & Asst. Sec. Asst. Sec. Treas. Treas. (1988- ) (1988- ) (1988- ) (1988- ) Richard J. Gagliardi 44 V.P. V.P. Asst. Sec. Asst. Treas. (1991- ) (1990- ) (1990- ) (1982- ) Previously, Asst. V.P. & Dir. Taxes (1988-90) Stanley I. Garnett,II 51 Senior Senior Dir. Dir. Dir. Dir. & V.P. V.P. - Fin. V.P. - Fin. (1990- ) (1990- ) (1990- ) (1990- ) (9/94- ) (9/94- ) V.P. & Asst. Sec. & Asst. Sec. (1985- ) (1982- ) (1982- ) Previously, Previously, Previously, Asst. Treas. V.P. - Fin. V.P. - Fin. Asst. Sec. (1990-9/94) (1990-9/94) (1981-90) Previously, V.P. - Legal & Regulatory (a) All officers and directors are elected annually. </TABLE>

<TABLE> <CAPTION> Position (a) and Period of Service Name Age APS APSC MP PE WP AGC <S> <C> <C> <C> <C> <C> <C> <C> Nancy H. Gormley 62 V.P. V.P. - Legal V.P. Asst. Sec. (1991- ) & Regulatory (1992- ) & Asst. Treas. (1990- ) (1990- ) Previously, Asst. V.P. (1/90-9/90); Previously, Gen. Solicitor Benjamin H. Hayes(b) 60 Pres. (1987-94) & Dir. (1992-94) Thomas K. Henderson 54 V.P. V.P. V.P. (1995- ) (1995- ) (1985- ) Kenneth M. Jones 57 V.P. & V.P. & Dir. & V.P. Comptroller Comptroller (1991- ) (1991- ) (1991- ) Previously, Comptroller (1976- ) Thomas J. Kloc 42 Comptroller Comptroller (1988- ) (1988- ) James D. Latimer 56 Executive V.P. (6/94- ) Previously, V.P. (1988-6/94) (a) All officers and directors are elected annually. (b) Retired effective January 1, 1995. </TABLE>

<TABLE> <CAPTION> Position (a) and Period of Service Name Age APS APSC MP PE WP AGC <S> <C> <C> <C> <C> <C> <C> <C> Kenneth D. Mowl 55 Sec. & Treas. (1986- ) Charles S. Mullett(b) 63 Sec. & Treas. (1983-94) Robert B. Murdock(b) 62 V.P. (1972-94) Richard E. Myers 58 Comptroller (1980- ) Alan J. Noia 47 Pres., COO Pres., COO Dir. Pres. Dir. Dir. & V.P. & Dir. & Dir. (9/94- ) (1990-94) (9/94- ) (9/94- ) (9/94- ) (9/94- ) Previously, & Dir. Previously, Previously, Previously, Previously, Dir. (1990- ) Dir. Dir. (1984-90) & V.P.-Fin. V.P.-Fin. (1987-90) Previously, (1987-90) V.P. (1982-90) (1987-90) (1987-90) Dir. & Exec. V.P. (3/90 - 5/90); Dir. & V.P. (1987-1990) Jay S. Pifer 57 Senior V.P. Pres. & Dir. Pres. & Dir. Pres. (1995- ) (1995- ) (1995- ) (1990- ) & Dir. (1992- ) Previously, V.P. (1985-90) Richard A. Roschli 60 V.P. (6/94- ) Previously, Asst. V.P. (5/94-6/94); Div. Mgr. (1988-5/94) Peter J. Skrgic 53 Senior V.P. Senior V.P. Dir. Dir. & V.P. Dir. Dir. & V.P. (9/94- ) (9/94- ) (1990- ) (1990- ) (1990- ) (1989- ) Previously, Previously, V.P. V.P. (1989-94) (1989-94) Robert R. Winter 51 V.P. V.P. (1987- ) (1995- ) Dale F. Zimmerman 61 Asst. Sec. & Sec. & Treas. Asst. Treas. (1990 - ) (1995- ) Previously, Asst. Sec. (1964-89); Asst. Treas. (1967-89) (a) All officers and directors are elected annually. (b) Retired effective January 1, 1995. </TABLE>

PART II ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS APS. AYP is the trading symbol of the common stock of APS 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, 1994, there were 66,818 holders of record of APS' common stock. The tables below show the dividends paid and the high and low sale prices of the common stock for the periods indicated: <TABLE> <CAPTION> 1994 1993(a) Dividend High Low Dividend High Low <S> <C> <C> <C> <C> <C> <C> 1st Quarter 41 cents $26-1/2 $22-3/8 40-1/2 cents $25-15/16 $23-7/16 2nd Quarter 41 cents $24 $20-1/8 40-1/2 cents $26-3/4 $25 3rd Quarter 41 cents $22-3/4 $19-3/4 41 cents $28-7/16 $26-5/8 4th Quarter 41 cents $22 $19-3/4 41 cents $28 $25-1/2 (a) Stock prices and dividends were adjusted to reflect a two-for-one stock split effective November 4, 1993. </TABLE> The high and low prices through February 2, 1995 were 24 and 21-1/2. The last reported sale on that date was at 23-5/8. Monongahela, Potomac Edison, and West Penn. The information required by this Item is not applicable as all the common stock of the Operating Subsidiaries is held by APS. AGC. The information required by this Item is not applicable as all the common stock of AGC is held by Monongahela, Potomac Edison, and West Penn.

ITEM 6. SELECTED FINANCIAL DATA Page No. APS D-1 Monongahela D-3 Potomac Edison D-5 West Penn D-7 AGC D-9

<TABLE> <CAPTION> D-1 APS CONSOLIDATED STATISTICS Year ended December 31 1994 1993 1992 1991 1990 1989 1984 Summary of Operations (in millions) <S> <C> <C> <C> <C> <C> <C> <C> Operating revenues $2 451.7 $2 331.5 $2 306.7 $2 282.2 $2 301.9 $2 260.7 $1 725.6 Operation expense 1 284.9 1 208.4 1 252.0 1 252.2 1 338.6 1 337.1 948.4 Maintenance 241.9 231.2 210.9 204.2 182.0 185.5 131.3 Depreciation 223.9 210.4 197.8 189.7 180.9 172.3 118.8 Taxes other than income 183.1 178.8 174.6 167.5 152.5 139.5 105.3 Taxes on income 129.7 128.1 115.4 119.1 106.4 89.0 134.4 Allowance for funds used during construction (19.6) (21.5) (17.5) (7.9) (7.2) (7.7) (34.9) Interest charges and preferred dividends 184.2 180.3 171.3 165.0 161.1 156.0 152.1 Other income and deductions (a) 3.8 (1.3) (1.6) (3.8) (5.9) (6.1) Consolidated income before cumulative effect of accounting change (a) 219.8 215.8 203.5 194.0 191.4 194.9 176.3 Cumulative effect of accounting change, net (b) 43.4 Consolidated net income $ 263.2 $ 215.8 $ 203.5 $ 194.0 $ 191.4 $ 194.9 $ 176.3 Common Stock Data (c) Shares outstanding at Dec. 31 (in thousands) 119 293 117 664 113 899 108 451 106 984 105 579 98 757 Average shares outstanding (in thousands) 118 272 114 937 111 226 107 548 106 102 104 787 97 627 Earnings per average share: Consolidated income before cumulative effect of accounting change (a) $1.86 $1.88 $1.83 $1.80 $1.80 $1.86 $1.81 Cumulative effect of accounting change (b) .37 Consolidated net income $2.23 $1.88 $1.83 $1.80 $1.80 $1.86 $1.81 Dividends paid per share $1.64 $1.63 $1.60 1/2 $1.58 1/2 $1.58 $1.55 $1.31 1/4 Dividend pay-out ratio (d) 86.2% 86.9% 88.3% 87.8% 87.6% 83.3% 72.7% Stockholders at Dec. 31 66 818 63 396 63 918 62 095 63 201 68 156 85 080 Market price range per share: High 26 1/2 28 7/16 24 3/8 23 1/4 21 1/16 21 1/4 15 Low 19 3/4 23 7/16 20 3/4 17 7/16 17 17 13/16 12 5/16 Book value per share at Dec. 31 $17.26 $16.62 $16.05 $15.54 $15.26 $14.99 $12.37 Return on average common equity (d)11.22% 11.40% 11.45% 11.59% 11.78% 12.41% 14.69% Capitalization Data at Dec. 31 Capitalization (in millions): Common stock $2 059.3 $1 955.8 $1 827.8 $1 685.6 $1 632.3 $1 582.4 $1 221.5 Preferred stock: Not subject to mandatory redemption 300.1 250.1 250.1 235.1 235.1 235.1 240.1 Subject to mandatory redemption 25.2 26.4 28.0 29.3 30.6 30.6 81.0 Long-term debt 2 178.5 2 008.1 1 951.6 1 747.6 1 642.2 1 578.4 1 464.9 Total capitalization $4 563.1 $4 240.4 $4 057.5 $3 697.6 $3 540.2 $3 426.5 $3 007.5 Capitalization ratios: Common stock 45.1% 46.1% 45.0% 45.6% 46.1% 46.2% 40.6% Preferred stock: Not subject to mandatory redemption 6.6 5.9 6.2 6.3 6.6 6.8 8.0 Subject to mandatory redemption .6 .6 .7 .8 .9 .9 2.7 Long-term debt 47.7 47.4 48.1 47.3 46.4 46.1 48.7 Total Assets at Dec. 31 (in millions) $6 362.2 $5 949.2 $5 039.3 $4 855.0 $4 561.3 $4 433.3 $3 736.8 Property Data at Dec. 31 (in millions) Gross property $7 586.8 $7 176.9 $6 679.9 $6 255.7 $5 986.2 $5 721.5 $4 424.3 Accumulated depreciation (2 529.4) (2 388.8) (2 240.0) (2 093.7) (1 946.1)(1 807.1) (1 176.0) Net property $5 057.4 $4 788.1 $4 439.9 $4 162.0 $4 040.1 $3 914.4 $3 248.3 Gross additions during year $ 508.3 $ 574.0 $ 487.6 $ 337.7 $ 321.8 $ 302.5 $ 297.9 Ratio of provisions for depreciation to depreciable property 3.32% 3.37% 3.31% 3.28% 3.27% 3.26% 3.15% </TABLE>

<TABLE> <CAPTION> D-2 CONSOLIDATED STATISTICS (continued) 1994 1993 1992 1991 1990 1989 1984 Revenues (in millions) <S> <C> <C> <C> <C> <C> <C> <C> Residential $ 863.7 $ 818.4 $ 734.9 $ 708.3 $ 649.5 $ 626.2 $ 514.1 Commercial 459.3 430.2 391.9 375.4 343.0 327.5 260.1 Industrial 728.0 673.4 637.7 600.2 571.5 553.5 515.5 Nonaffiliated utilities 331.6 346.7 465.5 525.0 679.9 698.5 389.5 Other 69.1 62.8 76.7 73.3 58.0 55.0 46.4 Total revenues $2 451.7 $2 331.5 $2 306.7 $2 282.2 $2 301.9 $2 260.7 $1 725.6 Sales--kWh (in millions) Residential 12 630 12 514 11 746 11 755 11 264 11 042 9 411 Commercial 7 607 7 440 7 071 7 003 6 670 6 479 5 274 Industrial 17 708 16 967 16 910 16 430 16 511 16 239 15 431 Nonaffiliated utilities 9 915 12 388 17 753 18 211 21 796 24 383 12 413 Other 1 275 1 240 1 186 1 146 1 101 1 110 950 Total sales 49 135 50 549 54 666 54 545 57 342 59 253 43 479 Output--kWh (in millions) Steam generation 38 959 38 247 40 373 42 307 41 933 43 497 39 298 Hydro and pumped-storage generation 1 390 1 233 1 204 1 654 1 426 1 774 205 Pumped-storage input (1 564) (1 385) (1 340) (1 907) (1 568) (1 973) Purchased power and exchanges, net 12 965 15 245 17 279 15 321 17 924 19 169 6 383 Losses and system uses (2 615) (2 791) (2 850) (2 830) (2 373) (3 214) (2 407) Total sales as above 49 135 50 549 54 666 54 545 57 342 59 253 43 479 Energy Supply Generating capability--MW at Dec. 31 System-owned 8 070 7 991 7 991 7 992 7 991 7 906 7 109 Nonutility contracts (e) 299 292 212 162 160 160 Maximum hour peak--MW 7 153 6 678 6 530 6 238 6 070 6 489 5 508 Load factor 66.8% 70.0% 69.3% 71.7% 71.3% 67.0% 69.3% Heat rate--Btu's per kWh 9 927 10 020 9 910 9 956 9 944 9 967 10 136 Fuel costs--cents per million Btu's 141.50 142.12 141.93 143.19 140.97 136.70 154.38 Customers at Dec. 31 (in thousands) Residential 1 189.7 1 176.6 1 161.5 1 146.6 1 133.4 1 118.1 1 045.4 Commercial 143.0 140.1 137.4 134.7 132.2 128.9 113.6 Industrial 24.2 23.8 23.6 23.1 22.8 2.4 20.4 Other 1.3 1.2 1.2 1.3 1.3 1.2 1.1 Total customers 1 358.2 1 341.7 1 323.7 1 305.7 1 289.7 1 270.6 1 180.5 Average Annual Use--kWh per customer Residential--APS 10 682 10 715 10 181 10 316 10 011 9 950 9 061 Residential--National 9 445 (f) 9 380 (f) 8 949 (f) 9 280 (c) 9 056 9 063 8 500 All retail service--APS 28 205 27 800 27 259 27 205 26 996 26 866 25 776 Average Rate--cents per kWh Residential--APS 6.84 6.54 6.26 6.03 5.77 5.67 5.46 Residential--National 8.78 (f) 8.73 (f) 8.63 (f) 8.46 8.17 7.95 7.53 All retail service--APS 5.43 5.23 4.96 4.80 4.56 4.48 4.30 (a) Includes asset write-off of $5.3 million ($.05 per share), net of income taxes in 1994. (b) To record unbilled revenues, net of income taxes. (c) Reflects a two-for-one common stock split effective November 4, 1993. (d) Excludes the cumulative effect of the accounting change and asset write-off in 1994. (e) Capability available through contractual arrangements with nonutility generators. (f) Preliminary. </TABLE>

<TABLE> <CAPTION> D-3 Monongahela SUMMARY OF OPERATIONS (Thousands of Dollars) 1994 1993 1992 1991 1990 1989 Electric operating revenues: <S> <C> <C> <C> <C> <C> <C> Residential $190 861 $185 141 $169 589 $163 757 $151 658 $146 429 Commercial 116 201 110 762 102 709 97 849 90 095 86 527 Industrial 202 181 187 669 186 442 177 688 169 654 165 940 Nonaffiliated utilities 79 701 86 032 119 628 140 029 177 573 185 122 Other, including affiliates 91 186 72 240 53 595 45 803 41 348 44 881 Total 680 130 641 844 631 963 625 126 630 328 628 899 Operation expense 394 438 364 027 372 002 364 968 379 663 395 614 Maintenance 69 389 67 770 62 909 64 035 57 768 58 690 Depreciation 57 952 56 056 53 865 51 903 50 433 48 381 Taxes other than income 40 404 34 076 33 207 35 378 34 310 32 552 Taxes on income 30 712 33 612 27 919 31 173 31 005 19 293 Allowance for funds used during construction (2 946) (5 780) (3 908) (1 341) (1 559) (2 295) Interest charges 38 156 37 588 36 013 33 494 33 264 32 544 Other income, net (7 911) (7 203) (8 388) (8 573) (9 505) (11 325) Income before cumulative effect of accounting change 59 936 61 698 58 344 54 089 54 949 55 445 Cumulative effect of accounting change, net (a) 7 945 Net income $67 881 $61 698 $58 344 $54 089 $54 949 $55 445 Return on average common equity (b) 10.66% 11.83% 11.96% 11.43% 11.84% 12.23% (a) To record unbilled revenues, net of income taxes. (b) Excludes the cumulative effect of the accounting change in 1994. </TABLE>

<TABLE> <CAPTION> D-4 Monongahela FINANCIAL AND OPERATING STATISTICS 1994 1993 1992 1991 1990 1989 PROPERTY, PLANT, AND EQUIPMENT at Dec. 31 (in thousands): <S> <C> <C> <C> <C> <C> <C> Gross $1 763 533 $1 684 322 $1 567 252 $1 458 643 $1 389 906 $1 334 814 Accumulated depreciation (701 271) (664 947) (628 595) (590 311) (550 104) (512 439) Net $1 062 262 $1 019 375 $ 938 657 $ 868 332 $ 839 802 $ 822 375 GROSS ADDITIONS TO PROPERTY (in thousands) $ 103 975 $ 140 748 $ 126 422 $ 84 515 $ 74 575 $ 84 972 TOTAL ASSETS at Dec. 31 (in thousands) $1 476 483 $1 407 453 $1 166 410 $1 091 287 $1 054 497 $1 024 709 CAPITALIZATION at Dec. 31: Amount (in thousands): Common stock $ 495 693 $ 483 030 $ 475 628 $ 428 855 $ 425 016 $ 410 409 Preferred stock (not subject to mandatory redemption) 114 000 64 000 64 000 69 000 69 000 69 000 Long-term debt 470 131 460 129 444 506 372 618 367 871 367 826 $1 079 824 $1 007 159 $ 984 134 $ 870 473 $ 861 887 $ 847 235 Ratios: Common stock 45.9% 48.0% 48.3% 49.3% 49.3% 48.4% Preferred stock (not subject to mandatory redemption) 10.6 6.3 6.5 7.9 8.0 8.2 Long-term debt 43.5 45.7 45.2 42.8 42.7 43.4 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% GENERATING CAPABILITY- kW at Dec. 31: Company-owned 2 326 300 2 325 300 2 325 300 2 325 300 2 325 300 2 301 925 Nonutility contracts* 161 000 159 000 79 000 29 000 27 000 27 000 KILOWATTHOURS IN THOUSANDS: Sales: Residential 2 674 664 2 689 830 2 527 247 2 581 628 2 430 539 2 401 287 Commercial 1 846 791 1 825 127 1 742 469 1 744 881 1 656 961 1 606 830 Industrial 4 942 388 4 656 921 4 872 126 4 905 715 4 868 551 4 828 376 Nonaffiliated utilities 2 383 531 3 082 715 4 578 187 4 877 930 5 634 908 6 490 586 Other,including affiliates 1 925 450 1 565 561 824 393 584 677 590 920 942 404 Total sales 13 772 824 13 820 154 14 544 422 14 694 831 15 181 879 16 269 483 Output: Steam generation 10 743 934 10 194 794 10 593 059 11 512 714 11 247 964 12 328 241 Pumped-storage generation 290 586 263 329 260 155 375 500 306 470 390 151 Pumped-storage input (373 116) (337 737) (332 989) (475 898) (389 467) (530 642) Purchased power and exchanges, net 3 784 421 4 381 916 4 705 418 3 969 954 4 618 564 4 815 449 Losses and system uses (673 001) (682 148) (681 221) (687 439) (601 652) (733 716) Total sales as above 13 772 824 13 820 154 14 544 422 14 694 831 15 181 879 16 269 483 CUSTOMERS at Dec. 31: Residential 300 465 297 865 294 595 291 578 288 990 286 823 Commercial 35 268 34 626 34 005 33 484 33 107 32 614 Industrial 8 029 8 014 8 005 7 994 7 946 7 870 Other 171 170 172 172 170 166 Total customers 343 933 340 675 336 777 333 228 330 213 327 473 RESIDENTIAL SERVICE: Average use-kWh per customer 8 957 9 093 8 636 8 905 8 457 8 406 Average revenue-dollars per customer 639.16 625.87 579.51 564.87 527.70 512.62 Average rate-cents per kWh 7.14 6.88 6.71 6.34 6.24 6.10 * Capability available through contractual arrangements with nonutility generators. </TABLE>

<TABLE> <CAPTION> D-5 Potomac Edison SUMMARY OF OPERATIONS (Thousands of Dollars) 1994 1993 1992 1991 1990 1989 Electric operating revenues: <S> <C> <C> <C> <C> <C> <C> Residential $296 090 $274 358 $243 413 $227 851 $213 165 $208 663 Commercial 135 937 124 667 111 506 104 642 97 902 94 648 Industrial 195 089 175 902 157 304 147 654 148 632 152 296 Nonaffiliated utilities 107 027 108 132 141 120 161 720 210 710 208 524 Other, including affiliates 25 222 29 526 34 544 32 210 27 135 26 287 Total 759 365 712 585 687 887 674 077 697 544 690 418 Operation expense 448 527 413 145 414 939 423 489 460 546 449 480 Maintenance 58 624 64 376 53 141 49 766 45 035 46 837 Depreciation 59 989 56 449 53 446 50 578 47 547 44 638 Taxes other than income 46 740 46 813 45 791 43 937 38 527 36 483 Taxes on income 33 163 30 086 28 422 24 194 25 132 27 680 Allowance for funds used during construction (5 874) (7 134) (5 368) (3 366) (2 908) (2 381) Interest charges 46 456 43 802 39 392 36 831 33 049 28 805 Other income, net (10 243) (8 419) (9 352) (9 593) (10 964) (10 802) Income before cumulative effect of accounting change 81 983 73 467 67 476 58 241 61 580 69 678 Cumulative effect of accounting change, net (a) 16 471 Net income $98 454 $73 467 $67 476 $58 241 $61 580 $69 678 Return on average common equity (b) 11.86% 11.63% 11.85% 11.04% 12.31% 15.07% (a) To record unbilled revenues, net of income taxes. (b) Excludes the cumulative effect of the accounting change in 1994. </TABLE>

<TABLE> <CAPTION> D-6 FINANCIAL AND OPERATING STATISTICS 1994 1993 1992 1991 1990 1989 PROPERTY, PLANT, AND EQUIPMENT at Dec. 31 (in thousands): <S> <C> <C> <C> <C> <C> <C> Gross $1 978 396 $1 857 961 $1 698 711 $1 557 695 $1 454 250 $1 352 491 Accumulated depreciation (673 853) (632 269) (591 378) (546 867) (504 168) (466 428) Net $1 304 543 $1 225 692 $1 107 333 $1 010 828 $ 950 082 $ 886 063 GROSS ADDITIONS TO PROPERTY (in thousands) $ 142 826 $ 179 433 $ 153 485 $ 116 589 $ 116 627 $ 104 009 TOTAL ASSETS at Dec. 31 (in thousands) $1 629 535 $1 519 763 $1 355 385 $1 256 712 $1 140 623 $1 074 464 CAPITALIZATION at Dec. 31: Amount (in thousands): Common stock $ 658 146 $ 626 467 $ 567 826 $ 480 931 $ 453 761 $ 421 583 Preferred stock: Not subject to mandatory redemption 36 378 36 378 36 378 56 378 56 378 56 378 Subject to mandatory redemption 25 200 26 400 28 005 29 280 30 555 30 630 Long-term debt 604 749 517 910 511 801 453 584 399 518 320 533 $1 324 473 $1 207 155 $1 144 010 $1 020 173 $ 940 212 $ 829 124 Ratios: Common stock 49.7% 51.9% 49.6% 47.1% 48.3% 50.8% Preferred stock: Not subject to mandatory redemption 2.7 3.0 3.2 5.5 6.0 6.8 Subject to mandatory redemption 1.9 2.2 2.5 2.9 3.2 3.7 Long-term debt 45.7 42.9 44.7 44.5 42.5 38.7 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% GENERATING CAPABILITY: kW at Dec. 31 2 072 292 2 076 592 2 076 592 2 077 192 2 076 292 2 059 292 KILOWATTHOURS IN THOUSANDS: Sales: Residential 4 214 997 4 144 958 3 822 387 3 753 884 3 561 824 3 466 647 Commercial 2 136 081 2 091 930 1 954 025 1 912 848 1 818 789 1 744 825 Industrial 5 339 737 5 194 909 4 979 219 4 881 835 4 928 433 4 896 273 Nonaffiliated utilities 3 194 580 3 860 791 5 394 006 5 649 050 6 818 528 7 311 705 Other, including affiliates 653 614 649 636 616 711 615 604 593 548 599 099 Total sales 15 539 009 15 942 224 16 766 348 16 813 221 17 721 122 18 018 549 Output: Steam generation 10 464 607 10 103 411 10 713 987 11 192 300 11 094 016 11 538 206 Hydro and pumped-storage generation 426 550 368 834 351 035 502 302 430 500 522 300 Pumped-storage input (506 213) (433 885) (407 393) (593 879) (489 243) (550 944) Purchased power and exchanges, net 5 896 492 6 691 792 6 937 037 6 517 575 7 387 314 7 526 595 Losses and system uses (742 427) (787 928) (828 318) (805 077) (701 465) (1 017 608) Total sales as above 15 539 009 15 942 224 16 766 348 16 813 221 17 721 122 18 018 549 CUSTOMERS at Dec. 31: Residential 315 309 309 096 302 559 295 564 289 695 281 469 Commercial 40 927 40 173 39 236 38 522 37 708 36 237 Industrial 4 595 4 509 4 435 4 283 4 132 3 957 Other 524 510 510 501 471 442 Total customers 361 355 354 288 346 740 338 870 332 006 322 105 RESIDENTIAL SERVICE: Average use-kWh per customer 13 506 13 562 12 766 12 822 12 463 12 511 Average revenue-dollars per customer 948.76 897.70 812.96 778.25 745.90 753.04 Average rate-cents per kWh 7.02 6.62 6.37 6.07 5.98 6.02 </TABLE>

<TABLE> <CAPTION> D-7 West Penn SUMMARY OF OPERATIONS (Thousands of Dollars) 1994 1993 1992 1991 1990 1989 Electric operating revenues: <S> <C> <C> <C> <C> <C> <C> Residential $ 376 776 $ 358 900 $ 321 871 $ 316 685 $ 284 691 $ 271 067 Commercial 207 165 194 773 177 697 172 924 154 999 146 364 Industrial 330 739 309 847 293 910 274 896 253 184 235 286 Nonaffiliated utilities 144 829 152 541 204 743 223 225 291 636 304 822 Other, including affiliates 68 733 68 916 78 620 83 073 74 342 58 108 Total 1 128 242 1 084 977 1 076 841 1 070 803 1 058 852 1 015 647 Operation expense 647 963 625 269 647 989 649 422 684 508 673 158 Maintenance 111 841 96 706 93 067 87 717 77 516 78 167 Depreciation 88 935 80 872 73 469 70 334 66 122 62 428 Taxes other than income 87 224 89 249 87 300 80 630 72 114 62 846 Taxes on income 50 385 51 529 44 078 47 846 33 867 24 988 Allowance for funds used during construction (10 777) (8 566) (8 276) (3 224) (2 729) (2 991) Interest charges 60 274 60 585 55 592 51 977 49 268 45 953 Asset write-off, net 5 179 Other income, net (13 797) (12 728) (14 534) (15 077) (15 067) (17 153) Consolidated income before cumulative effect of accounting change 101 015 102 061 98 156 101 178 93 253 88 251 Cumulative effect of accounting change, net (a) 19 031 Consolidated net income $120 046 $102 061 $98 156 $101 178 $93 253 $88 251 Return on average common equity (b) 10.49% 11.49% 11.53% 12.66% 12.07% 11.62% (a) To record unbilled revenues, net of income taxes. (b) Excludes the cumulative effect of the accounting change and asset write-off in 1994. </TABLE>

<TABLE> <CAPTION> D-8 West Penn Power Company and Subsidiaries FINANCIAL AND OPERATING STATISTICS 1994 1993 1992 1991 1990 1989 PROPERTY, PLANT, AND EQUIPMENT at Dec. 31 (in thousands): <S> <C> <C> <C> <C> <C> <C> Gross $3 013 777 $2 803 811 $2 581 641 $2 409 005 $2 312 425 $2 209 054 Accumulated depreciation (1 009 565) (962 623) (904 906) (857 999) (809 674) (762 700) Net $2 004 212 $1 841 188 $1 676 735 $1 551 006 $1 502 751 $1 446 354 GROSS ADDITIONS TO PROPERTY (in thousands) $ 260 366 $ 251 017 $ 204 409 $ 134 443 $ 128 762 $ 112 801 TOTAL ASSETS at Dec. 31 (in thousands) $2 731 858 $2 544 763 $2 083 127 $2 006 309 $1 842 766 $1 784 493 CAPITALIZATION at Dec. 31: Amount (in thousands): Common stock $ 955 482 $ 893 969 $ 782 341 $ 774 707 $ 723 567 $ 694 107 Preferred stock (not subject to mandatory redemption) 149 708 149 708 149 708 109 708 109 708 109 708 Long-term debt 836 426 782 369 759 005 621 906 563 378 563 410 $1 941 616 $1 826 046 $1 691 054 $1 506 321 $1 396 653 $1 367 225 Ratios: Common stock 49.2% 49.0% 46.3% 51.4% 51.8% 50.8% Preferred stock (not subject to mandatory redemption) 7.7 8.2 8.8 7.3 7.9 8.0 Long-term debt 43.1 42.8 44.9 41.3 40.3 41.2 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% GENERATING CAPABILITY-kW at Dec. 31: Company-owned 3 671 408 3 589 408 3 589 408 3 589 408 3 589 408 3 544 783 Nonutility contracts (a) 138 000 133 000 133 000 133 000 133 000 133 000 KILOWATTHOURS IN THOUSANDS: Sales: Residential 5 740 028 5 679 746 5 396 533 5 419 150 5 271 390 5 173 781 Commercial 3 624 117 3 522 566 3 374 355 3 345 255 3 194 141 3 127 641 Industrial 7 426 267 7 114 765 7 058 895 6 643 238 6 713 824 6 514 384 Nonaffiliated utilities 4 337 106 5 444 798 7 780 654 7 683 817 9 342 543 10 580 015 Other, including affiliates 1 530 853 1 821 189 2 247 844 2 485 366 2 426 414 1 868 121 Total sales 22 658 371 23 583 064 25 858 281 25 576 826 26 948 312 27 263 942 Output: Steam generation 17 750 267 17 949 335 19 066 445 19 602 129 19 590 731 19 630 384 Hydro and pumped-storage generation 673 195 600 497 592 895 775 798 688 517 862 119 Pumped-storage input (684 715) (613 290) (599 729) (836 700) (689 186) (891 847) Purchased power and exchanges, net 6 119 757 6 967 752 8 139 496 7 373 185 8 428 158 9 125 988 Losses and system uses (1 200 133) (1 321 230) (1 340 826) (1 337 586) (1 069 908) (1 462 702) Total sales as above 22 658 371 23 583 064 25 858 281 25 576 826 26 948 312 27 263 942 CUSTOMERS at Dec. 31: Residential 573 963 569 601 564 300 559 444 554 716 549 773 Commercial 66 842 65 337 64 212 62 674 61 396 60 062 Industrial 11 563 11 218 11 138 10 826 10 687 10 561 Other 586 576 569 692 680 660 Total customers 652 954 646 732 640 219 633 636 627 479 621 056 RESIDENTIAL SERVICE: Average use-kWh per customer 10 041 10 025 9 608 9 733 9 550 9 459 Average revenue-dollars per customer 659.07 633.48 573.07 568.76 515.75 495.60 Average rate-cents per kWh 6.56 6.32 5.96 5.84 5.40 5.24 (a) Capability available through contractual arrangements with nonutility generators. </TABLE>

<TABLE> <CAPTION> D-9 AGC STATISTICS 1994 1993 1992 1991 1990 1989 SUMMARY OF OPERATIONS (Thousands of Dollars) Electric <S> <C> <C> <C> <C> <C> <C> operating revenues $91 022 $90 606 $96 147 $100 505 $104 482 $111 011 Operation and maintenance expense 6 695 6 609 6 094 6 774 5 974 6 229 Depreciation 16 852 16 899 16 827 16 778 16 756 16 816 Taxes other than income taxes 5 223 5 347 5 236 4 563 4 712 5 062 Federal income taxes 14 737 13 262 14 702 15 455 16 458 17 230 Interest charges 17 809 21 635 22 585 24 030 26 883 30 020 Other income, net (11) (328) (21) (24) (17) (24) Net income $29 717 $27 182 $30 724 $ 32 929 $ 33 716 $ 35 678 Return on average common equity 13.14% 11.72% 12.79% 13.09% 12.78% 12.95% PROPERTY, PLANT, AND EQUIPMENT at Dec. 31 (in thousands): Gross $824 714 $824 904 $825 493 $822 332 $821 424 $820 376 Accumulated depreciation (143 965) (128 375) (114 684) (97 915) (81 514) (64 906) Net $680 749 $696 529 $710 809 $724 417 $739 910 $755 470 GROSS ADDITIONS TO PROPERTY (in thousands) $1 065 $2 729 $3 251 $1 391 $1 214 $532 TOTAL ASSETS at Dec. 31 (in thousands) $714 236 $735 929 $727 820 $742 223 $757 084 $777 047 CAPITALIZATION at Dec. 31: Amount (in thousands): Common stock $222 729 $228 512 $235 530 $244 593 $254 664 $265 648 Long-term debt 267 165 277 196 287 139 299 502 311 461 326 600 $489 894 $505 708 $522 669 $544 095 $566 125 $592 248 Ratios: Common stock 45.5% 45.2% 45.1% 45.0% 45.0% 44.9% Long-term debt 54.5 54.8 54.9 55.0 55.0 55.1 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% KILOWATTHOURS IN THOUSANDS: Pumping energy supplied by parents 1 564 044 1 384 912 1 340 111 1 906 477 1 567 896 1 973 433 Pumped-storage generation 1 218 446 1 079 985 1 047 015 1 504 310 1 233 782 1 554 767 </TABLE>

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Page No. APS M-1 Monongahela M-5 Potomac Edison M-13 West Penn M-21 AGC M-30

M-1 APS MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CONSOLIDATED NET INCOME Earnings per share were $2.23 in 1994, including $.37 of non-recurring income from the cumulative effect of an accounting change to record unbilled revenues. The 1994 results also reflect the write-off ($.05 per share) of previously accumulated costs related to future facilities no longer considered meaningful in the industry's more competitive environment. Earnings per share were $1.88 and $1.83 in 1993 and 1992, respectively. Consolidated net income was $263.2 million including the $43.4 million non-recurring cumulative effect of an accounting change and net of the $5.3 million asset write-off described above. Consolidated net income was $215.8 million and $203.5 million in 1993 and 1992, respectively. The 1994 and 1993 increases in consolidated net income resulted primarily from kWh sales and retail rate increases. These revenue increases, in both years, were offset in part by higher expenses. The subject of competition for customers, particularly industrial customers, has been receiving a lot of attention. In 1994 the Maryland, Ohio, and Pennsylvania commissions started proceedings described as inquiries into the subject, which are still in progress. The inquiries are not expected to result in immediately meaningful changes in current relations with our customers. All customers, except wholesale customers regulated by the Federal Energy Regulatory Commission (FERC), continue to be required to purchase their electricity requirements from the utility in whose franchised territory they reside. This is not to say that competition does not exist. Utilities continue to compete for the siting of new industrial and commercial customers, to retain existing customers in the franchised territory, and, for those businesses with multiple plants in multiple territories, to maintain or shift their production to local facilities. As in the past, electric utilities continue to compete with suppliers of other forms of energy. Because the subsidiaries are the lowest or among the lowest cost suppliers of electricity in their regions, they should not experience the competitive concerns of other utilities who use cost-based pricing. However, the subsidiaries continue to face competition from utilities with excess generation that are willing to sell at prices intended only to recover variable costs. SALES AND REVENUES KWh sales to and revenues from residential, commercial, and industrial customers are shown on page 35. Such kWh sales increased 2.8% and 3.3% in 1994 and 1993, respectively. The increases in revenues from sales to residential, commercial, and industrial customers resulted from the following: Increase from Prior Year 1994 1993 (Millions of Dollars) Increased kWh sales $ 23.6 $ 46.6 Fuel and energy cost adjustment clauses* 48.3 57.0 Rate increases: Pennsylvania 22.7 25.2 Maryland 11.9 12.7 West Virginia 9.7 5.3 Virginia 8.5 2.5 Ohio 2.1 52.8 47.8 Other 4.3 6.2 $129.0 $157.6 * Changes in revenues from fuel and energy cost adjustment clauses have little effect on consolidated net income. The increased kWh sales in 1994 reflect growth in both residential and commercial customers and higher use by commercial customers. The 1994 residential use was down slightly from 1993 levels reflecting a decrease in both heating and cooling degree days. The increased kWh sales to residential and commercial customers in 1993 reflect both growth in number of customers and higher use. While 1993 heating degree days showed only a slight increase over 1992, and were approximately normal, cooling degree days increased 69% over 1992 and were 25% over normal, contributing to the 1993 kWh sales increases. Rate case decisions in almost all jurisdictions, representing revenue increases in excess of $120 million on an annual basis, were issued for the subsidiaries in 1994. These included recovery of the remaining carrying charges on investment, depreciation, and all operating costs required to comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and other increasing levels of expense. See Rate Matters on pages 7-9 for further information on rate changes. KWh sales to industrial customers increased 4.4% in 1994 and .3% in 1993. The 1994 increase occurred in almost all industrial groups, particularly coal mining (142 gigawatt-hours [GWh], 9.2%); paper, printing and publishing (130 GWh, 24.9%); iron and steel (130 GWh, 3.8%); and chemical customers (112 GWh, 5.0%). The relatively flat industrial sales growth in 1993 included one particular group, coal mines staffed by union personnel, which recorded reduced usage because of selective work stoppages by the United Mine Workers of America (UMWA) for most of the year prior to the settling of the dispute in December 1993. KWh sales to and revenues from nonaffiliated utilities are comprised of the following items: 1994 1993 1992 KWh sales (in billions): From subsidiaries' generation 1.1 1.2 3.2 From purchased power 8.8 11.2 14.6 9.9 12.4 17.8 Revenues (in millions): From subsidiaries'generation $ 29.0 $ 28.5 $ 91.7 From sales of purchased power 302.6 318.2 373.8 $331.6 $346.7 $465.5

M-2 Decreased sales to nonaffiliated utilities resulted primarily from decreased demand and continuing price competition. Sales supplied by subsidiaries' generation in 1994 continued at less than 15% of 1988 levels because of continuing growth of kWh sales to retail customers, which reduces the amount available for sale, and because other suppliers were willing or able to make the sales at lower prices. A significant factor affecting the subsidiaries' ability to compete in the market for sales to nonaffiliated utilities has been the approximate 290% increase (from about 67 cents per MWh to $2.60 per MWh) in taxes on generation in West Virginia since March 1989--a significant cost not experienced by utilities not generating in West Virginia. Further decreases in these sales are anticipated. About 95% of the aggregate benefits from sales to nonaffiliated utilities is passed on to retail customers and has little effect on consolidated net income. The increase in other revenues in 1994 resulted from increased revenues from wholesale customers. The decrease in other revenues in 1993 resulted from an agreement with the FERC to record in 1993 about $14 million of revenues as sales to nonaffiliated utilities. Similar transactions were recorded as other revenues in prior years. About $46 million of other revenues in 1994 were derived from wholesale customers regulated by the FERC who have the ability to obtain their electricity requirements from other suppliers. In 1994, customers representing about 40% of these revenues signed seven-year contracts to remain as customers. In the event that the other customers were to select another supplier, the subsidiaries would retain transmission revenues with the result that any net income loss would not be significant. OPERATING EXPENSES Fuel expenses increased .5% in 1994 and decreased 4% in 1993, both primarily due to changes in kWh generated. Fuel expenses are primarily subject to deferred power cost accounting procedures, as described in Note A to the consolidated financial statements, with the result that changes in fuel expenses have little effect on consolidated net income. "Purchased power and exchanges, net" represents power purchases from and exchanges with other utilities and qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and is comprised of the following items: 1994 1993 1992 (Millions of Dollars) Purchased power: For resale to other utilities $267.1 $280.9 $344.0 From PURPA generation 134.0 105.2 94.0 Other 40.4 33.8 12.7 Total power purchased 441.5 419.9 450.7 Power exchanges, net (.6) (2.5) .7 $440.9 $417.4 $451.4 The amount of power purchased from other utilities for use by subsidiaries and for resale to other utilities depends upon the availability of the subsidiaries' generating equipment, transmission capacity, and fuel, and their cost of generation and the cost of operations of other utilities from which such purchases are made. The primary reason for the fluctuations in purchases for resale to other utilities is described under SALES AND REVENUES above. The cost of power purchased for use by the subsidiaries, including power from PURPA generation, is mostly recovered from customers currently through the regular fuel and energy cost recovery procedures followed by the subsidiaries' regulatory commissions and is primarily subject to deferred power cost procedures with the result that changes in such costs have little effect on consolidated net income. The increases in purchases from PURPA generation reflect additional generation from new PURPA projects. None of the subsidiaries' purchased power contracts is capitalized since there are no minimum payment requirements absent associated kWh generation. The 1993 increase in other purchased power reflects efforts to conserve coal during the UMWA dispute. Other purchased power continued to increase in 1994 because of increased sales to retail customers combined with generating unit outages in the first quarter of 1994. The increase in other operation expense in 1994 resulted primarily from a decision to increase the allowances for uncollectible accounts ($9 million), increases in salaries and wages ($5 million) and employee benefit costs, primarily pension expense ($6 million) and other postretirement benefits ($3 million), and provisions for environmental liabilities ($3 million). Allowances for uncollectible accounts were increased due to an increase in aged outstanding receivables caused by customers taking advantage of rate regulations which make it difficult if not impossible to curtail service to non-paying customers during the winter months. In a continuing effort to control salary and wage expenses and to improve the overall efficiency of the Company in a competitive environment, the Company has an ongoing program to consolidate various related functions within the subsidiaries. The increase in pension expense occurred because the subsidiaries in 1994 discontinued the practice of deferring SFAS No. 87 pension expense in Pennsylvania and West Virginia to reflect recent rate case decisions in those states. Pension expense in 1994 also includes a charge of $3.1 million for write-off of prior SFAS No. 87 deferrals in West Virginia because recovery of those deferrals was denied in the most recent rate cases. During 1992, the subsidiaries implemented significant changes to their benefits plans, including cost caps, in an effort to both control and reduce employee benefits costs. The cost caps provide for future post-retirement medical benefit costs to be capped at two times 1993 levels. Approximately $1 million of the $3 million increase in postretirement benefit expenses for 1994 was due to the 1993 cost cap being greater than actuarily projected. The adoption of SFAS No. 106 in 1993 increased 1993 postretirement benefit expense by approximately $5 million. The increase in other operation expense for 1993 resulted primarily from increases in employee benefit costs and salaries and wages. Another FASB standard, SFAS No. 112, "Employers' Accounting for Postemployment Benefits", effective in 1994, requires companies to accrue for other postemployment benefits such as disability benefits, health care benefits

M-3 for disabled employees, severance pay, and workers' compensation claims. The subsidiaries currently accrue for workers' compensation claims, and the estimated liability for the other benefits is not material. Maintenance expenses represent costs incurred to maintain the power stations, the transmission and distribution (T&D) system, and general plant, and reflect routine maintenance of equipment and rights-of-way as well as planned major repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. The subsidiaries are also experiencing, and expect to continue to experience, increased expenditures due to the aging of their power stations. Variations in maintenance expense result primarily from unplanned events and planned major projects, which vary in timing and magnitude depending upon the length of time equipment has been in service without a major overhaul, the amount of work found necessary when the equipment is dismantled, and outage requirements to comply with the CAAA. Maintenance expense in 1993 includes the effects of an ice storm and blizzard in March 1993. Depreciation expense increases resulted primarily from additions to electric plant. On November 16, 1994, the subsidiaries declared the Harrison scrubbers available for service and started depreciation on them amounting to $32 million annually. Taxes other than income increased $4 million in 1994 primarily due to increases in gross receipts taxes resulting from higher revenues from retail customers. The 1993 increase ($4 million) resulted from increases in gross receipts taxes ($5 million) and increased property taxes ($2 million) offset by decreased West Virginia Business and Occupation taxes due to decreased generation in that state. The net increase of $2 million in federal and state income taxes in 1994 resulted primarily from an increase in income before taxes. The net increase in 1993 of $13 million resulted primarily from an increase in income before taxes ($9 million) and an increase in the tax due to the Revenue Reconciliation Act of 1993 ($3 million). Note B to the consolidated financial statements provides a further analysis of income tax expenses. The 1994 combined decrease of $2 million in allowances for funds used during construction (AFUDC), as well as the 1993 combined increase of $4 million, reflect variations in construction expenditures including those associated with the CAAA, net of CAAA amounts included in rate base and earning a cash return. Future levels of AFUDC can be expected to decrease upon substantial completion of Phase I of the CAAA compliance program. Other income and deductions in 1994 reflect the write-off of $5.3 million net of income taxes of previously accumulated costs related to future facilities which are no longer considered meaningful in the industry's more competitive environment. Fluctuations in other income, net, were individually insignificant. Other interest expense reflects changes in the levels of short-term debt maintained by the companies throughout the year, as well as the associated interest rates. The increase in dividends on preferred stock of the subsidiaries reflects the issuance in May 1994 of $50 million of preferred stock with a dividend rate of $7.73 per share. LIQUIDITY AND CAPITAL RESOURCES SEC regulations define "liquidity" as "the ability of an enterprise to generate adequate amounts of cash to meet the enterprise's need for cash". System companies need cash for operating expenses, the payment of interest and dividends, retirement of debt and certain preferred stocks, and for their construction programs. To meet these needs, the companies have used internally generated funds and external financings, such as the sale of common and preferred stock, debt instruments, installment loans, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, the companies' cash needs, and capitalization ratio objectives. The availability and cost of external financing depend upon the financial health of the companies seeking those funds. CAPITAL REQUIREMENTS Construction expenditures for 1994 were $508 million and for 1995 and 1996 are estimated at $341 million and $284 million, respectively. These estimates include $61 million and $7 million, respectively, for substantial completion of the program of complying with Phase I of the CAAA discussed under ENVIRONMENTAL MATTERS on page 10. Annual construction expenditures through 1998 are not expected to significantly exceed 1995 estimated levels. Construction expenditure levels in 1999 and beyond will depend upon the strategy eventually selected for complying with Phase II of the CAAA, as well as future generation requirements. The Harrison Scrubber Project was completed on schedule and the final cost was approximately 24% below the original budget. Primary factors contributing to the reduced cost include: (1) the absence of any major construction problems, (2) financing and material and equipment costs lower than expected, and (3) favorable rulings of state commissions allowing the inclusion of carrying costs of construction in rates in lieu of AFUDC. The possibility of new legislation which could restrict or discourage carbon dioxide emissions, either through taxation or caps, further complicates the CAAA Phase II planning process. The subsidiaries have additional capital requirements of an annual preferred stock sinking fund ($1.2 million) and debt maturities (see Note H to the consolidated financial statements). In a further effort to meet the challenges of the new competitive environment in the industry, AYP Capital, Inc., an unregulated wholly-owned subsidiary of the Company, was formed. It is intended that AYP Capital operate as an innovative and flexible organization, pursuing and developing new opportunities in unregulated markets that will strengthen the long-term competitiveness and profitability of the System. The Company has been authorized by the SEC to purchase common stock of and make capital contributions to AYP Capital in the amount of $3 million. INTERNAL CASH FLOWS Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $246 million in 1994 compared with $270 million in 1993. In 1994 the subsidiaries financed approximately 48% of their capital expenditure program through internal cash generation. Based upon the new rate case authorizations received in 1994, it is expected that close to 100% of the capital expenditure program can be financed through internal cash generation in 1995. The increase in other investments reflects the 1994 cash surrender values for secured benefit plans and a related prepayment. Materials and supplies, primarily fuel, constituted a significant use of cash in 1994 ($21 million). A new five-year National Bituminous Coal Wage Agreement was signed with the union in December 1993.

M-4 System coal inventory declined during the renegotiations due to selective mine shutdowns, and has returned to a more appropriate level. December 1992 levels reflected increases to provide for an adequate coal supply in the event of a strike. FINANCINGS During 1994, the Company issued 1,629,372 shares of common stock under its Dividend Reinvestment and Stock Purchase Plan (DRISP), and Employee Stock Ownership and Savings Plan (ESOSP) for $35.0 million. During 1994, the subsidiaries issued an aggregate of $140 million of first mortgage bonds having interest rates of 8% to 8.125%, an aggregate of $35 million of tax-exempt solid waste disposal notes to Harrison County, West Virginia, and $50 million of $7.73 preferred stock. Debt redemption costs are amortized over the life of the associated new bonds. Due to the significant number of refinancings which have occurred over the past three years, this balance is now about $41 million. Reduced future interest expense will more than offset these expenses. Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. Short-term debt decreased $3.8 million to $126.8 million in 1994. In 1992, the Company and its subsidiaries established an internal money pool whereby surplus funds of the Company and certain subsidiaries may be borrowed on a short-term basis by the Company's subsidiaries. This has contributed to the continued low temporary cash investment amounts. At December 31, 1994, unused lines of credit with banks were $202 million. In addition, a multi-year credit program established in January 1994 provides the subsidiaries with the ability to borrow on a standby revolving credit basis up to $300 million. After the initial three-year term, the program agreement provides that the maturity date may be extended in one-year increments. There were no borrowings under this facility in 1994. During 1995, the subsidiaries have no current plans to issue new securities; however, if economic and market conditions make it desirable, they may refinance up to $783 million of first mortgage bonds, preferred stock, and pollution control revenue notes. The subsidiaries may also engage in additional Harrison County tax-exempt solid waste disposal financings to the extent that funds and qualified properties are available. The Company plans to continue DRISP/ESOSP common stock sales. The subsidiaries anticipate that they will be able to meet their future cash needs through internal cash generation and external financings, as they have in the past, and possibly through alternative financing procedures. ENVIRONMENTAL MATTERS AND OTHER CONTINGENCIES In the normal course of business, the subsidiaries are subject to various contingencies and uncertainties relating to their operations and construction programs, including cost recovery in the regulatory process, laws, regulations and uncertainties related to environmental matters, and legal actions. Contingencies and uncertainties related to the CAAA are discussed above and under Note J to the consolidated financial statements. The subsidiaries previously reported that the Environmental Protection Agency (EPA) had identified them and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. A Remedial Investigation/Feasibility Study prepared by the EPA indicates remedial alternatives which range as high as $113 million, to be shared by all responsible parties. The EPA has not yet selected which remedial alternatives it will use. The subsidiaries believe they have defenses to allegations of liability and intend to vigorously defend this matter. Although it is not possible at this time to determine what costs, if any, the subsidiaries may incur, they have recorded provisions for liabilities based on the range of remediation cost estimates and their relative participation, along with the approximately 875 others. The subsidiaries believe that provisions for liabilities and insurance recoveries are such that final resolution of this matter will not have a material effect on their financial position. Monongahela has been named as a defendant along with multiple other defendants in 1,625 pending asbestos cases involving one or more plaintiffs; Monongahela, Potomac Edison, and West Penn have been named as defendants along with multiple other defendants in an additional 716 cases by one or more plaintiffs. Because these cases are filed by "shotgun" complaints naming many plaintiffs and many defendants, it is currently impossible to determine the actual number of claims against the subsidiaries. However, based on past experience and data available to date, it is estimated that less than 500 cases actually involve claims against any or all of the subsidiaries. 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. All plaintiffs claiming exposure at subsidiary-operated stations were employed by third-party contractors, with the exception of three known plaintiffs who claim to have been 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 that 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. Because of the multiple defendants, the subsidiaries believe their potential liability is a very small percentage of the total amount of the damages sought. A total of 94 cases have been previously settled by Monongahela for an amount substantially less than the anticipated cost of defense. The subsidiaries believe that the remaining cases involving them are without merit and that provisions for liabilities and insurance recoveries are such that these suits will not have a material effect on their financial position.

M-5 Monongahela MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Net Income Net income was $67.9 million in 1994, including $7.9 million of non-recurring income from the cumulative effect of an accounting change to record unbilled revenues. Net income was $61.7 million and $58.3 million in 1993 and 1992, respectively. Net income in 1994 and 1993 continue to reflect increases in revenues from retail customers resulting from increased kWh sales and retail rate increases. The decrease in 1994 income before the accounting change resulted primarily from higher expenses, including taxes, pension expense, and depreciation. The subject of competition for customers, particularly industrial customers, has been receiving a lot of attention. In 1994 the Ohio commission started a proceeding described as an informal roundtable discussion into the subject, which is still in progress. This process is not expected to result in immediately meaningful changes in current relations with our customers. All customers, except wholesale customers regulated by the Federal Energy Regulatory Commission (FERC), continue to be required to purchase their electricity requirements from the utility in whose franchised territory they reside. This is not to say that competition does not exist. Utilities continue to compete for the siting of new industrial and commercial customers, to retain existing customers in the franchised territory, and, for those businesses with multiple plants in multiple territories, to maintain or shift their production to local facilities. As in the past, electric utilities continue to compete with suppliers of other forms of energy. Because the Company is among the lowest cost suppliers of electricity in its region, it should not experience the competitive concerns of other utilities who use cost-based pricing. However, the Company continues to face competition from utilities with excess generation that are willing to sell at prices intended only to recover variable costs. Sales and Revenues KWh sales to and revenues from residential, commercial, and industrial customers are shown on pages 16 and 17. Such kWh sales increased 3.2% and .3% in 1994 and 1993, respectively. The increases in revenues from sales to residential, commercial, and industrial customers resulted from the following: Increase from Prior Year 1994 1993 (Millions of Dollars) Increased kWh sales $ 3.8 $ 6.6 Fuel and energy cost adjustment clauses* 13.0 11.8 Rate increases: West Virginia 7.9 4.1 Ohio 2.1 7.9 6.2 Other 1.0 .2 $25.7 $24.8 * Changes in revenues from fuel and energy cost adjustment clauses have little effect on net income.

M-6 The increased kWh sales in 1994 reflect growth in both residential and commercial customers. The 1994 residential use was down slightly from 1993 levels reflecting a decrease in both heating and cooling degree days. The increased kWh sales to residential and commercial customers in 1993 reflect both growth in number of customers and higher use. While 1993 heating degree days showed only a slight increase over 1992, and were only 6% above normal, cooling degree days increased 54% over 1992, contributing to the 1993 kWh sales increase. Rate case decisions in West Virginia and by the FERC for wholesale customers, representing revenue increases in excess of $30 million on an annual basis, were issued for the Company in 1994. These included recovery of the remaining carrying charges on investment, depreciation, and all operating costs required to comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and other increasing levels of expense. KWh sales to industrial customers increased 6.1% in 1994 and decreased 4.4% in 1993. The 1994 increase occurred primarily from coal mining (128 gigawatt-hours [GWh], 16.1%); chemical (91 GWh, 5.3%); and primary metals customers (77 GWh, 8.3%). The increase in sales to primary metals customers was due in part to the discontinuance of one customer's use of its own generation, which contributed to 1993 decreased sales. The 1993 decrease also reflects a decline in sales to coal customers. Coal mines staffed by union personnel recorded reduced usage because of selective work stoppages by the United Mine Workers of America (UMWA) for most of the year prior to the settling of the dispute in December 1993. KWh sales to and revenues from nonaffiliated utilities are comprised of the following items: 1994 1993 1992 KWh sales (in billions): From Company generation .3 .3 1.0 From purchased power 2.1 2.8 3.6 2.4 3.1 4.6 Revenues (in millions): From Company generation $ 7.7 $ 8.4 $ 26.7 From sales of purchased power 72.0 77.6 92.9 $79.7 $86.0 $119.6 Decreased sales to nonaffiliated utilities resulted primarily from decreased demand and continuing price competition. Sales supplied by the Company's generation in 1994 continued at less than 15% of 1988 levels because of growth of kWh sales to retail customers, which reduces the amount available for sale, and because other suppliers were willing or able to make the sales at lower prices. A significant factor affecting the Company's ability to compete in the market for sales to nonaffiliated utilities has been the approximate 290% increase (from about 67 cents per MWh to $2.60 per MWh) in taxes on generation in West Virginia since March 1989 a significant cost not experienced by utilities not generating in West Virginia. Further decreases in these sales are anticipated.

M-7 The increase in other revenues in 1994 and 1993 resulted from continued increases in sales of capacity, energy, and spinning reserve to other affiliated companies because of additional capacity and energy available from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA). This increase was offset in part in 1993 by an agreement with the FERC to record in 1993 about $3 million of revenues as sales to nonaffiliated utilities. Similar transactions were recorded as other revenues in prior years. About 90% of the aggregate benefits from sales to affiliated and nonaffiliated utilities is passed on to retail customers and has little effect on net income. About $4 million of other revenues in 1994 were derived from wholesale customers regulated by the FERC who have the ability to obtain their electricity requirements from other suppliers. In the event that these customers were to select another supplier, the Company would retain transmission revenues with the result that any net income loss would not be significant. Operating Expenses Fuel expenses increased 4% in 1994 and decreased 3% in 1993, both primarily due to changes in kWh generated. Fuel expenses are primarily subject to deferred power cost accounting procedures, as described in Note A to the financial statements, with the result that changes in fuel expenses have little effect on net income. "Purchased power and exchanges, net" represents power purchases from and exchanges with nonaffiliated utilities and qualified facilities under PURPA, capacity charges paid to Allegheny Generating Company (AGC), and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and is comprised of the following items: 1994 1993 1992 (Millions of Dollars) Nonaffiliated transactions: Purchased power: For resale to other utilities $ 63.7 $ 68.6 $ 85.5 From PURPA generation 68.3 55.7 37.4 Other 9.4 8.1 3.1 Power exchanges, net (.2) (.6) .3 Affiliated transactions: AGC capacity charges 20.1 23.3 24.2 Energy and spinning reserve charges .5 .5 2.8 $161.8 $155.6 $153.3 The amount of power purchased from nonaffiliated utilities for use by the Company and for resale to nonaffiliated utilities depends upon the availability of the Company's generating equipment, transmission capacity, and fuel, and its cost of generation and the cost of operations of nonaffiliated utilities from which such purchases are made. The primary reason for the fluctuations in purchases for resale to nonaffiliated utilities is described under Sales and Revenues above. The cost of power and capacity purchased for use by the Company, including power from PURPA generation and affiliated transactions, is mostly recovered from customers currently through the regular fuel and

M-8 energy cost recovery procedures followed by the Company's regulatory commissions and is primarily subject to deferred power cost procedures with the result that changes in such costs have little effect on net income. The increases in purchases from PURPA generation reflects additional generation from new PURPA projects. None of the Company's purchased power contracts is capitalized since there are no minimum payment requirements absent associated kWh generation. The 1993 increase in other purchased power reflects efforts to conserve coal during the UMWA dispute. Other purchased power continued to increase in 1994 because of increased sales to retail customers combined with generating unit outages in the first quarter of 1994. Energy and spinning reserve charges decreased in 1993 primarily because of additional generation available from PURPA projects. The increase in other operation expense in 1994 resulted primarily from increases in pension expense ($4 million), allowance for uncollectible accounts ($1 million), and salaries and wages ($1 million). The increase in pension expense occurred because the Company in 1994 discontinued the practice of deferring SFAS No. 87 pension expense in West Virginia to reflect the recent rate case decision. Pension expense in 1994 also includes a charge of $2.5 million for write-off of prior SFAS No. 87 deferrals in West Virginia because recovery of those deferrals was denied in the most recent rate case. In a continuing effort to control salary and wage expenses and to improve the overall efficiency of the Company in a competitive environment, the Allegheny Power System has an ongoing program to consolidate various related functions within the System. The increase in other operation expense for 1993 resulted primarily from increases in salaries and wages and employee benefit costs. During 1992, the Company implemented significant changes to its benefits plans, including cost caps, in an effort to both control and reduce employee benefit costs. The cost caps provide for future postretirement medical benefit costs to be capped at two times 1993 levels. The adoption of SFAS No. 106 in 1993 increased 1993 postretirement benefit expense by approximately $2 million. Another FASB standard, SFAS No. 112, "Employers' Accounting for Postemployment Benefits", effective in 1994, requires companies to accrue for other postemployment benefits such as disability benefits, health care benefits for disabled employees, severance pay, and workers' compensation claims. The Company currently accrues for workers' compensation claims, and the estimated liability for the other benefits is not material. Maintenance expenses represent costs incurred to maintain the power stations, the transmission and distribution (T&D) system, and general plant, and reflect routine maintenance of equipment

M-9 and rights-of-way as well as planned major repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. In early January 1994, the Company experienced the worst storm in its history. The expenses were deferred and are being amortized over a five-year period beginning in November 1994, concurrent with recovery from customers. The Company is also experiencing, and expects to continue to experience, increased expenditures due to the aging of its power stations. Variations in maintenance expense result primarily from unplanned events and planned major projects, which vary in timing and magnitude depending upon the length of time equipment has been in service without a major overhaul, the amount of work found necessary when the equipment is dismantled, and outage requirements to comply with the CAAA. Depreciation expense increases resulted primarily from additions to electric plant. On November 16, 1994, the Company declared the Harrison scrubbers available for service and started depreciation on them amounting to $8 million annually. The 1994 depreciation expense increase was offset in part by a decrease in depreciation rates in West Virginia of about $7 million annually effective in November 1994, concurrent with the base rate increase. A further reduction of about $4 million annually effective in January 1996, will result in depreciation rates for the Company which are comparable to those of other electric utilities, particularly those providing service in West Virginia. Taxes other than income increased $6 million in 1994 primarily due to an increase in West Virginia Business and Occupation taxes resulting from prior period adjustments recorded in 1993 and 1992. The 1993 increase ($1 million) was due primarily to increases in gross receipts taxes resulting from higher revenues from retail customers. The net decrease of $3 million in federal and state income taxes in 1994 resulted primarily from a decrease in income before taxes ($2 million) and the reversal of a provision for prior years which is no longer needed ($2 million). The net increase in 1993 of $6 million resulted primarily from an increase in income before taxes ($4 million), and an increase in the tax rate due to the Revenue Reconciliation Act of 1993 ($1 million). Note B to the financial statements provides a further analysis of income tax expenses. The 1994 combined decrease of $3 million in allowances for funds used during construction (AFUDC), as well as the 1993 combined increase of $2 million, reflect variations in construction expenditures including those associated with the CAAA, net of CAAA amounts included in rate base and earning a cash return. Future levels of AFUDC can be expected to decrease upon substantial completion of Phase I of the CAAA compliance program. The changes in other income, net, in 1994 and 1993 resulted primarily from the Company's share of earnings of AGC (see Note D to the financial statements). Other fluctuations in other income, net, were individually insignificant. Other interest expense reflects changes in the levels of short-term debt maintained by the Company throughout the year, as well as the associated interest rates. Liquidity and Capital Resources SEC regulations define "liquidity" as "the ability of an enterprise to generate adequate amounts of cash to meet the enterprise's need for cash". The Company needs cash for operating expenses, the payment of interest and dividends, retirement of debt, and for its construction program. To meet these needs, the Company has used internally generated funds and external financings, such as the sale of common and preferred stock, debt instruments, installment loans, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, the Company's cash needs, and capitalization ratio objectives. The availability and cost of external financing depend upon the financial health of the companies seeking those funds. Capital Requirements Construction expenditures for 1994 were $104 million and for 1995 and 1996 are estimated at $74 million and $70 million, respectively. These estimates include $11 million and $2 million, respectively, for substantial completion of the program of complying with Phase I of the CAAA. Annual construction expenditures through 1998, on average, are not expected to significantly exceed 1995 estimated levels. Construction expenditure levels in 1999 and beyond will depend upon the strategy eventually selected for complying with Phase II of the CAAA, as well as future generation requirements. The Harrison Scrubber Project was completed on schedule and the final cost was approximately 24% below the original budget. Primary factors contributing to the reduced cost include: (1) the absence of any major construction problems, (2) financing and material and equipment costs lower than expected, and (3) favorable rulings of state commissions allowing the inclusion of carrying costs of construction in rates in lieu of AFUDC. The possibility of new legislation which could restrict or discourage carbon dioxide emissions, either through taxation or caps, further complicates the CAAA Phase II planning process. The Company has additional capital requirements of debt maturities (see Note I to the financial statements). Internal Cash Flows Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $67 million in 1994 compared with $69 million in 1993. In 1994 the Company financed

M-10 approximately 64% of its capital expenditure program through internal cash generation. Based upon the new rate case authorizations received in 1994 and an Ohio rate case filed in January 1995, it is expected that close to 100% of the capital expenditure program can be financed through internal cash generation in 1995. Materials and supplies, primarily fuel, constituted a significant use of cash in 1994 ($6 million). A new five-year National Bituminous Coal Wage Agreement was signed with the union in December 1993. System coal inventory declined during the renegotiations due to selective mine shutdowns, and has returned to a more appropriate level. December 1992 levels reflected increases to provide for an adequate coal supply in the event of a strike. Financings During 1994, the Company issued $50 million of $7.73 preferred stock and $8.83 million of tax-exempt solid waste disposal notes to Harrison County, West Virginia. Due to the significant number of refinancings which have occurred over the past three years, the balance of debt redemption costs is now about $11 million. These costs are being amortized over the life of the associated new bonds. Reduced future interest expense will more than offset these expenses. Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. Short-term debt, including notes payable to affiliates under the money pool, decreased $23.6 million to $39.5 million in 1994. In 1992, the Company and its affiliates established an internal money pool as a facility to accommodate intercompany short-term borrowing needs, to the extent that certain of the companies have funds available. The internal money pool has contributed to the continued low temporary cash investment amounts. At December 31, 1994, the Company had SEC authorization to issue up to $100 million of short-term debt. In addition, a multi-year credit program established in January 1994 provides the Company with the ability to borrow on a standby revolving credit basis up to $81 million. After the initial three-year term, the program agreement provides that the maturity date may be extended in one-year increments. There were no borrowings under this facility in 1994. During 1995, the Company has no current plans to issue new securities; however, if economic and market conditions make it desirable, it may refinance up to $300 million of first mortgage bonds, preferred stock, and pollution control revenue notes. The Company may also engage in additional Harrison County tax-exempt solid waste disposal financings to the extent that funds and qualified properties are available.

M-11 The Company anticipates that it will be able to meet its future cash needs through internal cash generation and external financings, as it has in the past, and possibly through alternative financing procedures. Environmental Matters and Other Contingencies In the normal course of business, the Company is subject to various contingencies and uncertainties relating to its operations and construction programs, including cost recovery in the regulatory process, laws, regulations and uncertainties related to environmental matters, and legal actions. Contingencies and uncertainties related to the CAAA are discussed above and under Note K to the financial statements. The Company previously reported that the Environmental Protection Agency (EPA) had identified it and its affiliates and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. A Remedial Investigation/Feasibility Study prepared by the EPA indicates remedial alternatives which range as high as $113 million, to be shared by all responsible parties. The EPA has not yet selected which remedial alternatives it will use. The Company believes it has defenses to allegations of liability and intends to vigorously defend this matter. Although it is not possible at this time to determine what costs, if any, the Company may incur, it has recorded provisions for liabilities based on the range of remediation cost estimates and its relative participation, along with the approximately 875 others. The Company believes that provisions for liabilities and insurance recoveries are such that final resolution of this matter will not have a material effect on its financial position. The Company has been named as a defendant along with multiple other defendants in 1,625 pending asbestos cases involving one or more plaintiffs, and the Company and its affiliates have been named as defendants along with multiple other defendants in an additional 716 cases by one or more plaintiffs. Because these cases are filed by "shotgun" complaints naming many plaintiffs and many defendants, it is currently impossible to determine the actual number of claims against the Company and its affiliates. However, based on past experience and data available to date, it is estimated that less than 500 cases actually involve claims against the Company or its affiliates. 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. All plaintiffs claiming exposure at

M-12 System-operated stations were employed by third-party contractors, with the exception of three known plaintiffs who claim to have been employees of the Company. 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 that 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. Because of the multiple defendants, the Company believes its potential liability is a very small percentage of the total amount of the damages sought. A total of 94 cases have been previously settled by the Company for an amount substantially less than the anticipated cost of defense. The Company believes that the remaining cases involving it are also without merit and that provisions for liabilities and insurance recoveries are such that these suits will not have a material effect on its financial position.

M-13 Potomac Edison MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Net Income Net income was $98.5 million in 1994, including $16.5 million of non-recurring income from the cumulative effect of an accounting change to record unbilled revenues. Net income was $73.5 million and $67.5 million in 1993 and 1992, respectively. The 1994 and 1993 increases in net income resulted primarily from kWh sales and retail rate increases. These revenue increases, in both years, were offset in part by higher expenses. The subject of competition for customers, particularly industrial customers, has been receiving a lot of attention. In 1994 the Maryland commission started a proceeding described as an inquiry into the subject, which is still in progress. The inquiry is not expected to result in immediately meaningful changes in current relations with our customers. All customers, except wholesale customers regulated by the Federal Energy Regulatory Commission (FERC), continue to be required to purchase their electricity requirements from the utility in whose franchised territory they reside. This is not to say that competition does not exist. Utilities continue to compete for the siting of new industrial and commercial customers, to retain existing customers in the franchised territory, and, for those businesses with multiple plants in multiple territories, to maintain or shift their production to local facilities. As in the past, electric utilities continue to compete with suppliers of other forms of energy. Because the Company is the lowest or among the lowest cost suppliers of electricity in its region, it should not experience the competitive concerns of other utilities who use cost-based pricing. However, the Company continues to face competition from utilities with excess generation that are willing to sell at prices intended only to recover variable costs. Sales and Revenues KWh sales to and revenues from residential, commercial, and industrial customers are shown on pages 16 and 17. Such kWh sales increased 2.3% and 6.3% in 1994 and 1993, respectively. The increases in revenues from sales to residential, commercial, and industrial customers resulted from the following: Increase from Prior Year 1994 1993 (Millions of Dollars) Increased kWh sales $10.3 $24.4 Fuel and energy cost adjustment clauses* 18.6 19.1 Rate increases: Maryland 11.9 12.7 Virginia 8.5 2.5 West Virginia 1.9 1.1 22.3 16.3 Other 1.0 2.9 $52.2 $62.7 * Changes in revenues from fuel and energy cost adjustment clauses have little effect on net income.

M-14 The increased kWh sales in 1994 reflect growth in the number of customers and higher use by industrial customers. The 1994 residential use was down slightly from 1993 levels reflecting a decrease in both heating and cooling degree days. The increased kWh sales to residential and commercial customers in 1993 reflect both higher use and growth in number of customers. While 1993 heating degree days showed only a slight increase over 1992, and were only 7% above normal, cooling degree days increased 82% over 1992 and were 12% over normal, contributing to the 1993 kWh sales increases. Rate case decisions in all retail jurisdictions, representing revenue increases in excess of $33 million on an annual basis, were issued for the Company in 1994. These included recovery of the remaining carrying charges on investment, depreciation, and all operating costs required to comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and other increasing levels of expense. KWh sales to industrial customers increased 2.8% in 1994 and 4.3% in 1993. The increase in both years occurred in almost all industrial groups, the most significant of which in 1994 was from rubber and plastics customers (61 gigawatt-hours [GWh], 22%) and in 1993 was from cement customers (59 GWh, 12%). KWh sales to and revenues from nonaffiliated utilities are comprised of the following items: 1994 1993 1992 KWh sales (in billions): From Company generation .3 .4 1.0 From purchased power 2.9 3.5 4.4 3.2 3.9 5.4 Revenues (in millions): From Company generation $ 8.9 $ 8.6 $ 27.5 From sales of purchased power 98.1 99.5 113.6 $107.0 $108.1 $141.1 Decreased sales to nonaffiliated utilities resulted primarily from decreased demand and continuing price competition. Sales supplied by the Company's generation in 1994 continued at less than 15% of 1988 levels because of continuing growth of kWh sales to retail customers, which reduces the amount available for sale, and because other suppliers were willing or able to make the sales at lower prices. A significant factor affecting the Company's ability to compete in the market for sales to nonaffiliated utilities has been the approximate 290% increase (from about 67 cents MWh to $2.60 per MWh) in taxes on generation in West Virginia since March 1989 - a significant cost not experienced by utilities not generating in West Virginia. Further decreases in these sales are anticipated. About 95% of the aggregate benefits from sales to nonaffiliated utilities is passed on to retail customers and has little effect on net income.

M-15 The decrease in other revenues in 1994 resulted from provisions for rate refunds recorded in 1994 for the 1993 and 1994 Virginia base rate increase requests, collected from customers subject to refund. A final order for the 1993 case has been received and refunds will be made to customers in early 1995. Commission approval of a settlement agreement for the 1994 request is pending. About $23 million of other revenues in 1994 were derived from wholesale customers regulated by the FERC who have the ability to obtain their electricity requirements from other suppliers. In the event that these customers were to select another supplier, the Company would retain transmission service revenues. The decrease in other revenues in 1993 resulted from an agreement with the FERC to record in 1993 about $4 million of revenues as sales to nonaffiliated utilities. Similar transactions were recorded as other revenues in prior years. Operating Expenses Fuel expenses increased 1% in 1994 and decreased 4% in 1993, both primarily due to changes in kWh generated. Fuel expenses are primarily subject to deferred power cost accounting procedures, as described in Note A to the financial statements, with the result that changes in fuel expenses have little effect on net income. "Purchased power and exchanges, net" represents power purchases from and exchanges with nonaffiliated utilities, capacity charges paid to Allegheny Generating Company (AGC), and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and is comprised of the following items: 1994 1993 1992 (Millions of Dollars) Nonaffiliated transactions: Purchased power: For resale to other utilities $ 86.5 $ 87.9 $104.6 Other 12.7 10.5 3.7 Power exchanges, net (.2) (.8) .2 Affiliated transactions: AGC capacity charges 29.4 28.0 29.6 Other affiliated capacity charges 37.6 28.4 21.9 Energy and spinning reserve charges 51.1 51.1 41.2 $217.1 $205.1 $201.2 The amount of power purchased from nonaffiliated utilities for use by the Company and for resale to nonaffiliated utilities depends upon the availability of the Company's generating equipment, transmission capacity, and fuel, and its cost of generation and the cost of operations of nonaffiliated utilities from which such purchases are made. The primary reason for the fluctuations in purchases for resale to nonaffiliated utilities is described under Sales and Revenues above. The cost of power purchased from nonaffiliates for use by the Company, AGC capacity charges in West Virginia, and affiliated energy and spinning reserve charges are mostly recovered from customers currently through the regular fuel and energy cost recovery procedures followed by the Company's regulatory commissions and is primarily

M-16 subject to deferred power cost procedures with the result that changes in such costs have little effect on net income. The 1993 increase in other purchased power reflects efforts to conserve coal because of selective work stoppages by the United Mine Workers of America for most of the year. Other purchased power continued to increase in 1994 because of increased sales to retail customers combined with generating unit outages in the first quarter of 1994. While the Company does not currently purchase generation from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA), several projects have been proposed, and an agreement has been reached with one facility to commence purchasing generation in 1999. This project and others may significantly increase the cost of power purchases passed on to customers. The increase in affiliated capacity in 1994 and 1993 and energy and spinning reserve charges in 1993 was due to growth of kWh sales to retail customers and an increase in affiliated energy available because of energy purchased by an affiliate from PURPA projects. The increase in other operation expense in 1994 resulted primarily from demand-side management program costs ($1 million) and cogeneration project expenses ($1 million), both of which are being recovered from customers, provisions for environmental liabilities ($1 million), and increases in affiliated company charges for transmission service ($2 million), salaries and wages ($1 million), and employee benefit costs ($1 million), primarily pension expense and other postretirement benefits. In a continuing effort to control salary and wage expenses and to improve the overall efficiency of the Company in a competitive environment, the Allegheny Power System has an ongoing program to consolidate various related functions within the System. The increase in pension expense occurred because the Company in 1994 discontinued the practice of deferring SFAS No. 87 pension expense in West Virginia to reflect a recent rate case decision. Pension expense in 1994 also includes a charge of $.9 million for write-off of prior SFAS No. 87 deferrals in Virginia and West Virginia because recovery of those deferrals was denied in the most recent rate cases. During 1992, the Company implemented significant changes to its benefits plans, including cost caps, in an effort to both control and reduce employee benefits costs. The cost caps provide for future postretirement medical benefit costs to be capped at two times 1993 levels. Approximately $.6 million of the increase in postretirement benefit expenses for 1994 was due to the 1993 cost cap being greater than actuarily projected. The adoption of SFAS No. 106 in 1993 increased 1993 postretirement benefit expense by approximately $1.5 million. The increase in other operation expense for 1993 resulted primarily from increases in employee benefit costs and salaries and wages. Another FASB standard, SFAS No. 112, "Employers' Accounting for Postemployment Benefits", effective in 1994, requires companies to accrue for other postemployment benefits such as disability benefits, healthcare benefits for disabled employees, severance

M-17 pay, and workers' compensation claims. The Company currently accrues for workers' compensation claims, and the estimated liability for the other benefits is not material. Maintenance expenses represent costs incurred to maintain the power stations, the transmission and distribution (T&D) system, and general plant, and reflect routine maintenance of equipment and rights-of-way as well as planned major repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. The Company is also experiencing, and expects to continue to experience, increased expenditures due to the aging of its power stations. Variations in maintenance expense result primarily from unplanned events and planned major projects, which vary in timing and magnitude depending upon the length of time equipment has been in service without a major overhaul, the amount of work found necessary when the equipment is dismantled, and outage requirements to comply with the CAAA. Depreciation expense increases resulted primarily from additions to electric plant. On November 16, 1994, the Company declared the Harrison scrubbers available for service and started depreciation on them amounting to $10 million annually. Taxes other than income increased $1 million in 1993 due to increases in gross receipts taxes resulting from higher revenues from retail customers ($1 million) and increased property taxes ($1 million), offset by decreased West Virginia Business and Occupation taxes due to decreased generation in that state ($1 million). The net increase of $3 million in federal and state income taxes in 1994 resulted primarily from an increase in income before taxes. The net increase in 1993 of $2 million in federal and state income taxes resulted primarily from an increase in income before taxes ($3 million) and an increase in the tax rate due to the Revenue Reconciliation Act of 1993 ($1 million), offset by plant removal tax deductions for which deferred taxes were not provided ($1 million). Note B to the financial statements provides a further analysis of income tax expenses. The 1994 combined decrease of $1 million in allowances for funds used during construction (AFUDC), as well as the 1993 combined increase of $2 million, reflect variations in construction expenditures including those associated with the CAAA, net of CAAA amounts included in rate base and earning a cash return. Future levels of AFUDC can be expected to decrease upon substantial completion of Phase I of the CAAA compliance program. The changes in other income, net, in 1994 and 1993 resulted primarily from the Company's share of earnings of AGC (see Note D to the financial statements) and in 1994 also from lost revenue and interest income for demand-side management programs. Other fluctuations in other income, net, were individually insignificant. Other interest expense reflects changes in the levels of short-term debt maintained by the Company throughout the year, as well as the associated interest rates.

M-18 Liquidity and Capital Resources SEC regulations define "liquidity" as "the ability of an enterprise to generate adequate amounts of cash to meet the enterprise's need for cash". The Company needs cash for operating expenses, the payment of interest and dividends, retirement of debt and certain preferred stock, and for its construction program. To meet these needs, the Company has used internally generated funds and external financings, such as the sale of common and preferred stock, debt instruments, installment loans, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, the Company's cash needs, and capitalization ratio objectives. The availability and cost of external financing depend upon the financial health of the companies seeking those funds. During 1994, the Company continued its participation in the Collaborative Process for Demand-Side Management in Maryland. Through December 31, 1994, the Company had received applications for $16.1 million in rebates related to the commercial lighting program. Program costs, including rebates and lost revenues, are deferred and are to be recovered through an energy conservation surcharge over a seven-year period. Capital Requirements Construction expenditures for 1994 were $143 million and for 1995 and 1996 are estimated at $92 million and $98 million, respectively. These estimates include $12 million and $5 million, respectively, for substantial completion of the program of complying with Phase I of the CAAA. Annual construction expenditures through 1998, on average, are not expected to significantly exceed 1995 estimated levels. Construction expenditure levels in 1999 and beyond will depend upon the strategy eventually selected for complying with Phase II of the CAAA, as well as future generation requirements. The Harrison Scrubber Project was completed on schedule and the final cost was approximately 24% below the original budget. Primary factors contributing to the reduced cost include: (1) the absence of any major construction problems, (2) financing and material and equipment costs lower than expected, and (3) favorable rulings of state commissions allowing the inclusion of carrying costs of construction in rates in lieu of AFUDC. The possibility of new legislation which could restrict or discourage carbon dioxide emissions, either through taxation or caps, further complicates the CAAA Phase II planning process. The Company has additional annual capital requirements of an annual preferred stock sinking fund ($1.2 million) and debt maturities (see Note I to the financial statements).

M-19 Internal Cash Flows Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $67 million in 1994 compared with $75 million in 1993. In 1994 the Company financed approximately 47% of its capital expenditure program through internal cash generation. Based upon the new rate case authorizations received in 1994, it is expected that close to 100% of the capital expenditure program can be financed through internal cash generation in 1995. Materials and supplies, primarily fuel, constituted a significant use of cash in 1994 ($5 million). A new five-year National Bituminous Coal Wage Agreement was signed with the union in December 1993. System coal inventory declined during the renegotiations due to selective mine shutdowns, and has returned to a more appropriate level. December 1992 levels reflected increases to provide for an adequate coal supply in the event of a strike. Financings During 1994, the Company issued $75 million of 8% first mortgage bonds and $11.56 million of tax-exempt solid waste disposal notes to Harrison County, West Virginia. Due to the significant number of refinancings which have occurred over the past three years, the balance of debt redemption costs is now about $8 million. These costs are being amortized over the life of the associated new bonds. Reduced future interest expense will more than offset these expenses. Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. In 1992, the Company and its affiliates established an internal money pool as a facility to accommodate intercompany short-term borrowing needs, to the extent that certain of the companies have funds available. The internal money pool has contributed to the continued low temporary cash investment amounts. At December 31, 1994, the Company had SEC authorization to issue up to $115 million of short-term debt. In addition, a multi-year credit program established in January 1994 provides the Company with the ability to borrow on a standby revolving credit basis up to $84 million. After the initial three-year term, the program agreement provides that the maturity date may be extended in one-year increments. There were no borrowings under this facility in 1994. During 1995, the Company has no current plans to issue new securities; however, if economic and market conditions make it desirable, it may refinance up to $231 million of first mortgage bonds, preferred stock, and pollution control revenue notes. The Company may also engage in addi- tional Harrison County tax-exempt solid waste disposal financings to the extent that funds and qualified properties are available. The Company anticipates that it will be able to meet its future cash needs through internal cash generation and external financings, as it has in the past, and possibly through alternative financing procedures.

M-20 Environmental Matters and Other Contingencies In the normal course of business, the Company is subject to various contingencies and uncertainties relating to its operations and construction programs, including cost recovery in the regulatory process, laws, regulations and uncertainties related to environmental matters, and legal actions. Contingencies and uncertainties related to the CAAA are discussed above and under Note K to the financial statements. The Company previously reported that the Environmental Protection Agency (EPA) had identified it and its affiliates and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. A Remedial Investigation/Feasibility Study prepared by the EPA indicates remedial alternatives which range as high as $113 million, to be shared by all responsible parties. The EPA has not yet selected which remedial alternatives it will use. The Company believes it has defenses to allegations of liability and intends to vigorously defend this matter. Although it is not possible at this time to determine what costs, if any, the Company may incur, it has recorded provisions for liabilities based on the range of remediation cost estimates and its relative participation, along with the approximately 875 others. The Company believes that provisions for liabilities and insurance recoveries are such that final resolution of this matter will not have a material effect on its financial position. Monongahela Power Company (MP), an affiliated company, has been named as a defendant along with multiple other defendants in 1,625 pending asbestos cases involving one or more plaintiffs, and the Company and its affiliates have been named as defendants along with multiple other defendants in an additional 716 cases by one or more plaintiffs. Because these cases are filed by "shotgun" complaints naming many plaintiffs and many defendants, it is currently impossible to determine the actual number of claims against the Company and its affiliates. However, based on past experience and data available to date, it is estimated that less than 500 cases actually involve claims against the Company or its affiliates. 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. All plaintiffs claiming exposure at System-operated stations were employed by third-party contractors, with the exception of three known plaintiffs who claim to have been employees of MP. The Company is joint owner with MP in five generating plants, including four operated by MP in West Virginia. 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 that 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. Because of the multiple defendants, the Company believes its potential liability is a very small percentage of the total amount of the damages sought. A total of 94 cases have been previously settled by MP for an amount substantially less than the anticipated cost of defense. The Company believes that the remaining cases involving it are also without merit and that provisions for liabilities and insurance recoveries are such that these suits will not have a material effect on its financial position.

M-21 West Penn MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Consolidated Net Income Consolidated net income was $120.0 million in 1994, including $19.0 million of non-recurring income from the cumulative effect of an accounting change to record unbilled revenues. The 1994 results also reflect the write-off ($5.2 million after tax) of previously accumulated costs related to future facilities no longer considered meaningful in the industry's more competitive environment. Consolidated net income was $102.1 million and $98.2 million in 1993 and 1992, respectively. The 1994 and 1993 increases in consolidated net income resulted primarily from kWh sales and retail rate increases. These revenue increases, in both years, were offset in part by higher expenses. The subject of competition for customers, particularly industrial customers, has been receiving a lot of attention. In 1994 the Pennsylvania commission initiated an investigation into the subject, which is still in progress. The inquiry is not expected to result in immediately meaningful changes in current relations with our customers. All customers, except wholesale customers regulated by the Federal Energy Regulatory Commission (FERC), continue to be required to purchase their electricity requirements from the utility in whose franchised territory they reside. This is not to say that competition does not exist. Utilities continue to compete for the siting of new industrial and commercial customers, to retain existing customers in the franchised territory, and, for those businesses with multiple plants in multiple territories, to maintain or shift their production to local facilities. As in the past, electric utilities continue to compete with suppliers of other forms of energy. Because the Company is the lowest or among the lowest cost suppliers of electricity in its region, it should not experience the competitive concerns of other utilities who use cost-based pricing. However, the Company continues to face competition from utilities with excess generation that are willing to sell at prices intended only to recover variable costs. Sales and Revenues KWh sales to and revenues from residential, commercial, and industrial customers are shown on pages 16 and 17. Such kWh sales increased 2.9% and 3.1% in 1994 and 1993, respectively. The increases in revenues from sales to residential, commercial, and industrial customers resulted from the following: Increase from Prior Year 1994 1993 (Millions of Dollars) Increased kWh sales $ 9.4 $15.5 Fuel and energy cost adjustment clauses* 16.8 26.2 Rate increases 22.7 25.2 Other 2.3 3.1 $51.2 $70.0 * Changes in revenues from fuel and energy cost adjustment clauses have little effect on consolidated net income.

M-22 The increased kWh sales to residential and commercial customers in 1994 and 1993 reflect growth in number of customers and higher commercial use. Residential usage increased in 1994 despite a decrease in both heating and cooling degree days. While 1993 heating degree days remained about the same as 1992, and were only 6% below normal, cooling degree days increased 70% over 1992 and were 46% over normal, contributing to the 1993 kWh sales increases. Rate case decisions in all jurisdictions, representing revenue increases in excess of $57 million on an annual basis, were issued for the Company in 1994. These included recovery of the remaining carrying charges on investment, depreciation, and all operating costs required to comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and other increasing levels of expenses. Rate increases also include a $61.6 million annual base rate increase in Pennsylvania effective May 18, 1993, including $26.1 million for recovery of carrying charges on CAAA compliance costs. KWh sales to industrial customers increased 4.4% in 1994 and .8% in 1993. The 1994 increase occurred in almost all industrial groups, particularly paper, printing and publishing (118 gigawatt-hours [GWh], 47.4%); fabricated metals (72 GWh, 6.9%); and iron and steel customers (53 GWh, 2.1%). The relatively flat industrial sales growth in 1993 included one particular group, coal mines staffed by union personnel, which recorded reduced usage because of selective work stoppages by the United Mine Workers of America (UMWA) for most of the year prior to the settling of the dispute in December 1993. KWh sales to and revenues from nonaffiliated utilities are comprised of the following items: 1994 1993 1992 KWh sales (in billions): From Company generation .5 .4 1.3 From purchased power 3.8 5.0 6.5 4.3 5.4 7.8 Revenues (in millions): From Company generation $ 12.3 $ 11.5 $ 37.5 From sales of purchased power 132.5 141.0 167.2 $144.8 $152.5 $204.7 Decreased sales to nonaffiliated utilities resulted primarily from decreased demand and continuing price competition. Sales supplied by the Company's generation in 1994 continued at less than 15% of 1988 levels because of continuing growth of kWh sales to retail customers, which reduces the amount available for sale, and because other suppliers were willing or able to make the sales at lower prices. A significant factor affecting the Company's ability to compete in the market for sales to nonaffiliated utilities has been the approximate 290% increase (from about 67 cents per MWh to $2.60 per MWh) in taxes on generation in West Virginia since March 1989 - a significant cost not experienced by utilities not generating in West Virginia. Further decreases in these sales are anticipated.

M-23 The decrease in other revenues in 1994 and 1993 resulted from continued decreases in sales of energy and spinning reserve to an affiliated company because of additional energy available to it from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA). The 1993 decrease was also due in part to an agreement with the FERC to record in 1993 about $6 million of revenues as sales to nonaffiliated utilities. Similar transactions were recorded as other revenues in prior years. Most of the aggregate benefits from sales to affiliated and nonaffiliated utilities is passed on to retail customers and has little effect on consolidated net income. About $19 million of other revenues in 1994 were derived from wholesale customers regulated by the FERC who have the ability to obtain their electricity requirements from other suppliers. In 1994, these customers signed seven-year contracts to remain as customers. Operating Expenses Fuel expenses decreased 2% in 1994 and 4% in 1993 primarily due to decreases in kWh generated. Fuel expenses are primarily subject to deferred power cost accounting procedures, as described in Note A to the consolidated financial statements, with the result that changes in fuel expenses have little effect on consolidated net income. "Purchased power and exchanges, net" represents power purchases from and exchanges with nonaffiliated utilities and qualified facilities under PURPA, capacity charges paid to AGC, and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and is comprised of the following items: 1994 1993 1992 (Millions of Dollars) Nonaffiliated transactions: Purchased power: For resale to other utilities $116.9 $124.5 $153.9 From PURPA generation 65.7 49.6 56.5 Other 18.3 15.2 5.9 Power exchanges, net (.2) (1.2) .3 Affiliated transactions: AGC capacity charges 37.2 42.3 43.5 Energy and spinning reserve charges 8.6 4.7 3.5 Other affiliated capacity charges .7 .7 .6 $247.2 $235.8 $264.2 The amount of power purchased from nonaffiliated utilities for use by the Company and for resale to nonaffiliated utilities depends upon the availability of the Company's generating equipment, transmission capacity, and fuel, and its cost of generation and the cost of operations of nonaffiliated utilities from which such purchases are made. The primary reason for the fluctuations in purchases for resale to nonaffiliated utilities is described under Sales and Revenues above. The cost of power and capacity purchased for use by the Company, including power from PURPA generation and affiliated transactions, is mostly recovered from customers currently through the regular fuel and energy cost recovery procedures followed by the Company's

M-24 regulatory commissions and is primarily subject to deferred power cost procedures with the result that changes in such costs have little effect on consolidated net income. The decrease in purchases from PURPA generation in 1993 was due to a planned generating outage at one PURPA project. None of the Company's purchased power contracts is capitalized since there are no minimum payment requirements absent associated kWh generation. The 1993 increase in other purchased power reflects efforts to conserve coal during the UMWA dispute. Other purchased power continued to increase in 1994 because of increased sales to retail customers combined with generating unit outages in the first quarter of 1994. The increase in other operation expense in 1994 resulted primarily from a decision to increase the allowances for uncollectible accounts ($8 million), increases in salaries and wages ($2 million) and employee benefit costs, primarily pension expense ($1 million) and other postretirement benefits ($2 million), and provisions for environmental liabilities ($1 million). Allowances for uncollectible accounts were increased due to an increase in aged outstanding receivables caused by customers taking advantage of rate regulations which make it difficult if not impossible to curtail service to non-paying customers during the winter months. In a continuing effort to control salary and wage expenses and to improve the overall efficiency of the Company in a competitive environment, the Allegheny Power System has an ongoing program to consolidate various related functions within the System. The increase in pension expense occurred because the Company in 1994 discontinued the practice of deferring SFAS No. 87 pension expense to reflect a recent rate case decision. During 1992, the Company implemented significant changes to its benefits plans, including cost caps, in an effort to both control and reduce employee benefit costs. The cost caps provide for future post-retirement medical benefit costs to be capped at two times 1993 levels. Approximately $.3 million of the increase in postretirement benefit expenses for 1994 was due to the 1993 cost cap being greater than actuarily projected. The adoption of SFAS No. 106 in 1993 increased 1993 postretirement benefit expenses by approximately $3 million. The increase in other operation expense for 1993 resulted primarily from increases in salaries and wages and employee benefit costs. Another FASB standard, SFAS No. 112, "Employers' Accounting for Postemployment Benefits", effective in 1994, requires companies to accrue for other postemployment benefits such as disability benefits, health care benefits for disabled employees, severance pay, and workers' compensation claims. The Company currently accrues for workers' compensation claims, and the estimated liability for the other benefits is not material. Maintenance expenses represent costs incurred to maintain the power stations, the transmission and distribution (T&D) system, and general plant, and reflect routine maintenance of equipment and rights-of-way as well as planned major repairs and unplanned

M-25 expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. The Company is also experiencing, and expects to continue to experience, increased expenditures due to the aging of its power stations. Variations in maintenance expense result primarily from unplanned events and planned major projects, which vary in timing and magnitude depending upon the length of time equipment has been in service without a major overhaul, the amount of work found necessary when the equipment is dismantled, and outage requirements to comply with the CAAA. Maintenance expense in 1993 includes the effects of an ice storm and blizzard in March 1993. Depreciation expense increases resulted primarily from additions to electric plant and from a change in depreciation rates and net salvage amortization in May 1993. On November 16, 1994, the Company declared the Harrison scrubbers available for service and started depreciation on them amounting to $14 million annually. Taxes other than income decreased $2 million in 1994 primarily due to a decrease in West Virginia Business and Occupation taxes (B&O taxes) ($3 million), offset in part by an increase in gross receipts taxes resulting from higher revenues from retail customers ($2 million). The 1993 increase ($2 million) was primarily due to increases in gross receipts taxes ($3 million) offset by decreased West Virginia B&O taxes ($2 million). The net decrease of $1 million in federal and state income taxes in 1994 resulted primarily from plant removal cost tax deductions for which deferred taxes were not provided. The net increase in 1993 of $7 million resulted primarily from an increase in income before taxes ($6 million), and an increase in the tax rate due to the Revenue Reconciliation Act of 1993 ($1 million). Note B to the consolidated financial statements provides a further analysis of income tax expenses. The 1994 combined increase of $2 million in allowances for funds used during construction (AFUDC), reflects increased construction expenditures including those associated with the CAAA, net of CAAA amounts included in rate base and earning a cash return. Future levels of AFUDC can be expected to decrease upon substantial completion of Phase I of the CAAA compliance program. Other income and deductions in 1994 reflect the write-off of $5.2 million net of income taxes of previously accumulated costs related to future facilities which are no longer considered meaningful in the industry's more competitive environment. The changes in other income, net, in 1994 and 1993 resulted primarily from the Company's share of earnings of AGC (see Note D to the consolidated financial statements). Other fluctuations in other income, net, were individually insignificant. Other interest expense reflects change in the levels of short-term debt maintained by the Company throughout the year, as well as the associated interest rates.

M-26 Liquidity and Capital Resources SEC regulations define "liquidity" as "the ability of an enterprise to generate adequate amounts of cash to meet the enterprise's need for cash". The Company needs cash for operating expenses, the payment of interest and dividends, retirement of debt, and for its construction program. To meet these needs, the Company has used internally generated funds and external financings, such as the sale of common and preferred stock, debt instruments, installment loans, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, the Company's cash needs, and capitalization ratio objectives. The availability and cost of external financing depend upon the financial health of the companies seeking those funds. Capital Requirements Construction expenditures for 1994 were $260 million and for 1995 and 1996 are estimated at $172 million and $115 million, respectively. These estimates include $38 million and $1 million, respectively, for substantial completion of the program of complying with Phase I of the CAAA. Annual construction expenditures through 1998, on average, are not expected to significantly vary from 1995 estimated levels. Construction expenditure levels in 1999 and beyond will depend upon the strategy eventually selected for complying with Phase II of the CAAA, as well as future generation requirements. The Harrison Scrubber Project was completed on schedule and the final cost was approximately 24% below the original budget. Primary factors contributing to the reduced cost include: (1) the absence of any major construction problems, (2) financing and material and equipment costs lower than expected, and (3) favorable ruling of the Pennsylvania PUC allowing the inclusion of carrying costs of construction in rates in lieu of AFUDC. The possibility of new legislation which could restrict or discourage carbon dioxide emissions, either through taxation or caps, further complicates the CAAA Phase II planning process. The Company has additional capital requirements of debt maturities (see Note I to the consolidated financial statements). Internal Cash Flows Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $109 million in 1994 compared with $119 million in 1993. In 1994 the Company financed approximately 42% of its capital expenditure program through internal cash generation. Based upon the new rate case authorizations received in 1994, it is expected that close to 100% of the capital expenditure program can be financed through internal cash generation in 1995.

M-27 Materials and supplies, primarily fuel, constituted a significant use of cash in 1994 ($9 million). A new five-year National Bituminous Coal Wage Agreement was signed with the union in December 1993. System coal inventory declined during the renegotiations due to selective mine shutdowns, and has returned to a more appropriate level. December 1992 levels reflected increases to provide for an adequate coal supply in the event of a strike. Financings During 1994 the Company issued $65 million of 8-1/8% first mortgage bonds and $14.91 million of tax-exempt solid waste disposal notes to Harrison County, West Virginia. Due to the significant number of refinancings which have occurred over the past three years, the balance of debt redemption costs is now about $10 million. These costs are being amortized over the life of the associated new bonds. Reduced future interest expense will more than offset these expenses. Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. In 1992, the Company and its affiliates established an internal money pool as a facility to accommodate intercompany short-term borrowing needs, to the extent that certain of the companies have funds available. The internal money pool has contributed to the continued low temporary cash investment amounts. At December 31, 1994, the Company had SEC authorization to issue up to $170 million of short-term debt. In addition, a multi-year credit program established in January 1994 provides the Company with the ability to borrow on a standby revolving credit basis up to $135 million. After the initial three-year term, the program agreement provides that the maturity date may be extended in one-year increments. There were no borrowings under this facility in 1994. During 1995, the Company has no current plans to issue new securities; however, if economic and market conditions make it desirable, it may refinance up to $251.5 million of first mortgage bonds, preferred stock, and pollution control revenue notes. The Company may also engage in additional Harrison County tax-exempt solid waste disposal financings to the extent that funds and qualified properties are available. The Company anticipates that it will be able to meet its future cash needs through internal cash generation and external financings, as it has in the past, and possibly through alternative financing procedures. Environmental Matters and Other Contingencies In the normal course of business, the Company is subject to various contingencies and uncertainties relating to its operations and construction programs, including cost recovery in

M-28 the regulatory process, laws, regulations and uncertainties related to environmental matters, and legal actions. Contingencies and uncertainties related to the CAAA are discussed above and under Note K to the consolidated financial statements. The Company previously reported that the Environmental Protection Agency (EPA) had identified it and its affiliates and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. A Remedial Investigation/Feasibility Study prepared by the EPA indicates remedial alternatives which range as high as $113 million, to be shared by all responsible parties. The EPA has not yet selected which remedial alternatives it will use. The Company believes it has defenses to allegations of liability and intends to vigorously defend this matter. Although it is not possible at this time to determine what costs, if any, the Company may incur, it has recorded provisions for liabilities based on the range of remediation cost estimates and its relative participation, along with the approximately 875 others. The Company believes that provisions for liabilities and insurance recoveries are such that final resolution of this matter will not have a material effect on its financial position. Monongahela Power Company (MP), an affiliated company, has been named as a defendant along with multiple other defendants in 1,625 pending asbestos cases involving one or more plaintiffs, and the Company and its affiliates have been named as defendants along with multiple other defendants in an additional 716 cases by one or more plaintiffs. Because these cases are filed by "shotgun" complaints naming many plaintiffs and many defendants, it is currently impossible to determine the actual number of claims against the Company and its affiliates. However, based on past experience and data available to date, it is estimated that less than 500 cases actually involve claims against the Company or its affiliates. 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. All plaintiffs claiming exposure at System-operated stations were employed by third-party contractors, with the exception of three known plaintiffs who claim to have been employees of MP. The Company is joint owner with MP in four generating plants, including three operated by MP in West Virginia. 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 that include a spousal claim for loss of consortium, damages are generally

M-29 sought against all defendants in an amount of up to an additional $1 million. Because of the multiple defendants, the Company believes its potential liability is a very small percentage of the total amount of the damages sought. A total of 94 cases have been previously settled by MP for an amount substantially less than the anticipated cost of defense. The Company believes that the remaining cases involving it are also without merit and that provisions for liabilities and insurance recoveries are such that these suits will not have a material effect on its financial position.

M-30 AGC MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Results of Operations As described under Liquidity and Capital Resources, revenues are determined under a cost of service formula rate schedule. Therefore, if all other factors remain equal, revenues are expected to decrease each year due to a normal continuing reduction in the Company's net investment in the Bath County station and its connecting transmission facilities upon which the return on investment is determined. The net investment (primarily net plant less deferred income taxes) decreases to the extent that provisions for depreciation and deferred income taxes exceed net plant additions. Revenues for 1994 increased primarily because of the return on equity settlement which resulted in an adjustment of prior period provisions for rate refunds. Revenues for 1993 decreased due to a reduction in interest charges and net investment, and reduced operating expenses which are described below. Additionally, revenues for 1993 were reduced by the recording of estimated liabilities for possible refunds pending final Federal Energy Regulatory Commission (FERC) decisions in rate case proceedings (see Liquidity and Capital Resources). The increase in operating expenses in 1994 resulted primarily from an increase in federal income taxes due to an increase in income before taxes ($1.5 million). The decrease in operating expenses in 1993 resulted from a decrease in federal income taxes due to a decrease in income before taxes ($1.9 million) offset by an increase in the tax rate due to the Revenue Reconciliation Act of 1993 ($.5 million), partially offset by an increase in operation and maintenance expense. The decreases in interest on long-term debt in 1994 and 1993 were the combined result of decreases in the average amount of and interest rates on long-term debt outstanding. The increase in other interest in 1994 was due to amortization of the premium paid to refund debentures in 1993. Liquidity and Capital Resources SEC regulations define "liquidity" as "the ability of an enterprise to generate adequate amounts of cash to meet the enterprise's need for cash". The Company's only operating assets are an undivided 40% interest in the Bath County (Virginia) pumped-storage hydroelectric station and its connecting transmission facilities. The Company has no present plans for construction of any other major facilities. Pursuant to an agreement, the Parents buy all of the Company's capacity in the station priced under a "cost of service formula" wholesale rate schedule approved by the FERC. Under this arrangement, the Company recovers in revenues all of its operation and maintenance expenses, depreciation, taxes, and a return on its investment.

M-31 Through February 29, 1992, the Company's return on equity (ROE) was adjusted annually pursuant to a settlement agreement approved by the FERC. In December 1991, the Company filed for a continuation of the existing ROE of 11.53% and other parties (the Consumer Advocate Division of the Public Service Commission of West Virginia, Maryland People's Counsel, and Pennsylvania Office of Consumer Advocate, collectively referred to as the joint consumer advocates or JCA) filed to reduce the ROE to 10%. Hearings were completed in June 1992, and a recommendation was issued by an Administrative Law Judge (ALJ) on December 21, 1993, for an ROE of 10.83%, which the JCA argues should be further adjusted to reflect changes in capital market conditions since the hearings. Exceptions to this recommendation were filed by all parties for consideration by the FERC. On January 28, 1994, the JCA filed a joint complaint with the FERC against the Company claiming that both the existing ROE of 11.53% and the ROE recommended by the ALJ of 10.83% were unjust and unreasonable. This new complaint requested an ROE of 8.53% with rates subject to refund beginning April 1, 1994. Hearings were completed in November 1994 and a recommendation was issued by an ALJ on December 22, 1994, dismissing the JCA's complaint. A settlement agreement for both cases is currently pending, which would reduce the Company's ROE to 11.13% for the period from March 1, 1992, through December 31, 1994, and increase the Company's ROE to 11.20% for the period from January 1, 1995, through December 31, 1995. During 1995, the parties have agreed to negotiate in good faith to approve a mechanism for setting ROE in the future. This settlement is subject to FERC approval. If approved, this settlement will require a refund to customers for the period through December 31, 1994, of about $4.42 million for which adequate reserves have been provided. Through a filing completed on October 31, 1994, the Company sought to add a prior tax payment of approximately $12 million to rate base which will produce about $1.4 million in additional annual revenues. On December 30, 1994, the FERC accepted the Company's filing, ordered that the increase in rates go into effect on June 1, 1995, subject to refund, and set the Company's ROE for hearing in 1995. A settlement agreement is currently pending. This settlement is subject to FERC approval. An internal money pool accommodates intercompany short-term borrowing needs, to the extent that certain of the Company's affiliates have funds available.

<TABLE> <CAPTION> ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Financial Statements Index Monon- Potomac West APS gahela Edison Penn AGC <S> <C> <C> <C> <C> <C> Report of Independent Accountants F-1 F-17 F-34 F-51 F-68 Statement of Income for F-2 F-18 F-35 F-52 F-69 the three years ended December 31, 1994 Statement of Retained Earnings - F-19 F-36 F-53 F-70 for the three years ended December 31, 1994 Statement of Cash Flows for F-3 F-20 F-37 F-54 F-71 the three years ended December 31, 1994 Balance Sheet at December 31, F-4 F-21 F-38 F-55 F-72 1994 and 1993 Statement of Capitalization at F-5 F-22 F-39 F-56 F-73 December 31, 1994 and 1993 Statement of Common Equity for F-6 - - - - the three years ended December 31, 1994 Notes to financial statements F-7 F-23 F-40 F-57 F-74 Financial Statement Schedules - Schedules - for the three years ended December 31, 1994 II Valuation and qualifying accounts S-1 S-2 S-3 S-4 - All other schedules are omitted because they are not applicable or the required information is shown in the Financial Statements or Notes thereto. </TABLE>

F-1 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of Allegheny Power System, Inc. In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Allegheny Power System, Inc. and its subsidiaries at December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Notes A, B and E to the consolidated financial statements, the Company changed its method of accounting for revenue recognition in 1994 and for income taxes and postretirement benefits other than pensions in 1993. PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP New York, New York February 2, 1995

F-2 APS CONSOLIDATED STATEMENT OF INCOME Year ended December 31 (Dollar amounts in thousands except for per share data) 1994 1993 1992 Electric Operating Revenues: Residential $ 863 725 $ 818 400 $ 734 874 Commercial 459 303 430 202 391 912 Industrial 728 009 673 418 637 656 Nonaffiliated utilities 331 557 346 705 465 491 Other 69 090 62 801 76 725 TOTAL OPERATING REVENUES 2 451 684 2 331 526 2 306 658 Operating Expenses: Operation: Fuel 547 241 544 659 567 833 Purchased power and exchanges, net 440 880 417 449 451 408 Deferred power costs, net (Note A) 11 805 (11 462) 89 Other 285 010 257 732 232 672 Maintenance 241 913 231 163 210 878 Depreciation 223 883 210 428 197 763 Taxes other than income taxes 183 060 178 788 174 578 Federal and state income taxes (Note B) 129 751 128 130 115 373 TOTAL OPERATING EXPENSES 2 063 543 1 956 887 1 950 594 OPERATING INCOME 388 141 374 639 356 064 Other Income and Deductions: Allowance for other than borrowed funds used during construction (Note A) 11 966 12 499 10 221 Asset write-off, net (Note A) (5 338) Other income, net 1 510 (6) 1 265 TOTAL OTHER INCOME AND DEDUCTIONS 8 138 12 493 11 486 INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS 396 279 387 132 367 550 Interest Charges and Preferred Dividends: Interest on long-term debt 153 668 157 449 147 427 Other interest 10 394 5 812 5 672 Allowance for borrowed funds used during construction (Note A) (7 630) (8 983) (7 331) Dividends on preferred stock of subsidiaries 20 096 17 098 18 235 TOTAL INTEREST CHARGES AND PREFERRED DIVIDENDS 176 528 171 376 164 003 Consolidated Income Before Cumulative Effect of Accounting Change 219 751 215 756 203 547 Cumulative Effect of Accounting Change, net (Note A) 43 446 Consolidated Net Income $ 263 197 $ 215 756 $ 203 547 Common Stock Shares Outstanding (average) (Note G) 118 272 373 114 937 032 111 226 318 Earnings Per Average Share (Note G): Consolidated income before cumulative effect of accounting change $1.86 $1.88 $1.83 Cumulative effect of accounting change, net (Note A) .37 Consolidated net income $2.23 $1.88 $1.83 See accompanying notes to consolidated financial statements.

<TABLE> <CAPTION> F-3 CONSOLIDATED STATEMENT OF CASH FLOWS Year ended December 31 1994 1993 1992 (Thousands of Dollars) Cash Flows from Operations: <S> <C> <C> <C> Consolidated net income $263 197 $215 756 $203 547 Depreciation 223 883 210 428 197 763 Deferred investment credit and income taxes, net 25 684 (2 388) 19 579 Deferred power costs, net 11 805 (11 462) 89 Allowance for other than borrowed funds used during construction (11 966) (12 499) (10 221) Cumulative effect of accounting change before income taxes (Note A) (72 333) Asset write-off before income taxes (Note A) 9 178 Changes in certain current assets and liabilities: Accounts receivable, net, excluding cumulative effect of accounting change (Note A) 9 666 (15 393) 12 452 Materials and supplies (20 519) 53 614 (30 359) Accounts payable 3 119 (305) 34 525 Taxes accrued (5 792) 3 619 (5 692) Interest accrued 3 452 (2 164) 5 139 Other, net 779 18 087 (19 431) 440 153 457 293 407 391 Cash Flows from Investing: Construction expenditures (508 254) (573 970) (487 587) Allowance for other than borrowed funds used during construction 11 966 12 499 10 221 (496 288) (561 471) (477 366) Cash Flows from Financing: Sale of common stock 34 709 99 875 119 884 Sale of preferred stock 49 635 39 450 Retirement of preferred stock (1 190) (1 611) (27 250) Issuance of long-term debt 197 098 691 343 398 619 Retirement of long-term debt (26 000) (632 000) (360 408) Deposit with trustees for redemption of long-term debt 115 785 Short-term debt, net (3 818) 119 431 (62 985) Cash dividends on common stock (193 951) (187 475) (179 739) 56 483 89 563 43 356 Net Change in Cash and Temporary Cash Investments (Note F) 348 (14 615) (26 619) Cash and Temporary Cash Investments at January 1 2 417 17 032 43 651 Cash and Temporary Cash Investments at December 31 $ 2 765 $ 2 417 $ 17 032 Supplemental cash flow information Cash paid during the year for: Interest (net of amount capitalized) $148 016 $153 455 $138 724 Income taxes 122 343 124 979 103 635 See accompanying notes to consolidated financial statements. </TABLE>

<TABLE> <CAPTION> F-4 CONSOLIDATED BALANCE SHEET As of December 31 1994 1993 ASSETS (Thousands of Dollars) Property, Plant, and Equipment: At original cost, including $215,756,000 and <S> <C> <C> $638,920,000 under construction $7 586 780 $7 176 847 Accumulated depreciation (2 529 354) (2 388 758) 5 057 426 4 788 089 Investments and Other Assets: Subsidiaries consolidated--excess of cost over book equity at acquisition (Note A) 15 077 15 077 Securities of associated company--at cost, which approximates equity 1 250 1 250 Other (Note A) 36 284 24 357 52 611 40 684 Current Assets: Cash and temporary cash investments (Note F) 2 765 2 417 Accounts receivable: Electric service, net of $11,353,000 and $3,418,000 uncollectible allowance (Note A) 250 367 188 139 Other 8 175 7 736 Materials and supplies--at average cost: Operating and construction 94 478 86 766 Fuel 84 199 71 392 Deferred power costs (Note A) 4 443 14 054 Prepaid taxes 43 880 43 139 Other 19 287 10 391 507 594 424 034 Deferred Charges: Regulatory assets (Note B) 643 791 577 817 Unamortized loss on reacquired debt 40 991 44 435 Other 59 812 74 109 744 594 696 361 Total $6 362 225 $5 949 168 CAPITALIZATION AND LIABILITIES Capitalization: Common stock, other paid-in capital, and retained earnings (Notes C and G) $2 059 304 $1 955 815 Preferred stock (Note G) 325 286 276 486 Long-term debt (Note H) 2 178 472 2 008 104 4 563 062 4 240 405 Current Liabilities: Short-term debt (Note I) 126 818 130 636 Long-term debt and preferred stock due within one year (Notes G and H) 29 200 27 200 Accounts payable 190 809 187 690 Taxes accrued: Federal and state income 13 873 14 689 Other 52 782 57 758 Interest accrued 42 078 38 626 Other 62 073 73 467 517 633 530 066 Deferred Credits and Other Liabilities: Unamortized investment credit 158 018 166 328 Deferred income taxes 972 113 873 695 Regulatory liabilities (Note B) 105 076 107 372 Other 46 323 31 302 1 281 530 1 178 697 Commitments and Contingencies (Note J) Total $6 362 225 $5 949 168 See accompanying notes to consolidated financial statements. </TABLE>

<TABLE> <CAPTION> F-5 CONSOLIDATED STATEMENT OF CAPITALIZATION As of December 31 1994 1993 1994 1993 Common Stock: (Thousands of Dollars) (Capitalization Ratios) Common stock of Allegheny Power System, Inc.--$1.25 par value per share, 260,000,000 shares authorized, outstanding <S> <C> <C> <C> <C> 119,292,954 and 117,663,582 shares (Note G) $ 149 116 $ 147 079 Other paid-in capital 963 269 931 063 Retained earnings (Note C) 946 919 877 673 TOTAL 2 059 304 1 955 815 45.1% 46.1% Preferred Stock of Subsidiaries--cumulative, par value $100 per share, authorized 9,997,123 shares (Note G): Not subject to mandatory redemption: December 31, 1994 Shares Regular Call Price Series Outstanding Per Share 3.60%- 4.80% 650 861 $102.205 to $110.00 65 086 65 086 $5.88 -$7.92 1 300 000 102.85 to 103.94 130 000 80 000 $8.00 -$8.80 650 000 103.25 to 104.20 65 000 65 000 Auction 2.52%- 4.28% 400 000 100.00 40 000 40 000 TOTAL (annual dividend requirements $19,554,469) 300 086 250 086 6.6% 5.9% Subject to mandatory redemption: December 31, 1994 Shares Regular Call Price Series Outstanding Per Share $7.16% 264 000 $105.37 26 400 27 600 TOTAL (annual dividend requirements $1,890,240) 26 400 27 600 Less current sinking fund requirement (1 200) (1 200) TOTAL 25 200 26 400 0.6% 0.6% Long-Term Debt of Subsidiaries (Note H): First mortgage bonds: December 31, 1994 Maturity Interest Rate-% 1994-1998 4 7/8-6 1/2 180 000 196 000 2000-2004 5 5/8-7 7/8 315 000 315 000 2006-2007 7 1/4-8 120 000 120 000 2019 8 7/8-9 1/4 165 000 165 000 2020-2024 7 3/4-9 5/8 760 000 620 000 Debentures due 2003-2023 5 5/8-6 7/8 150 000 150 000 Secured notes due 1998-2024 4.95-9.375 368 300 333 005 Unsecured notes due 1996-2012 6.10-6.40 27 495 27 495 Installment purchase obligations due 1998 6.875 19 100 19 100 Commercial paper 6.25 41 736 21 362 Medium-term notes due 1994-1998 5.75-7.93 77 975 87 975 Unamortized debt discount and premium, net (18 134) (16 943) TOTAL (annual interest requirements $162,558,089) 2 206 472 2 037 994 Less current maturities (28 000) (26 000) Less amounts on deposit with trustee (3 890) TOTAL 2 178 472 2 008 104 47.7% 47.4% Total Capitalization $4 563 062 $4 240 405 100.0% 100.0% See accompanying notes to consolidated financial statements. </TABLE>

<TABLE> <CAPTION> F-6 CONSOLIDATED STATEMENT OF COMMON EQUITY Year ended December 31 Shares Other Retained Total Outstanding Common Paid-In Earnings Common (Note G) Stock Capital (Note C) Equity (Thousands of Dollars) <S> <C> <C> <C> <C> <C> Balance at January 1, 1992 108 451 312 $135 564 $723 520 $826 570 $1 685 654 Add: Sale of common stock, net of expenses: Public offerings 3 960 000 4 950 81 544 86 494 Dividend Reinvestment and Stock Purchase Plan and Employee Stock Ownership and Savings Plan 1 487 424 1 859 31 530 33 389 Consolidated net income 203 547 203 547 Deduct: Dividends on common stock of the Company (cash) 179 739 179 739 Expenses related to subsidiary companies' preferred stock transactions 556 980 1 536 Balance at December 31, 1992 113 898 736 $142 373 $836 038 $849 398 $1 827 809 Add: Sale of common stock, net of expenses: Public offerings 2 400 000 3 000 61 057 64 057 Dividend Reinvestment and Stock Purchase Plan and Employee Stock Ownership and Savings Plan 1 364 846 1 706 34 402 36 108 Consolidated net income 215 756 215 756 Deduct: Dividends on common stock of the Company (cash) 187 475 187 475 Expenses related to common stock split 290 290 Expenses related to subsidiary companies' preferred stock transactions 144 6 150 Balance at December 31, 1993 117 663 582 $147 079 $931 063 $877 673 $1 955 815 Add: Sale of common stock, net of expenses: Dividend Reinvestment and Stock Purchase Plan and Employee Stock Ownership and Savings Plan 1 629 372 2 037 32 988 35 025 Consolidated net income 263 197 263 197 Deduct: Dividends on common stock of the Company (cash) 193 951 193 951 Expenses related to 1993 public offerings 79 79 Expenses related to common stock split 237 237 Expenses related to subsidiary companies' preferred stock transactions 466 466 Balance at December 31, 1994 119 292 954 $149 116 $963 269 $946 919 $2 059 304 See accompanying notes to consolidated financial statements. </TABLE>

F-7 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (These notes are an integral part of the consolidated financial statements.) NOTE A--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The Company and its subsidiaries (companies) are subject to regulation by the Securities and Exchange Commission. The regulated subsidiaries are subject to regulation by various state bodies having jurisdiction and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company and its subsidiaries are summarized below. CONSOLIDATION: The Company owns all of the outstanding common stock of its subsidiaries. The consolidated financial statements include the accounts of the Company and all subsidiary companies after elimination of intercompany transactions. REVENUES: Beginning in 1994, revenues, including amounts resulting from the application of fuel and energy cost adjustment clauses, are recognized in the same period in which the related electric services are provided to customers, by recording an estimate for unbilled revenues for services provided from the meter reading date to the end of the accounting period. In 1993 and 1992, revenues were recorded for billings rendered to customers, except for a portion of unbilled revenues in West Virginia. DEFERRED POWER COSTS, NET: The costs of fuel, purchased power, and certain other costs, and revenues from sales and transmission services to other utilities, are deferred until they are either recovered from or credited to customers under fuel and energy cost recovery procedures. PROPERTY, PLANT, AND EQUIPMENT: Property, plant, and equipment are stated at original cost, less contributions in aid of construction, except for capital leases which are recorded at present value. Cost includes direct labor and material, allowance for funds used during construction (AFUDC) on property for which construction work in progress is not included in rate base, and such indirect costs as administration, maintenance, and depreciation of transportation and construction equipment, and pensions, taxes, and other fringe benefits related to employees engaged in construction. The cost of depreciable property units retired, plus removal costs less salvage, are charged to accumulated depreciation. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used". AFUDC is recognized as a cost of property, plant, and equipment with offsetting credits to other income and interest charges. Rates used by the subsidiaries for computing AFUDC in 1994, 1993, and 1992 averaged 9.00%, 9.37%, and 9.19%, respectively. AFUDC is not included in the cost of such construction when the cost of financing the construction is being recovered through rates.

F-8 DEPRECIATION AND MAINTENANCE: Provisions for depreciation are determined generally on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 3.3% of average depreciable property in 1994, 3.4% in 1993, and 3.3% in 1992. The cost of maintenance and of certain replacements of property, plant, and equipment is charged principally to operating expenses. INVESTMENTS: The investment in subsidiaries consolidated represents the excess of acquisition cost over book equity (goodwill) prior to 1966. Goodwill is not being amortized because, in management's opinion, there has been no reduction in its value. Other investments primarily represent the estimated cash surrender values and prepayments of purchased life insurance contracts on certain qualifying management employees under an executive life insurance plan and a supplemental executive retirement plan (Secured Benefit Plan). Payment of future premiums will fully fund these benefits. INCOME TAXES: Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in another period. Differences between income tax expense computed on the basis of financial accounting income and taxes payable based on taxable income are accounted for substantially in accordance with the accounting procedures followed for ratemaking purposes. Deferred tax assets and liabilities recorded in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes", represent the tax effect of temporary differences between the financial statement and tax basis of assets and liabilities computed utilizing the most current tax rates. Provisions for federal income tax were reduced in previous years by investment credits, and amounts equivalent to such credits were charged to income with concurrent credits to a deferred account, balances of which are being amortized over estimated service lives of the related properties. POSTRETIREMENT BENEFITS: The subsidiaries have a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on the employee's years of service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act and not more than can be deducted for federal income tax purposes.

F-9 The subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which comprise the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. The funding plan for these costs is to contribute to Voluntary Employee Beneficiary Association (VEBA) trust funds an amount equal to the annual cost as determined by SFAS No. 106 (described below). Medical benefits are self-insured; the life insurance plan is paid through insurance premiums. The FASB has prescribed the determination of annual pension and other postretirement benefits expenses in SFAS No. 87, "Employers' Accounting for Pensions", and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", respectively. The subsidiaries record annual pension expense in accordance with SFAS No. 87. Prior to 1994, regulatory deferrals of these benefit expenses were recorded pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", for those jurisdictions which reflected as net expense the funding of pensions and cash payments of other benefits in the ratemaking process. Regulatory deferrals of SFAS No. 106 benefits expenses were recorded for those jurisdictions in which SFAS No. 106 costs were not yet included in rates. ASSET WRITE-OFF: In 1994, the subsidiaries wrote off $9.2 million ($5.3 million net of income taxes) of previously accumulated costs related to a potential future power plant site and a proposed transmission line. In the industry's more competitive environment, it is no longer reasonable to assume future recovery of these costs in rates. ACCOUNTING CHANGES: Effective January 1, 1994, the subsidiaries changed their revenue recognition method to include the accrual of estimated unbilled revenues for electric services. This change results in a better matching of revenues and expenses, and is consistent with predominant utility industry practice. Previously, in accordance with ratemaking procedures followed in West Virginia, Monongahela Power Company had recorded a portion of revenues for service rendered but unbilled at year-end. The cumulative effect of this accounting change for years prior to 1994, which is shown separately in the consolidated statement of income for 1994, resulted in a benefit of $43.4 million (after related income taxes of $28.9 million), or $.37 per share of common stock. The effect of the change on the current year's consolidated income before the cumulative effect of accounting change, as well as on 1993 and 1992 consolidated net income, is not material. Effective January 1, 1993, the subsidiaries adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions". Prior to 1993, medical expenses and life insurance premiums paid for retired employees and their dependents were recorded as expense in the period they were paid. Also effective January 1, 1993,

F-10 the subsidiaries adopted SFAS No. 109, "Accounting for Income Taxes". This standard mandated a change from the previous income-based deferral approach to a balance sheet-based liability approach for computing deferred income taxes. NOTE B--INCOME TAXES: Details of federal and state income tax provisions are: 1994 1993 1992 (Thousands of Dollars) Income taxes--current: Federal $114 263 $110 815 $ 92 937 State 15 633 20 732 4 144 Total 129 896 131 547 97 081 Income taxes--deferred, net of amortization 33 994 6 034 28 318 Investment credit disallowed (404) Amortization of deferred investment credit (8 310) (8 422) (8 335) Total income taxes 155 580 129 159 116 660 Income taxes--credited (charged) to other income and deductions 3 058 (1 029) (1 287) Income taxes--charged to accounting change (including state income taxes) (28 887) Income taxes--charged to operating income $129 751 $128 130 $115 373 The total provision for income taxes is different than the amount produced by applying the federal income statutory tax rate to financial accounting income, as set forth below: 1994 1993 1992 (Thousands of Dollars) Financial accounting income before cumulative effect of accounting change, preferred dividends, and income taxes $369 598 $360 984 $337 155 Amount so produced $129 400 $126 300 $114 600 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower tax depreciation 8 000 8 800 7 600 Plant removal costs (5 600) (6 000) (6 500) State income tax, net of federal income tax benefit 11 600 15 000 12 600 Amortization of deferred investment credit (8 310) (8 422) (8 335) Other, net (5 339) (7 548) (4 592) Total $129 751 $128 130 $115 373

F-11 Federal income tax returns through 1991 have been examined and substantially settled. In adopting SFAS No. 109, the subsidiaries recognized a significant increase in both deferred tax assets and liabilities. At December 31, the deferred tax assets and liabilities were comprised of the following: 1994 1993 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credit $ 99 821 $ 105 289 Unbilled revenue 13 043 38 363 Tax interest capitalized 33 773 22 236 Contributions in aid of construction 18 742 17 176 State tax loss carryback/carryforward 8 256 14 560 Other 40 927 21 658 214 562 219 282 Deferred tax liabilities: Book vs. tax plant basis differences, net 1 123 763 1 051 500 Other 51 996 42 122 1 175 759 1 093 622 Total net deferred tax liabilities 961 197 874 340 Add portion above included in current assets (liabilities) 10 916 (645) Total long-term net deferred tax liabilities $ 972 113 $ 873 695 It is expected that regulatory commissions will allow recovery of the deferred tax liabilities in future years as they are paid, and accordingly, the subsidiaries have recorded regulatory assets of $605 million which offset the increase in deferred tax liabilities. Regulatory liabilities of $105 million have been recorded which offset the increase in deferred tax assets in order to reflect the subsidiaries' obligation to pass such tax benefits on to their customers as the benefits are realized in cash in future years. NOTE C--DIVIDEND RESTRICTION: Supplemental indentures relating to most outstanding bonds of the subsidiaries contain dividend restrictions under the most restrictive of which $461,539,000 of consolidated retained earnings at December 31, 1994, is not available for cash dividends on their common stocks, except that a portion thereof may be paid as cash dividends where concurrently an equivalent amount of cash is received by a subsidiary as a capital contribution or as the proceeds of the issue and sale of shares of such subsidiary's common stock.

F-12 NOTE D--PENSION BENEFITS: Net pension costs, a portion of which (about 25% to 30%) was charged to plant construction, included the following components: 1994 1993 1992 (Thousands of Dollars) Service cost--benefits earned $14 940 $13 361 $12 402 Interest cost on projected benefit obligation 38 630 37 387 36 049 Actual return on plan assets (61) (89 680) (65 641) Net amortization and deferral (48 983) 43 653 21 344 SFAS No. 87 pension cost 4 526 4 721 4 154 Regulatory reversal (deferral) 6 681 (1 509) (3 862) Net pension cost $11 207 $ 3 212 $ 292 The benefits earned to date and funded status at December 31 using a measurement date of September 30 were as follows: 1994 1993 (Thousands of Dollars) Actuarial present value of accumulated benefit obligation earned to date (including vested benefit of $403,610,000 and $401,986,000) $429 998 $429 360 Funded status: Actuarial present value of projected benefit obligation $529 411 $546 776 Plan assets at market value, primarily common stocks and fixed income securities 573 122 602 194 Plan assets in excess of projected benefit obligation (43 711) (55 418) Add: Unrecognized cumulative net gain from past experience different from that assumed 52 078 58 402 Unamortized transition asset, being amortized over 14 years beginning January 1, 1987 18 882 22 028 Less unrecognized prior service cost due to plan amendments 10 650 12 939 Pension cost liability at September 30 16 599 12 073 Fourth quarter contributions 7 800 -- Pension liability at December 31 $ 8 799 $ 12 073 In determining the actuarial present value of the projected benefit obligation at September 30, 1994, 1993, and 1992, the discount rates used were 7.75%, 7.25%, and 7.75%, and the rates of increase in future compensation levels were 4.75%, 4.75%, and 5.25%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1994, 1993, and 1992.

F-13 NOTE E--POSTRETIREMENT BENEFITS OTHER THAN PENSIONS: The subsidiaries adopted SFAS No. 106 as of January 1, 1993, which requires accrual of postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents during the years the employees render the necessary service to receive such benefits. Prior to 1993, medical expenses and life insurance premiums paid by the subsidiaries for retired employees and their dependents were recorded in expense in the period in which they were paid ($6,553,000 in 1992). SFAS No. 106 postretirement cost in 1994 and 1993, a portion of which (about 25% to 30%) was charged to plant construction, included the following components: 1994 1993 (Thousands of Dollars) Service cost--benefits earned $ 3 058 $ 2 000 Interest cost on accumulated postretirement benefit obligation 13 732 11 300 Actual loss (return) on plan assets 135 (24) Amortization of unrecognized transition obligation 7 300 7 300 Other net amortization and deferral 206 24 SFAS No. 106 postretirement cost 24 431 20 600 Regulatory deferral (3 908) (4 790) Net postretirement cost $20 523 $15 810 The benefits earned to date and funded status at December 31 using a measurement date of September 30 were as follows: 1994 1993 (Thousands of Dollars) Accumulated postretirement benefit obligation: Retirees $118 518 $115 019 Fully eligible employees 24 791 24 135 Other employees 52 914 55 255 Total obligation 196 223 194 409 Plan assets at market value 19 791 4 646 Accumulated postretirement benefit obligation in excess of plan assets 176 432 189 763 Less: Unrecognized cumulative net loss from past experience different from that assumed 34 190 41 450 Unrecognized transition obligation, being amortized over 20 years beginning January 1, 1993 130 900 138 200 Postretirement benefit liability at September 30 11 342 10 113 Fourth quarter contributions and benefit payments 5 826 4 549 Postretirement benefit liability at December 31 $ 5 516 $ 5 564

F-14 The plan assets at market value are comprised of fixed income securities, common stocks, and a short-term investment fund in 1994; and a short-term investment fund in 1993. The unfunded accumulated postretirement benefit obligation (APBO) at January 1, 1993, of $145,500,000 (transition obligation) is being amortized prospectively over 20 years as permitted by SFAS No. 106. In determining the APBO at September 30, 1994, 1993, and 1992, the discount rates used were 7.75%, 7.25%, and 8%, and the rates of increase in future compensation levels were 4.75%, 4.75%, and 5.5%, respectively. The 1994 expected long-term rate of return on assets was 8.25% net of tax. For measurement purposes, a health care trend rate of 9% for 1995, declining 1% each year thereafter to 6.75% in the year 1998 and beyond, and plan provisions which limit future medical and life insurance benefits, were assumed. Increasing the assumed health care trend rate by 1% in each year would increase the APBO at December 31, 1994, by $13.5 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1994 by $1.3 million. The subsidiaries have been authorized recovery of approximately 90% of SFAS No. 106 expenses in rates. NOTE F--FAIR VALUE OF FINANCIAL INSTRUMENTS: The carrying amounts and estimated fair value of financial instruments at December 31, 1994 and 1993 were as follows: <TABLE> <CAPTION> 1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Assets: <S> <C> <C> <C> <C> Temporary cash investments $ 73 $ 73 $ 244 $ 244 Life insurance contracts 35 584 33 884 23 971 24 032 Liabilities: Short-term debt 126 818 126 818 130 636 130 636 Mandatorily redeemable preferred stock 26 400 25 542 27 600 28 566 Long-term debt 2 224 606 2 114 871 2 054 937 2 129 923 </TABLE> The carrying amount of temporary cash investments, as well as short-term debt, approximates the fair value because of the short maturity of those instruments. The fair value of mandatorily redeemable preferred stock was estimated based on quoted market prices. The fair value of long-term debt was estimated based on actual market prices or market prices of similar issues. The fair value of the life insurance contracts in Note A was estimated based on cash surrender value. The Company does not have any financial instruments held or issued for trading purposes.

F-15 For purposes of the consolidated statement of cash flows, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, and repurchase agreements, are considered to be the equivalent of cash. NOTE G--STOCKHOLDERS' EQUITY: COMMON STOCK: In November 1993, the common shareholders approved a two-for-one split of the Company's common stock effective November 4, 1993. The stock split reduced the par value of the common stock from $2.50 per share to $1.25 per share and increased the number of authorized shares of common stock from 130,000,000 to 260,000,000. The number of common stock shares outstanding and per share information for all periods reflect the two-for-one split. PREFERRED STOCK: In May 1994, Monongahela issued 500,000 shares of Series L, $7.73 preferred stock with par value of $100 per share. This Series is not redeemable prior to August 1, 2004. All of the preferred stock is entitled on voluntary liquidation to its then current call price and on involuntary liquidation to $100 a share. The holders of West Penn Power Company's market auction preferred stock are entitled to dividends at a rate determined by an auction held the business day preceding each quarterly dividend payment date. MANDATORILY REDEEMABLE PREFERRED STOCK: The Potomac Edison Company's $7.16 preferred stock is entitled to a cumulative sinking fund sufficient to retire 12,000 shares each year at $100 a share plus accrued dividends. That subsidiary has the noncumulative option in each year to retire up to an additional 12,000 shares at the same price. The call price declines in future years. NOTE H--LONG-TERM DEBT: Maturities for long-term debt for the next five years are: 1995, $28,000,000; 1996, $43,575,000; 1997, $26,900,000; 1998, $227,136,000; and 1999, $5,300,000. Substantially all of the properties of the subsidiaries are held subject to the lien securing each subsidiary's first mortgage bonds. Some properties are also subject to a second lien securing certain pollution control and solid waste disposal notes. Commercial paper borrowings issuable by Allegheny Generating Company are backed by a revolving credit agreement with a group of seven banks which provides for loans of up to $50 million at any one time outstanding through 1998. Each bank has the option to discontinue its loans after 1998 upon three years' prior written notice. Without such notice, the loans are automatically extended for one year. However, to the extent that funds are available from the companies, Allegheny Generating Company borrowings are made through an internal money pool as described in Note I.

F-16 NOTE I--SHORT-TERM DEBT: To provide interim financing and support for outstanding commercial paper, lines of credit have been established with several banks. The companies have fee arrangements on all of their lines of credit and no compensating balance requirements. At December 31, 1994, unused lines of credit with banks were $202,150,000. In addition to bank lines of credit, an internal money pool accommodates intercompany short-term borrowing needs, to the extent that certain of the companies have funds available. In January 1994, a multi-year credit program was established which provides that the subsidiaries may borrow up to $300 million on a standby revolving credit basis. Short-term debt outstanding for 1994 and 1993 consisted of: 1994 1993 (Thousands of Dollars) Balance at end of year: Commercial Paper $103,968 -- 6.06% $54,811 -- 3.31% Notes Payable to Banks 22,850 -- 5.92% 75,825 -- 3.45% Average amount outstanding during the year: Commercial Paper 67,290 -- 4.25% 21,567 -- 3.24% Notes Payable to Banks 33,273 -- 4.17% 25,597 -- 3.19% NOTE J--COMMITMENTS AND CONTINGENCIES: CONSTRUCTION PROGRAM: The subsidiaries have entered into commitments for their construction programs, for which expenditures are estimated to be $341 million for 1995 and $284 million for 1996. These estimates include expenditures for the program of complying with the Clean Air Act Amendments of 1990 (CAAA) as discussed below. ENVIRONMENTAL MATTERS: The companies are subject to various laws, regulations, and uncertainties as to environmental matters. Compliance may require them to incur substantial additional costs to modify or replace existing and proposed equipment and facilities and may affect adversely the lead time, size, and siting of future generating stations, increase the complexity and cost of pollution control equipment, and otherwise add to the cost of future operations. Construction estimates for 1995 and 1996 include $61 million and $7 million, respectively, for compliance with Phase I of the CAAA. Through 1998, annual construction expenditures are not expected to significantly exceed 1995 estimated levels. Construction expenditure levels in 1999 and beyond will depend upon the strategy eventually selected for complying with Phase II of the CAAA, as well as future generation requirements. LITIGATION: In the normal course of business, the companies become involved in various legal proceedings. The companies do not believe that the ultimate outcome of these proceedings will have a material effect on their financial position.

F-17 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of Monongahela Power Company In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Monongahela Power Company (a subsidiary of Allegheny Power System, Inc.) at December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Notes A, B and F to the financial statements, the Company changed its method of accounting for revenue recognition in 1994 and for income taxes and postretirement benefits other than pensions in 1993. PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP New York, New York February 2, 1995

<TABLE> <CAPTION> F-18 Monongahela STATEMENT OF INCOME YEAR ENDED DECEMBER 31 1994 1993 1992 (Thousands of Dollars) Electric Operating Revenues: <S> <C> <C> <C> Residential $190 861 $185 141 $169 589 Commercial 116 201 110 762 102 709 Industrial 202 181 187 669 186 442 Nonaffiliated utilities 79 701 86 032 119 628 Other, including affiliates 91 186 72 240 53 595 Total Operating Revenues 680 130 641 844 631 963 Operating Expenses: Operation: Fuel 150 088 144 408 149 219 Purchased power and exchanges, net 161 839 155 602 153 272 Deferred power costs, net (Note A) 7 604 (2 489) 5 468 Other 74 907 66 506 64 043 Maintenance 69 389 67 770 62 909 Depreciation 57 952 56 056 53 865 Taxes other than income taxes 40 404 34 076 33 207 Federal and state income taxes (Note B) 30 712 33 612 27 919 Total Operating Expenses 592 895 555 541 549 902 Operating Income 87 235 86 303 82 061 Other Income and Deductions: Allowance for other than borrowed funds used during construction (Note A) 1 566 3 092 2 007 Other income, net 7 911 7 203 8 388 Total Other Income and Deductions 9 477 10 295 10 395 Income Before Interest Charges 96 712 96 598 92 456 Interest Charges: Interest on long-term debt 35 187 35 555 34 241 Other interest 2 969 2 033 1 772 Allowance for borrowed funds used during construction (Note A) (1 380) (2 688) (1 901) Total Interest Charges 36 776 34 900 34 112 Income Before Cumulative Effect of Accounting Change 59 936 61 698 58 344 Cumulative Effect of Accounting Change, net (Note A) 7 945 Net Income $67 881 $61 698 $58 344 </TABLE>

<TABLE> <CAPTION> F-19 STATEMENT OF RETAINED EARNINGS <S> <C> <C> <C> Balance at January 1 $185 486 $178 084 $171 307 Add: Net income 67 881 61 698 58 344 253 367 239 782 229 651 Deduct: Dividends on capital stock: Preferred stock 7 260 4 458 4 845 Common stock 47 481 49 838 46 532 Charge on redemption of preferred stock 190 Total Deductions 54 741 54 296 51 567 Balance at December 31 (Note C) $198 626 $185 486 $178 084 See accompanying notes to financial statements. </TABLE>

<TABLE> <CAPTION> F-20 Monongahela Power Company STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31 1994 1993 1992 (Thousands of Dollars) Cash Flows from Operations: <S> <C> <C> <C> Net income $67 881 $61 698 $58 344 Depreciation 57 952 56 056 53 865 Deferred investment credit and income taxes, net 3 350 6 352 6 982 Deferred power costs, net 7 604 (2 489) 5 468 Unconsolidated subsidiaries' dividends in excess of earnings 1 647 1 971 2 552 Allowance for other than borrowed funds used during construction (1 566) (3 092) (2 007) Cumulative effect of accounting change before income taxes (Note A) (13 279) Changes in certain current assets and liabilities: Accounts receivable, net, excluding cumulative effect of accounting change (Note A) 4 756 (8 412) (1 386) Materials and supplies (5 944) 12 917 (7 434) Accounts payable (2 044) 129 10 599 Taxes accrued (950) (5 674) (8 441) Interest accrued 286 290 1 178 Other, net 1 731 3 296 (558) 121 424 123 042 119 162 Cash Flows from Investing: Construction expenditures (103 975) (140 748) (126 422) Allowance for other than borrowed funds used during construction 1 566 3 092 2 007 (102 409) (137 656) (124 415) Cash Flows from Financing: Sale of common stock 40 000 Sale of preferred stock 49 635 Retirement of preferred stock (5 194) Issuance of long-term debt 9 718 82 331 156 311 Retirement of long-term debt (68 471) (89 414) Short-term debt, net (26 530) 63 100 (53 117) Notes payable to affiliates 2 900 (8 030) 8 030 Dividends on capital stock: Preferred stock (7 260) (4 458) (4 845) Common stock (47 481) (49 838) (46 532) (19 018) 14 634 5 239 Net Change in Cash and Temporary Cash Investments (Note G) (3) 20 (14) Cash and Temporary Cash Investments at January 1 135 115 129 Cash and Temporary Cash Investments at December 31 $132 $135 $115 Supplemental cash flow information Cash paid during the year for: Interest (net of amount capitalized) $35 347 $33 941 $32 486 Income taxes 29 939 30 982 22 946 See accompanying notes to financial statements. </TABLE>

F-21 BALANCE SHEET DECEMBER 31 1994 1993 (Thousands of Dollars) ASSETS Property, Plant, and Equipment: At original cost, including $35,856,000 and $144,621,000 under construction $1 763 533 $1 684 322 Accumulated depreciation (701 271) (664 947) 1 062 262 1 019 375 Investments: Allegheny Generating Company-common stock at equity (Note D) 60 137 61 698 Other 509 595 60 646 62 293 Current Assets: Cash 132 135 Accounts receivable: Electric service, net of $1,912,000 and $1,084,000 uncollectible allowance (Note A) 62 631 48 995 Affiliated and other 9 483 14 596 Materials and supplies-at average cost: Operating and construction 24 563 22 393 Fuel 23 678 19 904 Prepaid taxes 17 599 19 788 Deferred power costs (Note A) 1 852 10 823 Other 5 328 3 772 145 266 140 406 Deferred Charges: Regulatory assets (Note B) 186 109 162 842 Unamortized loss on reacquired debt 11 500 12 229 Other 10 700 10 308 208 309 185 379 Total $1 476 483 $1 407 453 CAPITALIZATION AND LIABILITIES Capitalization: Common stock, other paid-in capital, and retained earnings (Notes C and H) $ 495 693 $ 483 030 Preferred stock, not subject to mandatory redemption (Note H) 114 000 64 000 Long-term debt (Note I) 470 131 460 129 1 079 824 1 007 159 Current Liabilities: Short-term debt (Note J) 36 570 63 100 Notes payable to affiliates (Note J) 2 900 Accounts payable 31 871 31 752 Accounts payable to affiliates 6 021 8 184 Taxes accrued: Federal and state income 118 Other 20 193 21 261 Interest accrued 10 927 10 641 Other 16 455 18 994 125 055 153 932 Deferred Credits and Other Liabilities: Unamortized investment credit 24 734 26 883 Deferred income taxes 216 264 192 466 Regulatory liabilities (Note B) 19 974 19 179 Other 10 632 7 834 271 604 246 362 Commitments and Contingencies (Note K) Total $1 476 483 $1 407 453 See accompanying notes to financial statements.

<TABLE> <CAPTION> F-22 STATEMENT OF CAPITALIZATION DECEMBER 31 1994 1993 1994 1993 (Thousands of Dollars) (Capitalization Ratios) Common Stock: Common stock-par value $50 per share, authorized 8,000,000 shares, outstanding 5,891,000 shares <C> <C> <C> <C> <C> (issued 800,000 shares in 1992) $294 550 $294 550 Other paid-in capital (Note H) 2 517 2 994 Retained earnings (Note C) 198 626 185 486 Total 495 693 483 030 45.9% 48.0% Preferred Stock (not subject to mandatory redemption): Cumulative preferred stock-par value $100 per share, authorized 1,500,000 shares, outstanding as follows (Note H): December 31, 1994 Regular Shares Call Price Date of Series Outstanding Per Share Issue 4.40% 90 000 $106.50 1945 9 000 9 000 4.80% B 40 000 105.25 1947 4 000 4 000 4.50% C 60 000 103.50 1950 6 000 6 000 $6.28 D 50 000 102.86 1967 5 000 5 000 $7.36 E 50 000 103.36 1968 5 000 5 000 $8.80 G 50 000 104.20 1971 5 000 5 000 $7.92 H 50 000 103.52 1972 5 000 5 000 $7.92 I 100 000 103.52 1973 10 000 10 000 $8.60 J 150 000 103.33 1976 15 000 15 000 $7.73 L 500 000 100.00 1994 50 000 Total (annual dividend requirements $8,323,000) 114 000 64 000 10.6 6.3 Long-Term Debt (Note I): First mortgage bonds: Date of Date Date Issue Redeemable Due 5-1/2% 1966 1994 1996 18 000 18 000 6-1/2% 1967 1994 1997 15 000 15 000 5-5/8% 1993 2000 2000 65 000 65 000 7-3/8% 1992 2002 2002 25 000 25 000 7-1/4% 1992 2002 2007 25 000 25 000 8-7/8% 1989 1994 2019 70 000 70 000 8-5/8% 1991 2001 2021 50 000 50 000 8-1/2% 1992 1997 2022 65 000 65 000 8-3/8% 1992 2002 2022 40 000 40 000 Interest Rate Secured notes due 1998-2024 5.95%-7.75% 74 050 65 225 Unsecured notes due 1996-2012 6.30%-6.40% 7 560 7 560 Installment purchase obligations due 1998 6.875% 19 100 19 100 Unamortized debt discount and premium, net (3 579) (3 785) Total (annual interest requirements $35,550,131) 470 131 461 100 42.8 42.7 Less amount on deposit with trustee 971 Total 470 131 460 129 43.5 45.7 Total Capitalization $1 079 824 $1 007 159 100.0 100.0% See accompanying notes to financial statements. </TABLE>

F-23 NOTES TO FINANCIAL STATEMENTS (These notes are an integral part of the financial statements.) Note A-Summary of Significant Accounting Policies: The Company is a wholly-owned subsidiary of Allegheny Power System, Inc. and is a part of the Allegheny Power integrated electric utility system (the System). The Company is subject to regulation by the Securities and Exchange Commission (SEC), by various state bodies having jurisdiction, and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below. REVENUES: Revenues, including amounts resulting from the application of fuel and energy cost adjustment clauses, are recognized in the same period in which the related electric services are provided to customers by recording an estimate for unbilled revenues for services provided from the meter reading date to the end of the accounting period. This procedure has been utilized for a number of years in West Virginia, as required by the Public Service Commission of West Virginia, and was adopted for all revenues beginning in 1994. DEFERRED POWER COSTS, NET: The costs of fuel, purchased power, and certain other costs, and revenues from sales and transmission services to other utilities, are deferred until they are either recovered from or credited to customers under fuel and energy cost recovery procedures. PROPERTY, PLANT, AND EQUIPMENT: Property, plant, and equipment, including facilities owned with affiliates in the System, are stated at original cost, less contributions in aid of construction, except for capital leases which are recorded at present value. Cost includes direct labor and material, allowance for funds used during construction (AFUDC) on property for which construction work in progress is not included in rate base, and such indirect costs as administration, maintenance, and depreciation of transportation and construction equipment, and pensions, taxes, and other fringe benefits related to employees engaged in construction. The cost of depreciable property units retired, plus removal costs less salvage, are charged to accumulated depreciation. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other

F-24 funds when so used". AFUDC is recognized as a cost of property, plant, and equipment with offsetting credits to other income and interest charges. Rates used for computing AFUDC in 1994, 1993, and 1992 were 8.16%, 8.69%, and 8.23%, respectively. AFUDC is not included in the cost of such construction when the cost of financing the construction is being recovered through rates. DEPRECIATION AND MAINTENANCE: Provisions for depreciation are determined generally on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 3.6% of average depreciable property in 1994 and 3.8% in each of the years 1993 and 1992. The cost of maintenance and of certain replacements of property, plant, and equipment is charged principally to operating expenses. INCOME TAXES: The Company joins with its parent and affiliates in filing a consolidated federal income tax return. The consolidated tax liability is allocated among the participants generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return tax liability. Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in another period. Differences between income tax expense computed on the basis of financial accounting income and taxes payable based on taxable income are accounted for substantially in accordance with the accounting procedures followed for ratemaking purposes. Deferred tax assets and liabilities recorded in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes", represent the tax effect of temporary differences between the financial statement and tax basis of assets and liabilities computed utilizing the most current tax rates. Provisions for federal income tax were reduced in previous years by investment credits, and amounts equivalent to such credits were charged to income with concurrent credits to a deferred account, balances of which are being amortized over estimated service lives of the related properties. POSTRETIREMENT BENEFITS: The Company participates with affiliated companies in the System in a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on the employee's years of service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act and not more than can be deducted for federal income tax purposes.

F-25 The Company also provides partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which comprise the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. The funding plan for these costs is to contribute to Voluntary Employee Beneficiary Association (VEBA) trust funds an amount equal to the annual cost as determined by SFAS No. 106 (described below). Medical benefits are self-insured; the life insurance plan is paid through insurance premiums. The FASB has prescribed the determination of annual pension and other postretirement benefits expenses in SFAS No. 87, "Employers' Accounting for Pensions", and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", respectively. The Company records annual pension expense in accordance with SFAS No. 87. Prior to 1994, regulatory deferrals of these benefit expenses were recorded pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", for West Virginia and Ohio jurisdictions. These jurisdictions reflected as net expense the funding of pensions and cash payments of other benefits in the ratemaking process. Regulatory deferrals of SFAS No. 106 benefits expenses were recorded for Ohio and West Virginia jurisdictions in which SFAS No. 106 costs were not yet included in rates. ACCOUNTING CHANGES: Effective January 1, 1994, the Company changed its revenue recognition method for revenues to include the accrual of estimated unbilled revenues for electric services. This change results in a better matching of revenues and expenses, and is consistent with predominant utility industry practice and the practice used in West Virginia for a number of years. The cumulative effect of this accounting change for the years prior to the adoption of this practice, including West Virginia, is shown separately in the statement of income for 1994, and resulted in a benefit of $7.9 million (after related income taxes of $5.4 million). The effect of the change on the current year's income before the cumulative effect of accounting change, as well as on 1993 and 1992 net income, is not material. Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions". Prior to 1993, medical expenses and life insurance premiums paid for retired employees and their dependents were recorded as expense in the period they were paid. Also effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes". This standard mandated a change from the previous income-based deferral approach to a balance sheet-based liability approach for computing deferred income taxes.

F-26 Note B-Income Taxes: Details of federal and state income tax provisions are: 1994 1993 1992 (Thousands of Dollars) Income taxes-current: Federal $27 793 $25 618 $20 365 State 4 841 1 692 830 Total 32 634 27 310 21 195 Income taxes-deferred, net of amortization 5 499 8 517 9 364 Investment credit disallowed (207) Amortization of deferred investment credit (2 149) (2 165) (2 175) Total income taxes 35 984 33 662 28 177 Income taxes-credited (charged) to other income 63 (50) (258) Income taxes-charged to accounting change (including state income taxes) (5 335) Income taxes-charged to operating income $30 712 $33 612 $27 919 The total provision for income taxes is different than the amount produced by applying the federal income statutory tax rate to financial accounting income as set forth below: 1994 1993 1992 (Thousands of Dollars) Financial accounting income before cumulative effect of accounting change and income taxes $90 648 $95 310 $86 263 Amount so produced $31 700 $33 400 $29 300 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower tax depreciation 5 400 5 700 4 900 Plant removal costs (2 100) (3 000) (2 600) State income tax, net of federal income tax benefit 3 500 3 800 3 800 Amortization of deferred investment credit (2 149) (2 165) (2 175) Equity in earnings of subsidiaries (2 800) (2 500) (2 800) Adjustments of provisions for prior years (1 900) 400 (100) Other, net (939) (2 023) (2 406) Total $30 712 $33 612 $27 919 Federal income tax returns through 1991 have been examined and substantially settled.

F-27 In adopting SFAS No. 109, the Company recognized a significant increase in both deferred tax assets and liabilities. At December 31, the deferred tax assets and liabilities were comprised of the following: <TABLE> <CAPTION> 1994 1993 (Thousands of Dollars) Deferred tax assets: <S> <C> <C> Unamortized investment tax credit $16 604 $18 043 Unbilled revenue 4 181 Tax interest capitalized 4 907 2 430 Contributions in aid of construction 2 223 2 058 Vacation pay 760 1 958 Advances for construction 1 771 1 601 Other 9 987 4 455 36 252 34 726 Deferred tax liabilities: Book vs. tax plant basis differences, net 228 997 205 829 Other 22 425 23 411 251 422 229 240 Total net deferred tax liabilities 215 170 194 514 Add portion above included in current assets (liabilities) 1 094 (2 048) Total long-term net deferred tax liabilities $216 264 $192 466 </TABLE> It is expected that regulatory commissions will allow recovery of the deferred tax liabilities in future years as they are paid, and accordingly, the Company has recorded regulatory assets of $174 million which offset the increase in deferred tax liabilities. Regulatory liabilities of $20 million have been recorded which offset the increase in deferred tax assets in order to reflect the Company's obligation to pass such tax benefits on to its customers as the benefits are realized in cash in future years. Note C-Dividend Restriction: Supplemental indentures relating to most outstanding bonds of the Company contain dividend restrictions under the most restrictive of which $103,482,000 of retained earnings at December 31, 1994, is not available for cash dividends on common stock, except that a portion thereof may be paid as cash dividends where concurrently an equivalent amount of cash is received by the Company as a capital contribution or as the proceeds of the issue and sale of shares of its common stock. Note D-Allegheny Generating Company: The Company owns 27% of the common stock of Allegheny Generating Company (AGC), and affiliates of the Company own the remainder. AGC owns an undivided 40% interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric station in Bath County, Virginia operated by the 60% owner, Virginia Power Company, a nonaffiliated utility. AGC recovers from the Company and its affiliates all of its operation and maintenance expenses, depreciation, taxes, and a return on its investment under a wholesale rate schedule approved by the FERC. Through February 29, 1992, AGC's return on equity (ROE) was adjusted annually pursuant to a settlement agreement approved by the FERC.

F-28 In December 1991, AGC filed for a continuation of the existing ROE of 11.53% and other parties (the Consumer Advocate Division of the West Virginia PSC, Maryland People's Counsel, and Pennsylvania Office of Consumer Advocate, collectively referred to as the joint consumer advocates or JCA) filed to reduce the ROE to 10%. Hearings were completed in June 1992, and a recommendation was issued by an Administrative Law Judge (ALJ) on December 21, 1993, for an ROE of 10.83%, which the JCA argues should be further adjusted to reflect changes in capital market conditions since the hearings. Exceptions to this recommendation were filed by all parties for consideration by the FERC. On January 28, 1994, the JCA filed a joint complaint with the FERC against AGC claiming that both the existing ROE of 11.53% and the ROE recommended by the ALJ of 10.83% were unjust and unreasonable. This new complaint requested an ROE of 8.53% with rates subject to refund beginning April 1, 1994. Hearings were completed in November 1994 and a recommendation was issued by an ALJ on December 22, 1994, dismissing the JCA's complaint. A settlement agreement for both cases is currently pending, which would reduce AGC's ROE to 11.13% for the period from March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.20% for the period from January 1, 1995, through December 31, 1995. Following is a summary of financial information for AGC: <TABLE> <CAPTION> December 31 1994 1993 (Thousands of Dollars) Balance sheet information: <S> <C> <C> Property, plant, and equipment $680 749 $696 529 Current assets 5 991 11 063 Deferred charges 27 496 28 337 Total assets $714 236 $735 929 Total capitalization $489 894 $505 708 Current liabilities 6 484 21 891 Deferred credits 217 858 208 330 Total capitalization and liabilities $714 236 $735 929 Year Ended December 31 1994 1993 1992 (Thousands of Dollars) Income statement information: Electric operating revenues $91 022 $90 606 $96 147 Operation and maintenance expense 6 695 6 609 6 094 Depreciation 16 852 16 899 16 827 Taxes other than income taxes 5 223 5 347 5 236 Federal income taxes 14 737 13 262 14 702 Interest charges 17 809 21 635 22 585 Other income, net (11) (328) (21) Net income $29 717 $27 182 $30 724 </TABLE> Results for 1994 reflect the effect of the pending settlement agreement. The Company's share of the equity in earnings above was $8.0 million, $7.3 million, and $8.3 million for 1994, 1993, and 1992, respectively, and is included in other income, net, on the Statement of Income.

F-29 Note E-Pension Benefits: The Company's share of net pension costs under the System's pension plan, a portion of which (about 25% to 30%) was charged to plant construction, included the following components: <TABLE> <CAPTION> 1994 1993 1992 (Thousands of Dollars) <S> <C> <C> <C> Service cost - benefits earned $ 3 677 $ 3 198 $ 3 054 Interest cost on projected benefit obligation 9 045 8 577 8 470 Actual loss (return) on plan assets 87 (22 606) (14 863) Net amortization and deferral (11 563) 12 048 4 453 SFAS No. 87 pension cost 1 246 1 217 1 114 Regulatory reversal (deferral) 3 718 (1 179) (1 114) Net pension cost $ 4 964 $ 38 $ ---- </TABLE> The benefits earned to date and funded status of the Company's share of the System plan at December 31 using a measurement date of September 30 were as follows: 1994 1993 (Thousands of Dollars) Actuarial present value of accumulated benefit obligation earned to date (including vested benefit of $92,823,000 and $91,750,000) $ 99 605 $ 98 898 Funded status: Actuarial present value of projected benefit obligation $123 935 $128 201 Plan assets at market value, primarily common stocks and fixed income securities 134 166 141 195 Plan assets in excess of projected benefit obligation (10 231) (12 994) Add: Unrecognized cumulative net gain from past experience different from that assumed 13 969 15 187 Unamortized transition asset, being amortized over 14 years beginning January 1, 1987 3 988 4 711 Less unrecognized prior service cost due to plan amendments 2 471 2 891 Pension cost liability at September 30 5 255 4 013 Fourth quarter contributions 1 829 - Pension liability at December 31 $3 426 $4 013 The foregoing includes the Company's portion of amounts applicable to employees at power stations which are owned jointly with affiliates. In determining the actuarial present value of the projected benefit obligation at September 30, 1994, 1993, and 1992, the discount rates used were 7.75%, 7.25%, and 7.75%, and the rates of increase in future compensation levels were 4.75%, 4.75%, and 5.25%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1994, 1993, and 1992.

F-30 Note F-Postretirement Benefits Other Than Pensions: The Company adopted SFAS No. 106 as of January 1, 1993, which requires accrual of postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents during the years the employees render the necessary service to receive such benefits. Prior to 1993, medical expenses and life insurance premiums paid by the Company for retired employees and their dependents were recorded in expense in the period in which they were paid ($2,390,000 in 1992). SFAS No. 106 postretirement cost in 1994 and 1993, a portion of which (about 25% to 30%) was charged to plant construction, included the following components: 1994 1993 (Thousands of Dollars) Service cost - benefits earned $ 764 $ 478 Interest cost on accumulated postretirement benefit obligation 3 655 2 819 Actual loss (return) on plan assets 38 (5) Amortization of unrecognized transition obligation 1 783 1 772 Other net amortization and deferral 50 5 SFAS No. 106 postretirement cost 6 290 5 069 Regulatory deferral (3 450) (1 981) Net postretirement cost $2 840 $3 088 The benefits earned to date and funded status of the Company's share of the System plan at December 31 using a measurement date of September 30 were as follows: 1994 1993 (Thousands of Dollars) Accumulated postretirement benefit obligation: Retirees $33 528 $32 469 Fully eligible employees 4 947 4 348 Other employees 14 458 14 664 Total obligation 52 933 51 481 Plan assets at market value 5 338 1 230 Accumulated postretirement benefit obligation in excess of plan assets 47 595 50 251 Less: Unrecognized cumulative net loss from past experience different from that assumed 12 752 14 161 Unrecognized transition obligation, being amortized over 20 years beginning January 1, 1993 32 368 34 059 Postretirement benefit liability at September 30 2 475 2 031 Fourth quarter contributions and benefit payments 1 437 997 Postretirement benefit liability at December 31 $1 038 $1 034

F-31 The plan assets at market value are comprised of fixed income securities, common stocks, and a short-term investment fund in 1994; and a short-term investment fund in 1993. The unfunded accumulated postretirement benefit obligation (APBO) at January 1, 1993, of $35,800,000 (transition obligation), is being amortized prospectively over 20 years as permitted by SFAS No. 106. In determining the APBO at September 30, 1994, 1993, and 1992, the discount rates used were 7.75%, 7.25%, and 8%, and the rates of increase in future compensation levels were 4.75%, 4.75%, and 5.5%, respectively. The 1994 expected long-term rate of return on assets was 8.25% net of tax. For measurement purposes, a health care trend rate of 9% for 1995, declining 1% each year thereafter to 6.75% in the year 1998 and beyond, and plan provisions which limit future medical and life insurance benefits, were assumed. Increasing the assumed health care trend rate by 1% in each year would increase the APBO at December 31, 1994, by $3.6 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1994 by $.3 million. Note G-Fair Value of Financial Instruments: The carrying amounts and estimated fair value of financial instruments at December 31, 1994 and 1993 were as follows: <TABLE> <CAPTION> 1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Liabilities: <S> <C> <C> <C> <C> Short-term debt $ 36 570 $ 36 570 $ 63 100 $ 63 100 Long-term debt 473 710 458 714 464 885 485 713 </TABLE> The carrying amount of short-term debt approximates the fair value because of the short maturity of those instruments. The fair value of long-term debt was estimated based on actual market prices or market prices of similar issues. The Company does not have any financial instruments held or issued for trading purposes. For purposes of the statement of cash flows, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, and repurchase agreements, are considered to be the equivalent of cash. Note H-Stockholders' Equity: COMMON STOCK AND OTHER PAID-IN CAPITAL: In September 1992, the Company issued and sold to its parent, 800,000 shares of its common stock at $50 per share. Other paid-in capital decreased $477,000 in 1994 as a result of underwriting fees and commissions associated with the Company's

F-32 sale of $50 million of preferred stock. Other paid-in capital decreased $4,000 in 1992 as a result of a preferred stock redemption. PREFERRED STOCK: In May 1994, the Company issued 500,000 shares of Series L, $7.73 cumulative preferred stock with par value of $100 per share. This Series is not redeemable prior to August 1, 2004. All of the preferred stock is entitled on voluntary liquidation to its then current call price and on involuntary liquidation to $100 a share. Note I-Long-Term Debt: Maturities for long-term debt for the next five years are: 1995, none; 1996, $18,500,000; 1997, $15,500,000; 1998, $20,100,000; and 1999, $1,000,000. Substantially all of the properties of the Company are held subject to the lien securing its first mortgage bonds. Some properties are also subject to a second lien securing certain pollution control and solid waste disposal notes. Certain first mortgage bond series are not redeemable by certain refunding until dates established in the respective supplemental indentures. Note J-Short-Term Debt: To provide interim financing and support for outstanding commercial paper, the System companies have established lines of credit with several banks. The Company has SEC authorization for total short-term borrowings of $100 million including money pool borrowings described below. The Company has fee arrangements on all of its lines of credit and no compensating balance requirements. In addition to bank lines of credit, an internal money pool accommodates intercompany short-term borrowing needs, to the extent that certain of the companies have funds available. In January 1994, the Company and its affiliates jointly established an aggregate $300 million multi-year credit program which provides that the Company may borrow up to $81 million on a standby revolving credit basis. Short-term debt outstanding for 1994 and 1993 consisted of: 1994 1993 (Thousands of Dollars) Balance at end of year: Commercial Paper $24,970-6.21% - Notes Payable to Banks 11,600-6.43% $63,100-3.45% Money Pool 2,900-5.49% - Average amount outstanding during the year: Commercial Paper 8,751-3.58% 3,467-3.19% Notes Payable to Banks 15,283-3.89% 10,627-3.20% Money Pool 11,363-4.51% 8,227-3.01%

F-33 Note K-Commitments and Contingencies: CONSTRUCTION PROGRAM: The Company has entered into commitments for its construction program, for which expenditures are estimated to be $74 million for 1995 and $70 million for 1996. These estimates include expenditures for the program of complying with the Clean Air Act Amendments of 1990 (CAAA) as discussed below. ENVIRONMENTAL MATTERS: System companies are subject to various laws, regulations, and uncertainties as to environmental matters. Compliance may require them to incur substantial additional costs to modify or replace existing and proposed equipment and facilities and may affect adversely the lead time, size, and siting of future generating stations, increase the complexity and cost of pollution control equipment, and otherwise add to the cost of future operations. Construction estimates for 1995 and 1996 include $11 million and $2 million, respectively, for compliance with Phase I of the CAAA. Through 1998, annual construction expenditures, on average, are not expected to significantly exceed 1995 estimated levels. Construction expenditure levels in 1999 and beyond will depend upon the strategy eventually selected for complying with Phase II of the CAAA, as well as future generation requirements. LITIGATION AND OTHER: In the normal course of business, the Company becomes involved in various legal proceedings. The Company does not believe that the ultimate outcome of these proceedings will have a material effect on its financial position. The Company is guarantor as to 27% of a $50 million revolving credit agreement of AGC, which in 1994 was used by AGC solely as support for its indebtedness for commercial paper outstanding.

F-34 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of The Potomac Edison Company In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of The Potomac Edison Company (a subsidiary of Allegheny Power System, Inc.) at December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Notes A, B and F to the financial statements, the Company changed its method of accounting for revenue recognition in 1994 and for income taxes and postretirement benefits other than pensions in 1993. PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP New York, New York February 2, 1995

<TABLE> <CAPTION> F-35 Potomac Edison STATEMENT OF INCOME YEAR ENDED DECEMBER 31 1994 1993 1992 (Thousands of Dollars) Electric Operating Revenues: <S> <C> <C> <C> Residential $296 090 $274 358 $243 413 Commercial 135 937 124 667 111 506 Industrial 195 089 175 902 157 304 Nonaffiliated utilities 107 027 108 132 141 120 Other, including affiliates 25 222 29 526 34 544 Total Operating Revenues 759 365 712 585 687 887 Operating Expenses: Operation: Fuel 145 045 143 587 150 218 Purchased power and exchanges, net 217 137 205 073 201 220 Deferred power costs, net (Note A) 1 321 (9 953) (3 850) Other 85 024 74 438 67 351 Maintenance 58 624 64 376 53 141 Depreciation 59 989 56 449 53 446 Taxes other than income taxes 46 740 46 813 45 791 Federal and state income taxes (Note B) 33 163 30 086 28 422 Total Operating Expenses 647 043 610 869 595 739 Operating Income 112 322 101 716 92 148 Other Income and Deductions: Allowance for other than borrowed funds used during construction (Note A) 3 671 4 329 3 204 Other income, net 10 243 8 419 9 352 Total Other Income and Deductions 13 914 12 748 12 556 Income Before Interest Charges 126 236 114 464 104 704 Interest Charges: Interest on long-term debt 44 706 42 695 38 081 Other interest 1 750 1 107 1 311 Allowance for borrowed funds used during construction (Note A) (2 203) (2 805) (2 164) Total Interest Charges 44 253 40 997 37 228 Income Before Cumulative Effect of Accounting Change 81 983 73 467 67 476 Cumulative Effect of Accounting Change, net (Note A) 16 471 Net Income $98 454 $73 467 $67 476 </TABLE>

<TABLE> <CAPTION> F-36 STATEMENT OF RETAINED EARNINGS <S> <C> <C> <C> Balance at January 1 $176 053 $167 412 $160 515 Add: Net income 98 454 73 467 67 476 274 507 240 879 227 991 Deduct: Dividends on capital stock: Preferred stock 4 331 4 434 6 059 Common stock 62 454 60 386 53 731 Charges on redemption of preferred stock 6 789 Total Deductions 66 785 64 826 60 579 Balance at December 31 (Note C) $207 722 $176 053 $167 412 See accompanying notes to financial statements. </TABLE>

<TABLE> <CAPTION> F-37 STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31 1994 1993 1992 (Thousands of Dollars) Cash Flows from Operations: <S> <C> <C> <C> Net income $98 454 $73 467 $67 476 Depreciation 59 989 56 449 53 446 Deferred investment credit and income taxes, net 12 688 (3 119) 5 192 Deferred power costs, net 1 321 (9 953) (3 850) Unconsolidated subsidiaries' dividends in excess of earnings 1 704 2 042 2 642 Allowance for other than borrowed funds used during construction (3 671) (4 329) (3 204) Cumulative effect of accounting change before income taxes (Note A) (26 163) Changes in certain current assets and liabilities: Accounts receivable, net, excluding cumulative effect of accounting change (Note A) 6 004 (7 640) (2 431) Materials and supplies (5 367) 13 971 (7 464) Accounts payable (9 981) 2 762 17 902 Taxes accrued (1 083) 240 (224) Interest accrued 563 1 664 69 Other, net (198) 14 006 (1 850) 134 260 139 560 127 704 Cash Flows from Investing: Construction expenditures (142 826) (179 433) (153 485) Allowance for other than borrowed funds used during construction 3 671 4 329 3 204 (139 155) (175 104) (150 281) Cash Flows from Financing: Sale of common stock 50 000 80 000 Retirement of preferred stock (1 190) (1 611) (22 056) Issuance of long-term debt 86 877 142 171 58 101 Retirement of long-term debt (16 000) (123 888) (46 782) Deposit with trustee for redemption of long-term debt 47 431 Notes receivable from affiliates 2 700 33 400 (38 000) Dividends on capital stock: Preferred stock (4 331) (4 434) (6 059) Common stock (62 454) (60 386) (53 731) 5 602 35 252 18 904 Net Change in Cash and Temporary Cash Investments (Note G) 707 (292) (3 673) Cash and Temporary Cash Investments at January 1 1 489 1 781 5 454 Cash and Temporary Cash Investments at December 31 $2 196 $1 489 $1 781 Supplemental cash flow information Cash paid during the year for: Interest (net of amount capitalized) $42 680 $37 427 $36 371 Income taxes 30 771 30 378 25 180 See accompanying notes to financial statements. </TABLE>

F-38 BALANCE SHEET DECEMBER 31 1994 1993 (Thousands of Dollars) ASSETS Property, Plant, and Equipment: At original cost, including $76,365,000 and $208,308,000 under construction $1 978 396 $1 857 961 Accumulated depreciation (673 853) (632 269) 1 304 543 1 225 692 Investments and Other Assets: Allegheny Generating Company - common stock at equity (Note D) 62 364 63 983 Other 938 819 63 302 64 802 Current Assets: Cash 2 196 1 489 Accounts receivable: Electric service, net of $1,177,000 and $1,207,000 uncollectible allowance (Note A) 68 714 44 575 Affiliated and other 2 403 6 383 Notes receivable from affiliates (Note J) 1 900 4 600 Materials and supplies at average cost: Operating and construction 27 800 26 153 Fuel 22 316 18 596 Prepaid taxes 13 168 12 523 Other 5 000 4 000 143 497 118 319 Deferred Charges: Regulatory assets (Note B) 88 758 76 962 Unamortized loss on reacquired debt 8 344 9 188 Other 21 091 24 800 118 193 110 950 Total $1 629 535 $1 519 763 CAPITALIZATION AND LIABILITIES Capitalization: Common stock, other paid-in capital, and retained earnings (Notes C and H) $658 146 $626 467 Preferred stock (Note H) 61 578 62 778 Long-term debt (Note I) 604 749 517 910 1 324 473 1 207 155 Current Liabilities: Long-term debt and preferred stock due within one year (Notes H and I) 1 200 17 200 Accounts payable 37 126 41 986 Accounts payable to affiliates 10 485 15 606 Taxes accrued: Federal and state income 3 565 2 970 Other 11 874 13 552 Interest accrued 9 195 8 632 Other 17 399 22 445 90 844 122 391 Deferred Credits and Other Liabilities: Unamortized investment credit 28 041 30 308 Deferred income taxes 149 299 133 027 Regulatory liabilities (Note B) 16 957 18 490 Other 19 921 8 392 214 218 190 217 Commitments and Contingencies (Note K) Total $1 629 535 $1 519 763 See accompanying notes to financial statements.

<TABLE> <CAPTION> F-39 Potomac Edison STATEMENT OF CAPITALIZATION DECEMBER 31 1994 1993 1994 1993 (Thousands of Dollars) (Capitalization Ratios) Common Stock: Common stock-no par value, authorized 23,000,000 shares, outstanding 22,385,000 shares (issued 2,500,000 shares <S> <C> <C> <C> <C> in 1993 and 4,000,000 shares in 1992) $447 700 $447 700 Other paid-in capital (Note H) 2 724 2 714 Retained earnings (Note C) 207 722 176 053 Total 658 146 626 467 49.7% 51.9% Preferred Stock: Cumulative preferred stock-par value $100 per share, authorized 5,388,046 shares, outstanding as follows (Note H): Not subject to mandatory redemption: December 31, 1994 Regular Shares Call Price Date of Series Outstanding Per Share Issue 3.60% 63 784 $103.75 1946 6 378 6 378 $5.88 C 100 000 102.85 1967 10 000 10 000 $7.00 D 50 000 103.20 1968 5 000 5 000 $8.32 F 50 000 103.54 1971 5 000 5 000 $8.00 G 100 000 103.25 1972 10 000 10 000 Total (annual dividend requirements $2,383,622) 36 378 36 378 2.7 3.0 Subject to mandatory redemption: $7.16 J 264 000 $105.37 1986 26 400 27 600 Total (annual dividend requirements $1,890,240) 26 400 27 600 Less current sinking fund requirement (1 200) (1 200) 25 200 26 400 1.9 2.2 Long-Term Debt (Note I): First mortgage Date of Date Date bonds: Issue Redeemable Due 4-5/8% 1964 1994 1994 16 000 5-7/8% 1966 1994 1996 18 000 18 000 5-7/8% 1993 2000 2000 75 000 75 000 8% 1991 2001 2006 50 000 50 000 9-1/4% 1989 1994 2019 65 000 65 000 9-5/8% 1990 1995 2020 80 000 80 000 8-7/8% 1991 2001 2021 50 000 50 000 8% 1992 2002 2022 55 000 55 000 7-3/4% 1993 2003 2023 45 000 45 000 8% 1994 2004 2024 75 000 Interest Rate Secured notes due 1998-2024 5.95%-7.30% 91 700 80 140 Unsecured note due 1996-2002 6.30% 5 500 5 500 Unamortized debt discount and premium, net (5 451) (4 456) Total (annual interest requirements $47,887,438) 604 749 535 184 Less current maturities (16 000) Less amount on deposit with trustee (1 274) 604 749 517 910 45.7 42.9 Total Capitalization $1 324 473 $1 207 155 100.0% 100.0% See accompanying notes to financial statements. </TABLE>

F-40 The Potomac Edison Company NOTES TO FINANCIAL STATEMENTS (These notes are an integral part of the financial statements.) Note A Summary of Significant Accounting Policies: The Company is a wholly-owned subsidiary of Allegheny Power System, Inc. and is a part of the Allegheny Power integrated electric utility system (the System). The Company is subject to regulation by the Securities and Exchange Commission (SEC), by various state bodies having jurisdiction, and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below. REVENUES: Beginning in 1994, revenues, generally including amounts resulting from the application of fuel and energy cost adjustment clauses, are recognized in the same period in which the related electric services are provided to customers by recording an estimate for unbilled revenues for services provided from the meter reading date to the end of the accounting period. In 1993 and 1992, revenues were recorded for billings rendered to customers. Revenues of $68.0 million from one industrial customer, Eastalco Aluminum Company, were 9% of total electric operating revenues in 1994. DEFERRED POWER COSTS, NET: The costs of fuel, purchased power, and certain other costs, and revenues from sales and transmission services to other utilities, are deferred until they are either recovered from or credited to customers under fuel and energy cost recovery procedures. PROPERTY, PLANT, AND EQUIPMENT: Property, plant, and equipment, including facilities owned with affiliates in the System, are stated at original cost, less contributions in aid of construction. Cost includes direct labor and material, allowance for funds used during construction (AFUDC) on property for which construction work in progress is not included in rate base, and such indirect costs as administration, maintenance, and depreciation of transportation and construction equipment, and pensions, taxes, and other fringe benefits related to employees engaged in construction. The cost of depreciable property units retired, plus removal costs less salvage, are charged to accumulated depreciation. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used". AFUDC is recognized as a cost of property, plant, and equipment with offsetting credits to other income and interest charges. Rates used for computing AFUDC in 1994, 1993,

F-41 and 1992 were 9.73%, 9.97%, and 9.92%, respectively. AFUDC is not included in the cost of such construction when the cost of financing the construction is being recovered through rates. AFUDC is not recorded for construction applicable to the state of Virginia, where construction work in progress is included in rate base. DEPRECIATION AND MAINTENANCE: Provisions for depreciation are determined generally on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 3.4% of average depreciable property in 1994 and 3.6% in each of the years 1993 and 1992. The cost of maintenance and of certain replacements of property, plant, and equipment is charged principally to operating expenses. INCOME TAXES: The Company joins with its parent and affiliates in filing a consolidated federal income tax return. The consolidated tax liability is allocated among the participants generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return tax liability. Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in another period. Differences between income tax expense computed on the basis of financial accounting income and taxes payable based on taxable income are accounted for substantially in accordance with the accounting procedures followed for ratemaking purposes. Deferred tax assets and liabilities recorded in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes", represent the tax effect of temporary differences between the financial statement and tax basis of assets and liabilities computed utilizing the most current tax rates. Provisions for federal income tax were reduced in previous years by investment credits, and amounts equivalent to such credits were charged to income with concurrent credits to a deferred account, balances of which are being amortized over estimated service lives of the related properties. POSTRETIREMENT BENEFITS: The Company participates with affiliated companies in the System in a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on the employee's years of service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act and not more than can be deducted for federal income tax purposes.

F-42 The Company also provides partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which comprise the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. The funding plan for these costs is to contribute to Voluntary Employee Beneficiary Association (VEBA) trust funds an amount equal to the annual cost as determined by SFAS No. 106 (described below). Medical benefits are self-insured; the life insurance plan is paid through insurance premiums. The FASB has prescribed the determination of annual pension and other postretirement benefits expenses in SFAS No. 87, "Employers' Accounting for Pensions", and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", respectively. The Company records annual pension expense in accordance with SFAS No. 87. Prior to 1994, regulatory deferrals of these benefit expenses were recorded pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", for West Virginia and Virginia jurisdictions. These jurisdictions reflected as net expense the funding of pensions and cash payments of other benefits in the ratemaking process. Regulatory deferrals of SFAS No. 106 benefits expenses were recorded for the West Virginia jurisdiction in which SFAS No. 106 costs were not yet included in rates. ACCOUNTING CHANGES: Effective January 1, 1994, the Company changed its revenue recognition method to include the accrual of estimated unbilled revenues for electric services. This change results in a better matching of revenues and expenses, and is consistent with predominant utility industry practice. The cumulative effect of this accounting change for years prior to 1994, which is shown separately in the statement of income for 1994, resulted in a benefit of $16.5 million (after related income taxes of $9.7 million). The effect of the change on the current year's income before the cumulative effect of accounting change, as well as on 1993 and 1992 net income, is not material. Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions". Prior to 1993, medical expenses and life insurance premiums paid for retired employees and their dependents were recorded as expense in the period they were paid. Also effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes". This standard mandated a change from the previous income-based deferral approach to a balance sheet-based liability approach for computing deferred income taxes. Note B

F-43 Income Taxes: Details of federal and state income tax provisions are: 1994 1993 1992 (Thousands of Dollars) Income taxes-current: Federal $34 193 $29 758 $26 366 State (2 849) 3 991 (2 635) Total 31 344 33 749 23 731 Income taxes-deferred, net of amortization 14 955 (770) 7 634 Investment credit disallowed (196) Amortization of deferred investment credit (2 267) (2 349) (2 246) Total income taxes 44 032 30 630 28 923 Income taxes-charged to other income (1 176) (544) (501) Income taxes-charged to accounting change (including state income taxes) (9 693) Income taxes-charged to operating income $33 163 $30 086 $28 422 The total provision for income taxes is less than the amount produced by applying the federal income statutory tax rate to financial accounting income as set forth below: 1994 1993 1992 (Thousands of Dollars) Financial accounting income before cumulative effect of accounting change and income taxes $115 146 $103 553 $ 95 898 Amount so produced $ 40 300 $ 36 200 $ 32 600 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower tax depreciation 100 2 300 2 300 Plant removal costs (1 700) (2 100) (1 500) State income tax, net of federal income tax benefit 1 300 1 600 1 200 Amortization of deferred investment credit (2 267) (2 349) (2 246) Equity in earnings of subsidiaries (2 900) (2 600) (2 900) Other, net (1 670) (2 965) (1 032) Total $33 163 $30 086 $28 422 Federal income tax returns through 1991 have been examined and substantially settled.

F-44 In adopting SFAS No. 109, the Company recognized a significant increase in both deferred tax assets and liabilities. At December 31, the deferred tax assets and liabilities were comprised of the following: 1994 1993 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credit $16 497 $17 922 Unbilled revenue 3 504 12 556 Tax interest capitalized 12 701 9 056 Contributions in aid of construction 11 653 10 530 State tax loss carryback/carryforward 2 721 5 770 Advances for construction 1 338 1 303 Other 5 800 3 279 54 214 60 416 Deferred tax liabilities: Book vs. tax plant basis differences, net 192 862 183 892 Other 13 367 10 122 206 229 194 014 Total net deferred tax liabilities 152 015 133 598 Less portion above included in current liabilities 2 716 571 Total long-term net deferred tax liabilities $149 299 $133 027 It is expected that regulatory commissions will allow recovery of the deferred tax liabilities in future years as they are paid, and accordingly, the Company has recorded regulatory assets of $76 million which offset the increase in deferred tax liabilities. Regulatory liabilities of $17 million have been recorded which offset the increase in deferred tax assets in order to reflect the Company's obligation to pass such tax benefits on to its customers as the benefits are realized in cash in future years. Note C-Dividend Restriction: Supplemental indentures relating to most outstanding bonds of the Company contain dividend restrictions under the most restrictive of which $103,730,000 of retained earnings at December 31, 1994, is not available for cash dividends on common stock, except that a portion thereof may be paid as cash dividends where concurrently an equivalent amount of cash is received by the Company as a capital contribution or as the proceeds of the issue and sale of shares of its common stock. Note D-Allegheny Generating Company: The Company owns 28% of the common stock of Allegheny Generating Company (AGC), and affiliates of the Company own the remainder. AGC owns an undivided 40% interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric station in Bath County, Virginia operated by the 60% owner, Virginia Power Company, a nonaffiliated utility. AGC recovers from the Company and its affiliates all of its operation and maintenance expenses, depreciation, taxes, and a return on its investment under a wholesale rate schedule approved by the FERC. Through February 29, 1992, AGC's return on equity

F-45 (ROE) was adjusted annually pursuant to a settlement agreement approved by the FERC. In December 1991, AGC filed for a continua- tion of the existing ROE of 11.53% and other parties (the Consumer Advocate Division of the West Virginia PSC, Maryland People's Counsel, and Pennsylvania Office of Consumer Advocate, collectively referred to as the joint consumer advocates or JCA) filed to reduce the ROE to 10%. Hearings were completed in June 1992, and a recommendation was issued by an Administrative Law Judge (ALJ) on December 21, 1993, for an ROE of 10.83%, which the JCA argues should be further adjusted to reflect changes in capital market conditions since the hearings. Exceptions to this recommendation were filed by all parties for consideration by the FERC. On January 28, 1994, the JCA filed a joint complaint with the FERC against AGC claiming that both the existing ROE of 11.53% and the ROE recommended by the ALJ of 10.83% were unjust and unreasonable. This new complaint requested an ROE of 8.53% with rates subject to refund beginning April 1, 1994. Hearings were completed in November 1994 and a recommendation was issued by an ALJ on December 22, 1994, dismissing the JCA's complaint. A settlement agreement for both cases is currently pending, which would reduce AGC's ROE to 11.13% for the period from March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.20% for the period from January 1, 1995, through December 31, 1995. Following is a summary of financial information for AGC: December 31 1994 1993 (Thousands of Dollars) Balance sheet information: Property, plant, and equipment $680 749 $696 529 Current assets 5 991 11 063 Deferred charges 27 496 28 337 Total assets $714 236 $735 929 Total capitalization $489 894 $505 708 Current liabilities 6 484 21 891 Deferred credits 217 858 208 330 Total capitalization and liabilities $714 236 $735 929 Year Ended December 31 1994 1993 1992 (Thousands of Dollars) Income statement information: Electric operating revenues $91 022 $90 606 $96 147 Operation and maintenance expense 6 695 6 609 6 094 Depreciation 16 852 16 899 16 827 Taxes other than income taxes 5 223 5 347 5 236 Federal income taxes 14 737 13 262 14 702 Interest charges 17 809 21 635 22 585 Other income, net (11) (328) (21) Net income $29 717 $27 182 $30 724 Results for 1994 reflect the effect of the pending settlement agreement. The Company's share of the equity in earnings above was $8.3 million, $7.6 million, and $8.6 million for 1994, 1993, and 1992, respectively, and is included in other income, net, on the Statement of Income.

F-46 Note E-Pension Benefits: The Company's share of net pension costs under the System's pension plan, a portion of which (about 30% to 35%) was charged to plant construction, included the following components: <TABLE> <CAPTION> 1994 1993 1992 (Thousands of Dollars) <S> <C> <C> <C> Service cost - benefits earned $ 3 555 $ 3 225 $ 2 923 Interest cost on projected benefit obligation 9 867 9 612 9 142 Actual loss (return) on plan assets 304 (22 481) (15 951) Net amortization and deferral (12 808) 10 669 4 743 SFAS No. 87 pension cost 918 1 025 857 Regulatory reversal (deferral) 1 194 537 (565) Net pension cost $ 2 112 $ 1 562 $ 292 </TABLE> The benefits earned to date and funded status of the Company's share of the System plan at December 31 using a measurement date of September 30 were as follows: 1994 1993 (Thousands of Dollars) Actuarial present value of accumulated benefit obligation earned to date (including vested benefit of $103,546,000 and $102,917,000) $110 577 $110 278 Funded status: Actuarial present value of projected benefit obligation $135 060 $139 320 Plan assets at market value, primarily common stocks and fixed income securities 146 211 153 440 Plan assets in excess of projected benefit obligation (11 151) (14 120) Add: Unrecognized cumulative net gain from past experience different from that assumed 13 165 14 927 Unamortized transition asset, being amortized over 14 years beginning January 1, 1987 4 183 4 951 Less unrecognized prior service cost due to plan amendments 2 732 3 218 Pension cost liability at September 30 3 465 2 540 Fourth quarter contributions 1 989 Pension liability at December 31 $1 476 $2 540 The foregoing includes the Company's portion of amounts applicable to employees at power stations which are owned jointly with affiliates. In determining the actuarial present value of the projected benefit obligation at September 30, 1994, 1993, and 1992, the discount rates used were 7.75%, 7.25%, and 7.75%, and the rates of increase in future compensation levels were 4.75%, 4.75%, and 5.25%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1994, 1993, and 1992.

F-47 Note F-Postretirement Benefits Other Than Pensions: The Company adopted SFAS No. 106 as of January 1, 1993, which requires accrual of postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents during the years the employees render the necessary service to receive such benefits. Prior to 1993, medical expenses and life insurance premiums paid by the Company for retired employees and their dependents were recorded in expense in the period in which they were paid ($1,790,000 in 1992). SFAS No. 106 postretirement cost in 1994 and 1993, a portion of which (about 30% to 35%) was charged to plant construction, included the following components: 1994 1993 (Thousands of Dollars) Service cost-benefits earned $ 696 $ 383 Interest cost on accumulated postretirement benefit obligation 4 047 3 042 Actual loss (return) on plan assets 47 (7) Amortization of unrecognized transition obligation 1 976 1 986 Other net amortization and deferral 53 7 SFAS No. 106 postretirement cost 6 819 5 411 Regulatory deferral (457) (846) Net postretirement cost $6 362 $4 565 The benefits earned to date and funded status of the Company's share of the System plan at December 31 using a measurement date of September 30 were as follows: 1994 1993 (Thousands of Dollars) Accumulated postretirement benefit obligation: Retirees $36 927 $35 189 Fully eligible employees 8 152 7 741 Other employees 14 035 14 635 Total obligation 59 114 57 565 Plan assets at market value 5 962 1 375 Accumulated postretirement benefit obligation in excess of plan assets 53 152 56 190 Less: Unrecognized cumulative net loss from past experience different from that assumed 14 223 15 695 Unrecognized transition obligation, being amortized over 20 years beginning January 1, 1993 35 928 37 995 Postretirement benefit liability at September 30 3 001 2 500 Fourth quarter contributions and benefit payments 1 634 1 132 Postretirement benefit liability at December 31 $1 367 $1 368

F-48 The plan assets at market value are comprised of fixed income securities, common stocks, and a short-term investment fund in 1994; and a short-term investment fund in 1993. The unfunded accumulated postretirement benefit obligation (APBO) at January 1, 1993, of $40,000,000 (transition obligation) is being amortized prospectively over 20 years as permitted by SFAS No. 106. In determining the APBO at September 30, 1994, 1993, and 1992, the discount rates used were 7.75%, 7.25%, and 8%, and the rates of increase in future compensation levels were 4.75%, 4.75%, and 5.5%, respectively. The 1994 expected long-term rate of return on assets was 8.25% net of tax. For measurement purposes, a health care trend rate of 9% for 1995, declining 1% each year thereafter to 6.75% in the year 1998 and beyond, and plan provisions which limit future medical and life insurance benefits, were assumed. Increasing the assumed health care trend rate by 1% in each year would increase the APBO at December 31, 1994, by $4.1 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1994 by $.4 million. Note G-Fair Value of Financial Instruments: The carrying amounts and estimated fair value of financial instruments at December 31, 1994 and 1993 were as follows: <TABLE> <CAPTION> 1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Liabilities: Mandatorily redeemable <S> <C> <C> <C> <C> preferred stock $ 26 400 $ 25 542 $ 27 600 $ 28 566 Long-term debt 610 200 594 519 539 640 566 070 </TABLE> The fair value of mandatorily redeemable preferred stock was estimated based on quoted market prices. The fair value of long-term debt was estimated based on actual market prices or market prices of similar issues. The Company does not have any financial instruments held or issued for trading purposes. For purposes of the statement of cash flows, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, and repurchase agreements, are considered to be the equivalent of cash. Note H-Stockholders' Equity: COMMON STOCK AND OTHER PAID-IN CAPITAL: The Company issued and sold common stock to its parent, at $20 per share, 2,500,000 shares in October 1993 and 4,000,000 shares in September 1992. Other paid-in capital increased $10,000 in 1994 and decreased $2,000 in 1992 as a result of preferred stock transactions.

F-49 PREFERRED STOCK: All of the preferred stock is entitled on voluntary liquidation to its then current call price and on involuntary liquidation to $100 a share. MANDATORILY REDEEMABLE PREFERRED STOCK: The Company's $7.16 preferred stock is entitled to a cumulative sinking fund sufficient to retire 12,000 shares each year at $100 a share plus accrued dividends. The Company has the noncumulative option in each year to retire up to an additional 12,000 shares at the same price. The call price declines in future years. Note I-Long-Term Debt: Maturities for long-term debt for the next five years are: 1995, none; 1996, $18,700,000; 1997, $800,000; 1998, $1,800,000; and 1999, $1,800,000. Substantially all of the properties of the Company are held subject to the lien securing its first mortgage bonds. Some properties are also subject to a second lien securing certain pollution control and solid waste disposal notes. Certain first mortgage bond series are not redeemable by certain refunding until dates established in the respective supplemental indentures. Note J-Short-Term Financing: To provide interim financing and support for outstanding commercial paper, the System companies have established lines of credit with several banks. The Company has SEC authorization for total short-term borrowings of $115 million, including money pool borrowings described below. The Company has fee arrangements on all of its lines of credit and no compensating balance requirements. In addition to bank lines of credit, an internal money pool accommodates intercompany short-term borrowing needs, to the extent that certain of the companies have funds available. In January 1994, the Company and its affiliates jointly established an aggregate $300 million multi-year credit program which provides that the Company may borrow up to $84 million on a standby revolving credit basis. There was no short-term debt outstanding at the end of 1994 or 1993. Average short-term debt outstanding during the year for 1994 and 1993 consisted of: 1994 1993 (Thousands of Dollars) Average amount outstanding during the year: Commercial Paper $1,021-3.96% $ 36-2.97% Notes Payable to Banks 2,499-3.96% 1,112-3.24% Money Pool 87-4.10% -

F-50 Note K-Commitments and Contingencies: CONSTRUCTION PROGRAM: The Company has entered into commitments for its construction program, for which expenditures are estimated to be $92 million for 1995 and $98 million for 1996. These estimates include expenditures for the program of complying with the Clean Air Act Amendments of 1990 (CAAA) as discussed below. ENVIRONMENTAL MATTERS: System companies are subject to various laws, regulations, and uncertainties as to environmental matters. Compliance may require them to incur substantial additional costs to modify or replace existing and proposed equipment and facilities and may affect adversely the lead time, size, and siting of future generating stations, increase the complexity and cost of pollution control equipment, and otherwise add to the cost of future operations. Construction estimates for 1995 and 1996 include $12 million and $5 million, respectively, for compliance with Phase I of the CAAA. Through 1998, annual construction expenditures, on average, are not expected to significantly exceed 1995 estimated levels. Construction expenditure levels in 1999 and beyond will depend upon the strategy eventually selected for complying with Phase II of the CAAA, as well as future generation requirements. LITIGATION AND OTHER: In the normal course of business, the Company becomes involved in various legal proceedings. The Company does not believe that the ultimate outcome of these proceedings will have a material effect on its financial position. The Company is guarantor as to 28% of a $50 million revolving credit agreement of AGC, which in 1994 was used by AGC solely as support for its indebtedness for commercial paper outstanding.

F-51 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of West Penn Power Company In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of West Penn Power Company (a subsidiary of Allegheny Power System, Inc.) at December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Notes A, B and F to the consolidated financial statements, the Company changed its method of accounting for revenue recognition in 1994 and for income taxes and postretirement benefits other than pensions in 1993. PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP New York, New York February 2, 1995

F-52 CONSOLIDATED STATEMENT OF INCOME YEAR ENDED DECEMBER 31 1994 1993 1992 (Thousands of Dollars) Electric Operating Revenues: Residential $ 376 776 $ 358 900 $ 321 871 Commercial 207 165 194 773 177 697 Industrial 330 739 309 847 293 910 Nonaffiliated utilities 144 829 152 541 204 743 Other, including affiliates 68 733 68 916 78 620 Total Operating Revenues 1 128 242 1 084 977 1 076 841 Operating Expenses: Operation: Fuel 252 108 256 664 268 395 Purchased power and exchanges, net 247 194 235 772 264 208 Deferred power costs, net (Note A) 2 880 979 (1 527) Other 145 781 131 854 116 913 Maintenance 111 841 96 706 93 067 Depreciation 88 935 80 872 73 469 Taxes other than income taxes 87 224 89 249 87 300 Federal and state income taxes (Note B) 50 385 51 529 44 078 Total Operating Expenses 986 348 943 625 945 903 Operating Income 141 894 141 352 130 938 Other Income and Deductions: Allowance for other than borrowed funds used during construction (Note A) 6 729 5 077 5 010 Asset write-off, net (Note A) (5 179) Other income, net 13 797 12 728 14 534 Total Other Income and Deductions 15 347 17 805 19 544 Income Before Interest Charges 157 241 159 157 150 482 Interest Charges: Interest on long-term debt 58 102 58 857 53 768 Other interest 2 172 1 728 1 824 Allowance for borrowed funds used during construction (Note A) (4 048) (3 489) (3 266) Total Interest Charges 56 226 157 096 52 326 Consolidated Income Before Cumulative Effect of Accounting Change 101 015 102 061 98 156 Cumulative Effect of Accounting Change, net (Note A) 19 031 Consolidated Net Income $120 046 $102 061 $ 98 156

F-53 CONSOLIDATED STATEMENT OF RETAINED EARNINGS Balance at January 1 $412 288 $400 515 $392 331 Add: Consolidated net income 120 046 102 061 98 156 532 334 502 576 490 487 Deduct: Dividends on capital stock of the Company: Preferred stock 8 504 8 206 7 331 Common stock 90 029 82 082 82 641 Total Deductions 98 533 90 288 89 972 Balance at December 31 (Note C) $433 801 $412 288 $400 515 See accompanying notes to consolidated financial statements.

F-54 CONSOLIDATED STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31 1994 1993 1992 (Thousands of Dollars) Cash Flows from Operations: Consolidated net income $120 046 $102 061 $98 156 Depreciation 88 935 80 872 73 469 Deferred investment credit and income taxes, net 699 (10 115) 809 Deferred power costs, net 2 880 979 (1 527) Unconsolidated subsidiaries' dividends in excess of earnings 2 773 3 311 4 287 Allowance for other than borrowed funds used during construction (6 729) (5 077) (5 010) Cumulative effect of accounting change before income taxes (Note A) (32 891) Asset write-off before income taxes (Note A) 8 919 Changes in certain current assets and liabilities: Accounts receivable, net, excluding cumulative effect of accounting change (Note A) 18 951 (5 947) 8 799 Materials and supplies (9 205) 26 889 (15 593) Accounts payable (675) 3 196 3 877 Taxes accrued (4 502) 9 198 1 875 Interest accrued 2 620 (5 146) 3 534 Other, net 16 100 8 878 (8 989) 207 921 209 099 163 687 Cash Flows from Investing: Construction expenditures (260 366) (251 017) (204 409) Allowance for other than borrowed funds used during construction 6 729 5 077 5 010 (253 637) (245 940) (199 399) Cash Flows from Financing: Sale of common stock 40 000 100 000 Sale of preferred stock 39 450 Issuance of long-term debt 80 129 268 766 181 843 Retirement of long-term debt (251 414) (158 500) Deposit with trustee for redemption of long-term debt 68 354 Notes receivable from affiliates 23 900 (4 000) (20 900) Dividends on capital stock: Preferred stock (8 504) (8 206) (7 331) Common stock (90 029) (82 082) (82 641) 45 496 23 064 20 275 Net Change in Cash and Temporary Cash Investments (Note G) (220) (13 777) (15 437) Cash and Temporary Cash Investments at January 1 565 14 342 29 779 Cash and Temporary Cash Investments at December 31 $ 345 $ 565 $ 14 342 Supplemental cash flow information Cash paid during the year for: Interest (net of amount capitalized) $ 51 745 $ 61 329 $ 48 135 Income taxes 54 958 55 111 45 868 See accompanying notes to consolidated financial statements.

F-55 CONSOLIDATED BALANCE SHEET DECEMBER 31 1994 1993 (Thousands of Dollars) ASSETS Property, Plant, and Equipment: At original cost, including $103,514,000 and $283,779,000 under construction $3 013 777 $2 803 811 Accumulated depreciation (1 009 565) (962 623) 2 004 212 1 841 188 Investments and Other Assets: Allegheny Generating Company-common stock at equity (Note D) 100 228 102 830 Other 1 474 1 537 101 702 104 367 Current Assets: Cash and temporary cash investments (Note G) 345 565 Accounts receivable: Electric service, net of $8,267,000 and $1,126,000 uncollectible allowance (Note A) 119 020 94 570 Affiliated and other 11 862 22 372 Notes receivable from affiliates (Note J) 1 000 24 900 Materials and supplies-at average cost: Operating and construction 39 922 36 030 Fuel 38 205 32 892 Deferred income taxes 12 538 1 974 Prepaid and other 12 525 15 980 235 417 229 283 Deferred Charges: Regulatory assets (Note B) 364 473 331 755 Unamortized loss on reacquired debt 10 494 11 645 Other 15 560 26 525 390 527 369 925 Total $2 731 858 $2 544 763 CAPITALIZATION AND LIABILITIES Capitalization: Common stock, other paid-in capital, and retained earnings (Notes C and H) $ 955 482 $ 893 969 Preferred stock, not subject to mandatory redemption (Note H) 149 708 149 708 Long-term debt (Note I) 836 426 782 369 1 941 616 1 826 046 Current Liabilities: Long-term debt due within one year (Note I) 27 000 Accounts payable 107 792 105 493 Accounts payable to affiliates 6 477 9 451 Taxes accrued: Federal and state income 9 217 11 533 Other 20 637 22 823 Interest accrued 16 475 13 855 Other 24 028 20 954 211 626 184 109 Deferred Credits and Other Liabilities: Unamortized investment credit 52 946 55 524 Deferred income taxes 471 515 424 000 Regulatory liabilities (Note B) 39 881 40 834 Other 14 274 14 250 578 616 534 608 Commitments and Contingencies (Note K) Total $2 731 858 $2 544 763 See accompanying notes to consolidated financial statements.

<TABLE> <CAPTION> F-56 CONSOLIDATED STATEMENT OF CAPITALIZATION DECEMBER 31 1994 1993 1994 1993 (Thousands of Dollars) (Capitalization Ratios) Common Stock of the Company: Common stock-no par value, authorized 28,902,923 shares, outstanding 24,361,586 shares (issued 2,000,000 shares in 1994 and 5,000,000 shares <S> <C> <C> <C> <C> in 1993) (Note H) $465 994 $425 994 Other paid-in capital (Note H) 55 687 55 687 Retained earnings (Note C) 433 801 412 288 Total 955 482 893 969 49.2% 49.0% Preferred Stock of the Company (not subject to mandatory redemption): Cumulative preferred stock-par value $100 per share, authorized 3,097,077 shares, outstanding as follows (Note H): December 31, 1994 Regular Shares Call Price Date of Series Outstanding Per Share Issue 4-1/2% 297 077 $110.00 1939 29 708 29 708 4.20% B 50 000 102.205 1948 5 000 5 000 4.10% C 50 000 103.50 1949 5 000 5 000 $7.00 D 100 000 103.94 1967 10 000 10 000 $7.12 E 100 000 103.49 1968 10 000 10 000 $8.08 G 100 000 103.27 1971 10 000 10 000 $7.60 H 100 000 103.23 1972 10 000 10 000 $7.64 I 100 000 103.16 1973 10 000 10 000 $8.20 J 200 000 103.30 1976 20 000 20 000 Auction 400 000 100.00 1992 40 000 40 000 Total (annual dividend requirements $8,847,847) 149 708 149 708 7.7 8.2 Long-Term Debt (Note I): First mortgage bonds of the Date of Date Date Company: Issue Redeemable Due 4-7/8% U 1965 1995 1995 27 000 27 000 5-1/2% JJ 1993 1998 1998 102 000 102 000 6-3/8% KK 1993 2003 2003 80 000 80 000 7-7/8% GG 1991 2001 2004 70 000 70 000 7-3/8% HH 1992 2002 2007 45 000 45 000 9% EE 1989 1994 2019 30 000 30 000 8-7/8% FF 1991 2001 2021 100 000 100 000 7-7/8% II 1992 2002 2022 135 000 135 000 8-1/8% LL 1994 2004 2024 65 000 Interest Rate Secured notes due 1998-2024 4.95%-9.375% 202 550 187 640 Unsecured notes due 2000-2007 6.10% 14 435 14 435 Unamortized debt discount and premium, net (7 559) (7 061) Total (annual interest requirements $61,854,043) 863 426 784 014 Less current maturities 27 000 Less amount on deposit with trustee 1 645 836 426 782 369 43.1 42.8 Total Capitalization $1 941 616 $1 826 046 100.0% 100.0% See accompanying notes to consolidated financial statements. </TABLE>

F-57 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (These notes are an integral part of the consolidated financial statements.) Note A-Summary of Significant Accounting Policies: The Company is a wholly-owned subsidiary of Allegheny Power System, Inc. and is a part of the Allegheny Power integrated electric utility system (the System). The Company is subject to regulation by the Securities and Exchange Commission (SEC), by various state bodies having jurisdiction, and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below. CONSOLIDATION: The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries (the companies). REVENUES: Beginning in 1994, revenues, including amounts resulting from the application of fuel and energy cost adjustment clauses, are recognized in the same period in which the related electric services are provided to customers by recording an estimate for unbilled revenues for services provided from the meter reading date to the end of the accounting period. In 1993 and 1992, revenues were recorded for billings rendered to customers. DEFERRED POWER COSTS, NET: The costs of fuel, purchased power, and certain other costs, and revenues from sales and transmission services to other utilities, are deferred until they are either recovered from or credited to customers under fuel and energy cost recovery procedures. PROPERTY, PLANT, AND EQUIPMENT: Property, plant, and equipment, including facilities owned with affiliates in the System, are stated at original cost, less contributions in aid of construction, except for capital leases which are recorded at present value. Cost includes direct labor and material, allowance for funds used during construction (AFUDC) on property for which construction work in progress is not included in rate base, and such indirect costs as administration, maintenance, and depreciation of transportation and construction equipment, and pensions, taxes, and other fringe benefits related to employees engaged in construction. The cost of depreciable property units retired, plus removal costs less salvage, are charged to accumulated depreciation. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including "the net cost for the period of construction of borrowed funds

F-58 used for construction purposes and a reasonable rate on other funds when so used". AFUDC is recognized as a cost of property, plant, and equipment with offsetting credits to other income and interest charges. Rates used for computing AFUDC in 1994, 1993, and 1992 were 8.88%, 9.40%, and 9.25%, respectively. AFUDC is not included in the cost of such construction when the cost of financing the construction is being recovered through rates. DEPRECIATION AND MAINTENANCE: Provisions for depreciation are determined generally on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 3.5%, 3.4%, and 3.3% of average depreciable property in 1994, 1993, and 1992, respectively. The cost of maintenance and of certain replacements of property, plant, and equipment is charged principally to operating expenses. INCOME TAXES: The companies join with the parent and affiliates in filing a consolidated federal income tax return. The consolidated tax liability is allocated among the participants generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return tax liability. Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in another period. Differences between income tax expense computed on the basis of financial accounting income and taxes payable based on taxable income are accounted for substantially in accordance with the accounting procedures followed for ratemaking purposes. Deferred tax assets and liabilities recorded in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes", represent the tax effect of temporary differences between the financial statement and tax basis of assets and liabilities computed utilizing the most current tax rates. Provisions for federal income tax were reduced in previous years by investment credits, and amounts equivalent to such credits were charged to income with concurrent credits to a deferred account, balances of which are being amortized over estimated service lives of the related properties. POSTRETIREMENT BENEFITS: The Company participates with affiliated companies in the System in a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on the employee's years of service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act and not more than can be deducted for federal income tax purposes. The Company also provides partially contributory medical and life insurance plans for eligible

F-59 retirees and dependents. Medical benefits, which comprise the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. The funding plan for these costs is to contribute to Voluntary Employee Beneficiary Association (VEBA) trust funds an amount equal to the annual cost as determined by SFAS No. 106 (described below). Medical benefits are self-insured; the life insurance plan is paid through insurance premiums. The FASB has prescribed the determination of annual pension and other postretirement benefits expenses in SFAS No. 87, "Employers' Accounting for Pensions", and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", respectively. The Company records annual pension expense in accordance with SFAS No. 87. Prior to 1994, regulatory deferrals of these benefit expenses were recorded pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", for its Pennsylvania jurisdiction which reflected as net expense the funding of pensions and cash payments of other benefits in the ratemaking process. ASSET WRITE-OFF: In 1994, the Company wroteoff $8.9 million ($5.2 million net of income taxes) of previously accumulated costs related to a potential future power plant site and a proposed transmission line. In the industry's more competitive environment, it is no longer reasonable to assume future recovery of these costs in rates. ACCOUNTING CHANGES: Effective January 1, 1994, the Company changed its revenue recognition method to include the accrual of estimated unbilled revenues for electric services. This change results in a better matching of revenues and expenses, and is consistent with predominant utility industry practice. The cumulative effect of this accounting change for years prior to 1994, which is shown separately in the consolidated statement of income for 1994, resulted in a benefit of $19.0 million (after related income taxes of $13.9 million). The effect of the change on the current year's consolidated income before the cumulative effect of accounting change, as well as on 1993 and 1992 consolidated net income, is not material. Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions". Prior to 1993, medical expenses and life insurance premiums paid for retired employees and their dependents were recorded as expense in the period they were paid. Also effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes". This standard mandated a change from the previous income-based deferral approach to a balance sheet-based liability approach for computing deferred income taxes.

<TABLE> <CAPTION> F-60 Note B-Income Taxes: Details of federal and state income tax provisions are: 1994 1993 1992 (Thousands of Dollars) Income taxes-current: <S> <C> <C> <C> Federal $46 964 $47 089 $37 965 State 13 282 14 983 5 884 Total 60 246 62 072 43 849 Income taxes-deferred, net of amortization 3 277 (7 522) 3 403 Investment credit disallowed (2) Amortization of deferred investment credit (2 578) (2 592) (2 592) Total income taxes 60 945 51 958 44 658 Income taxes-credited (charged) to other income and deductions 3 300 (429) (580) Income taxes-charged to accounting change (including state income taxes) (13 860) Income taxes-charged to operating income $50 385 $51 529 $44 078 The total provision for income taxes is less than the amount produced by applying the federal income statutory tax rate to financial accounting income as set forth below: 1994 1993 1992 (Thousands of Dollars) Financial accounting income before cumulative effect of accounting change and income taxes $151 400 $153 590 $142 234 Amount so produced $ 53 000 $ 53 800 $ 48 400 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower (excess) tax depreciation 2 000 100 (200) Plant removal costs (1 700) (900) (2 500) State income tax, net of federal income tax benefit 6 400 9 600 7 600 Amortization of deferred investment credit (2 578) (2 592) (2 592) Equity in earnings of subsidiaries (4 600) (4 300) (4 700) Other, net (2 137) (4 179) (1 930) Total $ 50 385 $ 51 529 $ 44 078 Federal income tax returns through 1991 have been examined and substantially settled. </TABLE>

F-61 In adopting SFAS No. 109, the Company recognized a significant increase in both deferred tax assets and liabilities. At December 31, the deferred tax assets and liabilities were comprised of the following: 1994 1993 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credit $ 38 560 $ 40 455 Unbilled revenue 9 539 21 626 Tax interest capitalized 16 165 10 750 State tax loss carryback/carryforward 5 535 8 790 Contributions in aid of construction 4 866 4 588 Other 18 905 7 416 93 570 93 625 Deferred tax liabilities: Book vs. tax plant basis differences, net 536 343 507 214 Other 16 204 8 437 552 547 515 651 Total net deferred tax liabilities 458 977 422 026 Add portion above included in current assets 12 538 1 974 Total long-term net deferred tax liabilities $471 515 $424 000 It is expected that regulatory commissions will allow recovery of the deferred tax liabilities in future years as they are paid, and accordingly, the Company has recorded regulatory assets of $351 million which offset the increase in deferred tax liabilities. Regulatory liabilities of $39 million have been recorded which offset the increase in deferred tax assets in order to reflect the Company's obligation to pass such tax benefits on to its customers as the benefits are realized in cash in future years. Note C-Dividend Restriction: Supplemental indentures relating to most outstanding bonds of the Company contain dividend restrictions under the most restrictive of which $285,914,000 of consolidated retained earnings at December 31, 1994, is not available for cash dividends on common stock, except that a portion thereof may be paid as cash dividends where concurrently an equivalent amount of cash is received by the Company as a capital contribution or as the proceeds of the issue and sale of shares of its common stock. Note D-Allegheny Generating Company: The Company owns 45% of the common stock of Allegheny Generating Company (AGC), and affiliates of the Company own the remainder. AGC owns an undivided 40% interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric station in Bath County, Virginia, operated by the 60% owner, Virginia Power Company, a nonaffiliated utility. AGC recovers from the Company and its affiliates all of its operation and maintenance expenses, depreciation, taxes, and a return on its investment under a wholesale rate schedule approved by the FERC. Through February 29, 1992, AGC's return on equity

F-62 (ROE) was adjusted annually pursuant to a settlement agreement approved by the FERC. In December 1991, AGC filed for a continuation of the existing ROE of 11.53% and other parties (the Consumer Advocate Division of the Public Service Commission of West Virginia, Maryland People's Counsel, and Pennsylvania Office of Consumer Advocate, collectively referred to as the joint consumer advocates or JCA) filed to reduce the ROE to 10%. Hearings were completed in June 1992, and a recommendation was issued by an Administrative Law Judge (ALJ) on December 21, 1993, for an ROE of 10.83%, which the JCA argues should be further adjusted to reflect changes in capital market conditions since the hearings. Exceptions to this recommendation were filed by all parties for consideration by the FERC. On January 28, 1994, the JCA filed a joint complaint with the FERC against AGC claiming that both the existing ROE of 11.53% and the ROE recommended by the ALJ of 10.83% were unjust and unreasonable. This new complaint requested an ROE of 8.53% with rates subject to refund beginning April 1, 1994. Hearings were completed in November 1994 and a recommendation was issued by an ALJ on December 22, 1994, dismissing the JCA's complaint. A settlement agreement for both cases is currently pending, which would reduce AGC's ROE to 11.13% for the period from March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.20% for the period from January 1, 1995, through December 31, 1995. Following is a summary of financial information for AGC: December 31 1994 1993 (Thousands of Dollars) Balance sheet information: Property, plant, and equipment $680 749 $696 529 Current assets 5 991 11 063 Deferred charges 27 496 28 337 Total assets $714 236 $735 929 Total capitalization $489 894 $505 708 Current liabilities 6 484 21 891 Deferred credits 217 858 208 330 Total capitalization and liabilities $714 236 $735 929 <TABLE> <CAPTION> Year Ended December 31 1994 1993 1992 (Thousands of Dollars) Income statement information: <S> <C> <C> <C> Electric operating revenues $91 022 $90 606 $96 147 Operation and maintenance expense 6 695 6 609 6 094 Depreciation 16 852 16 899 16 827 Taxes other than income taxes 5 223 5 347 5 236 Federal income taxes 14 737 13 262 14 702 Interest charges 17 809 21 635 22 585 Other income, net (11) (328) (21) Net income $29 717 $27 182 $30 724 </TABLE> Results for 1994 reflect the effect of the pending settlement agreement. The Company's share of the equity in earnings above was $13.4 million, $12.2 million, and $13.8 million for 1994, 1993, and 1992, respectively, and is included in other income, net, on the Consolidated Statement of Income.

F-63 Note E-Pension Benefits: The Company's share of net pension costs under the System's pension plan, a portion of which (about 25% to 30%) was charged to plant construction, included the following components: <TABLE> <CAPTION> 1994 1993 1992 (Thousands of Dollars) <S> <C> <C> <C> Service cost - benefits earned $ 5 124 $ 4 606 $ 4 272 Interest cost on projected benefit obligation 14 051 13 773 13 312 Actual loss (return) on plan assets 358 (31 224) (24 750) Net amortization and deferral (18 210) 14 262 (8 388) SFAS No. 87 pension cost 1 323 1 417 1 222 Regulatory deferral $ - (1 309) (1 222) Net pension cost $ 1 323 $ 108 $ - </TABLE> Regulatory deferrals amounting to $3,039,000 will be amortized to operating expenses over the four-year period 1995 through 1998 in accordance with authorized rate recovery. An additional $833,000 regulatory deferral was charged to plant construction in 1994. The benefits earned to date and funded status of the Company's share of the System plan at December 31 using a measurement date of September 30 were as follows: 1994 1993 (Thousands of Dollars) Actuarial present value of accumulated benefit obligation earned to date (including vested benefit of $150,168,000 and $151,394,000) $158 578 $160 097 Funded status: Actuarial present value of projected benefit obligation $191 787 $199 414 Plan assets at market value, primarily common stocks and fixed income securities 207 623 219 625 Plan assets in excess of projected benefit obligation (15 836) (20 211) Add: Unrecognized cumulative net gain from past experience different from that assumed 15 103 17 586 Unamortized transition asset, being amortized over 14 years beginning January 1, 1987 8 427 9 678 Less unrecognized prior service cost due to plan amendments 4 999 5 678 Pension cost liability at September 30 2 695 1 375 Fourth quarter contributions 2 843 - Pension (prepayment) liability at December 31 $ (148) $ 1 375 The foregoing includes the Company's portion of amounts applicable to employees at power stations which are owned jointly with affiliates. In determining the actuarial present value of the projected benefit obligation at September 30, 1994, 1993, and 1992, the discount rates used were 7.75%, 7.25%, and 7.75%, and the rates of increase in future compensation levels were 4.75%, 4.75%, and

F-64 5.25%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1994, 1993, and 1992. Note F-Postretirement Benefits Other Than Pensions: The Company adopted SFAS No. 106 as of January 1, 1993, which requires accrual of postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents during the years the employees render the necessary service to receive such benefits. Prior to 1993, medical expenses and life insurance premiums paid by the Company for retired employees and their dependents were recorded in expense in the period in which they were paid ($1,907,000 in 1992). SFAS No. 106 postretirement cost in 1994 and 1993, a portion of which (about 25% to 30%) was charged to plant construction, included the following components: 1994 1993 (Thousands of Dollars) Service cost - benefits earned $1 154 $ 939 Interest cost on accumulated postretirement benefit obligation 4 461 4 389 Actual loss (return) on plan assets 31 (9) Amortization of unrecognized transition obligation 2 817 2 817 Other net amortization and deferral 83 9 SFAS No. 106 postretirement cost 8 546 8 145 Regulatory deferral - (1 963) Net postretirement cost $8 546 $6 182 The benefits earned to date and funded status of the Company's share of the System plan at December 31 using a measurement date of September 30 were as follows: 1994 1993 (Thousands of Dollars) Accumulated postretirement benefit obligation: Retirees $35 895 $35 748 Fully eligible employees 8 290 9 030 Other employees 17 013 18 378 Total obligation 61 198 63 156 Plan assets at market value 6 173 1 510 Accumulated postretirement benefit obligation in excess of plan assets 55 025 61 646 Less: Unrecognized cumulative net (gain) loss from past experience different from that assumed (543) 3 362 Unrecognized transition obligation, being amortized over 20 years beginning January 1, 1993 50 929 53 746 Postretirement benefit liability at September 30 4 639 4 538 Fourth quarter contributions and benefit payments 2 113 1 960 Postretirement benefit liability at December 31 $2 526 $2 578

F-65 The plan assets at market value are comprised of fixed income securities, common stocks, and a short-term investment fund in 1994; and a short-term investment fund in 1993. The unfunded accumulated postretirement benefit obligation (APBO) at January 1, 1993, of $56,600,000 (transition obligation) is being amortized prospectively over 20 years as permitted by SFAS No. 106. In determining the APBO at September 30, 1994, 1993, and 1992, the discount rates used were 7.75%, 7.25%, and 8%, and the rates of increase in future compensation levels were 4.75%, 4.75%, and 5.5%, respectively. The 1994 expected long-term rate of return on assets was 8.25% net of tax. For measurement purposes, a health care trend rate of 9% for 1995, declining 1% each year thereafter to 6.75% in the year 1998 and beyond, and plan provisions which limit future medical and life insurance benefits, were assumed. Increasing the assumed health care trend rate by 1% in each year would increase the APBO at December 31, 1994, by $4.2 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1994 by $.4 million. The Company has been authorized recovery of SFAS No. 106 expenses in rates. Note G-Fair Value of Financial Instruments: The carrying amounts and estimated fair value of financial instruments at December 31, 1994 and 1993 were as follows: <TABLE> <CAPTION> 1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Assets: <S> <C> <C> <C> <C> Temporary cash investments $ 73 $ 73 $ 244 $ 244 Liabilities: Long-term debt 870 985 826 003 791 075 823 333 </TABLE> The carrying amount of temporary cash investments approximates the fair value because of the short maturity of those instruments. The fair value of long-term debt was estimated based on actual market prices or market prices of similar issues. The Company does not have any financial instruments held or issued for trading purposes. For purposes of the consolidated statement of cash flows, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, and repurchase agreements, are considered to be the equivalent of cash. Note H-Stockholders' Equity: COMMON STOCK AND OTHER PAID-IN CAPITAL: The Company issued and sold common stock to its parent, at $20 per share, 2,000,000 shares in October 1994 and 5,000,000 shares in October 1993. Other paid-in capital decreased $145,000 in 1993 and $550,000 in 1992 as a result of the underwriting fees and commissions and miscellaneous expenses associated with the Company's sale of $40 million of preferred stock in 1992.

F-66 PREFERRED STOCK: All of the preferred stock is entitled on voluntary liquidation to its then current call price and on involuntary liquidation to $100 per share. The holders of the Company's market auction preferred stock are entitled to dividends at a rate determined by an auction held the business day preceding each quarterly dividend payment date. Note I-Long-Term Debt: Maturities for long-term debt for the next five years are: 1995, $27,000,000; 1996 and 1997, none; 1998, $103,500,000; and 1999, $2,500,000. Substantially all of the properties of the Company are held subject to the lien securing its first mortgage bonds. Some properties are also subject to a second lien securing certain pollution control and solid waste disposal notes. Certain first mortgage bond series are not redeemable by certain refunding until dates established in the respective supplemental indentures. Note J-Short-Term Financing: To provide interim financing and support for outstanding commercial paper, the System companies have established lines of credit with several banks. The Company has SEC authorization for total short-term borrowings of $170 million, including money pool borrowings described below. The Company has fee arrangements on all of its lines of credit and no compensating balance requirements. In addition to bank lines of credit, an internal money pool accommodates intercompany short-term borrowing needs, to the extent that certain of the companies have funds available. In January 1994, the Company and its affiliates jointly established an aggregate $300 million multi-year credit program which provides that the Company may borrow up to $135 million on a standby revolving credit basis. There was no short-term debt outstanding at the end of 1994 or 1993. Average short-term debt outstanding during the year for 1994 and 1993 consisted of: 1994 1993 (Thousands of Dollars) Average amount outstanding during the year: Commercial Paper $2,216-4.38% - Notes Payable to Banks 2,379-4.37% $9,081-3.18% Money Pool 521-4.24% 1,166-3.01% Note K-Commitments and Contingencies: CONSTRUCTION PROGRAM: The Company has entered into commitments for its construction program, for which expenditures are estimated to be $172 million for 1995 and $115 million for 1996. These estimates include expenditures for the program of complying with the Clean Air Act Amendments of 1990 (CAAA) as discussed below.

F-67 ENVIRONMENTAL MATTERS: System companies are subject to various laws, regulations, and uncertainties as to environmental matters. Compliance may require them to incur substantial additional costs to modify or replace existing and proposed equipment and facilities and may affect adversely the lead time, size, and siting of future generating stations, increase the complexity and cost of pollution control equipment, and otherwise add to the cost of future operations. Construction estimates for 1995 and 1996 include $38 million and $1 million, respectively, for compliance with Phase I of the CAAA. Through 1998, annual construction expenditures, on average, are not expected to significantly vary from 1995 estimated levels. Construction expenditure levels in 1999 and beyond will depend upon the strategy eventually selected for complying with Phase II of the CAAA, as well as future generation requirements. LITIGATION AND OTHER: In the normal course of business, the Company becomes involved in various legal proceedings. The Company does not believe that the ultimate outcome of these proceedings will have a material effect on its financial position. The Company is guarantor as to 45% of a $50 million revolving credit agreement of AGC, which in 1994 was used by AGC solely as support for its indebtedness for commercial paper outstanding.

F-68 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of Allegheny Generating Company In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Allegheny Generating Company (an Allegheny Power System, Inc. affiliate) at December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Notes A and B to the financial statements, the Company changed its method of accounting for income taxes in 1993. PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP New York, New York February 2, 1995

<TABLE> <CAPTION> F-69 STATEMENT OF INCOME YEAR ENDED DECEMBER 31 1994 1993 1992 (Thousands of Dollars) <S> <C> <C> <C> Electric Operating Revenues $91 022 $90 606 $96 147 Operating Expenses: Operation and maintenance expense 6 695 6 609 6 094 Depreciation 16 852 16 899 16 827 Taxes other than income taxes 5 223 5 347 5 236 Federal income taxes (Note B) 14 737 13 262 14 702 Total Operating Expenses 43 507 42 117 42 859 Operating Income 47 515 48 489 53 288 Other Income and Deductions 11 328 21 Income Before Interest Charges 47 526 48 817 53 309 Interest Charges: Interest on long-term debt 16 863 21 185 22 285 Other interest 946 450 300 Total Interest Charges 17 809 21 635 22 585 Net Income $29 717 $27 182 $30 724 </TABLE>

<TABLE> <CAPTION> F-70 STATEMENT OF RETAINED EARNINGS <S> <C> <C> <C> Balance at January 1 $18 512 $25 530 $34 593 Add: Net income 29 717 27 182 30 724 48 229 52 712 65 317 Deduct: Dividends on common stock 35 500 34 200 39 787 Balance at December 31 $12 729 $18 512 $25 530 See accompanying notes to financial statements. </TABLE>

<TABLE> <CAPTION> F-71 STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31 1994 1993 1992 (Thousands of Dollars) Cash Flows from Operations: <S> <C> <C> <C> Net income $29 717 $27 182 $30 724 Depreciation 16 852 16 899 16 827 Deferred investment credit and income taxes, net 9 567 5 321 6 437 Changes in certain current assets and liabilities: Accounts receivable 7 099 (6 118) (11) Materials and supplies (2) (163) 131 Accounts payable 37 6 (242) Taxes accrued (216) (153) (766) Interest accrued (200) 632 361 Other, net (7 133) 4 851 1 853 55 721 48 457 55 314 Cash Flows from Investing: Construction expenditures (1 065) (2 739) (3 251) Cash Flows from Financing: Issuance of long-term debt 198 075 2 364 Retirement of long-term debt (19 126) (209 598) (14 842) Cash dividends on common stock (35 500) (34 200) (39 787) (54 626) (45 723) (52 265) Net Change in Cash 30 (5) (202) Cash at January 1 15 20 222 Cash at December 31 $ 45 $ 15 $ 20 Supplemental cash flow information Cash paid during the year for: Interest $17 078 $21 109 $22 062 Income taxes 7 137 8 220 9 027 See accompanying notes to financial statements. </TABLE>

F-72 BALANCE SHEET DECEMBER 31 1994 1993 (Thousands of Dollars) ASSETS Property, Plant, and Equipment: At original cost, including $21,000 and $2,212,000 under construction $824 714 $824 904 Accumulated depreciation (143 965) (128 375) 680 749 696 529 Current Assets: Cash 45 15 Accounts receivable from parents 1 516 8 615 Materials and supplies - at average cost 2 193 2 191 Other 2 237 242 5 991 11 063 Deferred Charges: Regulatory assets (Note B) 4 449 4 489 Unamortized loss on reacquired debt 10 653 11 374 Other 12 394 12 474 27 496 28 337 Total $714 236 $735 929

F-73 CAPITALIZATION AND LIABILITIES Capitalization: Common stock - $1.00 par value per share, authorized 5,000 shares, outstanding 1,000 shares $ 1 $ 1 Other paid-in capital 209 999 209 999 Retained earnings 12 729 18 512 222 729 228 512 Long-term debt (Note D) 267 165 277 196 489 894 505 708 Current Liabilities: Long-term debt due within one year (Note D) 1 000 10 000 Accounts payable 48 11 Interest accrued 4 900 5 100 Taxes accrued 33 249 Other 503 6 531 6 484 21 891 Deferred Credits: Unamortized investment credit 52 297 53 613 Deferred income taxes 137 297 125 848 Regulatory liabilities (Note B) 28 264 28 869 217 858 208 330 Total $714 236 $735 929 See accompanying notes to financial statements.

F-74 NOTES TO FINANCIAL STATEMENTS (These notes are an integral part of the financial statements.) Note A Summary of Significant Accounting Policies: The Company was incorporated in Virginia in 1981. Its common stock is owned by Monongahela Power Company - 27%, The Potomac Edison Company - 28%, and West Penn Power Company - 45% (the Parents). The Parents are wholly-owned subsidiaries of Allegheny Power System, Inc. and are a part of the Allegheny Power integrated electric utility system. The Company is subject to regulation by the Securities and Exchange Commission (SEC) and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below. PROPERTY, PLANT, AND EQUIPMENT: Property, plant, and equipment are stated at original cost, and consist of a 40% undivided interest in the Bath County pumped-storage hydroelectric station and its connecting transmission facilities. The cost of depreciable property units retired plus removal costs less salvage are charged to accumulated depreciation. DEPRECIATION AND MAINTENANCE: Provisions for depreciation are determined on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 2.1% of average depreciable property in each of the years 1994, 1993, and 1992. The cost of maintenance and of certain replacements of property, plant, and equipment is charged to operating expenses. INCOME TAXES: The Company joins with its parents and affiliates in filing a consolidated federal income tax return. The consolidated tax liability is allocated among the participants generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return tax liability. Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in another period. Differences between income tax expense computed on the basis of financial accounting income and taxes payable based on taxable income are deferred. Deferred tax assets and liabilities recorded in accordance with the Financial Accounting Standards Board Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes", represent the tax effect of temporary differences between the financial statement and tax basis of assets and liabilities computed utilizing the most current tax rates. Prior to 1987, provisions for federal income tax were reduced by investment credits, and amounts equivalent to such credits were charged to income with concurrent credits to a deferred

F-75 account, balances of which are being amortized over estimated service lives of the related properties. ACCOUNTING CHANGE: Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes". This standard mandated a change from the previous income-based deferral approach to a balance sheet-based liability approach for computing deferred income taxes. Note B Income Taxes: Details of federal income tax provisions are: <TABLE> <CAPTION> 1994 1993 1992 (Thousands of Dollars) <S> <C> <C> <C> Current income taxes payable $ 5 176 $ 8 112 $ 8 276 Deferred income taxes - accelerated depreciation 10 883 6 637 7 758 Investment credit adjustment Amortization of deferred investment credit (1 316) (1 316) (1 322) Total income taxes 14 743 13 433 14 713 Income taxes-charged to other income (6) (171) (11) Income taxes-charged to operating income $14 737 $13 262 $14 702 </TABLE> In 1994, the total provision for income taxes ($14,737,000) was less than the amount produced by applying the federal income tax statutory rate to financial accounting income before income taxes ($15,559,000), due primarily to amortization of deferred investment credit ($1,316,000). Federal income tax returns through 1991 have been examined and substantially settled. In adopting SFAS No. 109, the Company recognized a significant increase in both deferred tax assets and liabilities. At December 31, the deferred tax assets and liabilities were comprised of the following: 1994 1993 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credit $ 28 160 $ 28 869 Other 104 28 264 28 869 Deferred tax liabilities: Book vs. tax plant basis differences, net 165 561 154 565 Other 152 165 561 154 717 Total net deferred tax liabilities $137 297 $125 848

F-76 It is expected the FERC will allow recovery of the deferred tax liabilities in future years as they are paid, and accordingly, the Company has recorded regulatory assets of $4 million which offset the increase in deferred tax liabilities. Regulatory liabilities of $28 million have been recorded which offset the increase in deferred tax assets in order to reflect the Company's obligation to pass such tax benefits on to its customers as the benefits are realized in cash in future years. Note C Fair Value of Financial Instruments: The carrying amounts and estimated fair value of financial instruments at December 31, 1994 and 1993 were as follows: <TABLE> <CAPTION> 1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Liabilities: Long-term debt: <S> <C> <C> <C> <C> Debentures $150 000 $120 195 $150 000 $142 730 Medium-term notes 77 975 73 704 87 975 90 715 Commercial paper 41 736 41 736 21 362 21 362 Notes payable to affiliates - - 29 500 29 500 </TABLE> The carrying amount of debentures and medium-term notes was based on actual market prices or market prices of similar issues. The carrying amount of commercial paper and notes payable to affiliates approximates the fair value because of the short maturity of those instruments. The Company does not have any financial instruments held or issued for trading purposes.

F-77 Note D Long-Term Debt: The Company had long-term debt outstanding as follows: Interest December 31 Rate - % 1994 1993 (Thousands of Dollars) Debentures due: September 1, 2003 5.625 $ 50 000 $ 50 000 September 1, 2023 6.875 100 000 100 000 Commercial paper 6.25 (1) 41 736 21 362 Medium-term notes due 1994-1998 6.37 (1) 77 975 87 975 Notes payable to affiliates 2.85 (2) 29 500 Unamortized debt discount (1 546) (1 641) Total $268 165 $287 196 Less current maturities 1 000 10 000 Total $267 165 $277 196 (1) Weighted average interest rate at December 31, 1994. (2) Weighted average interest rate at December 31, 1993. The Company has a revolving credit agreement with a group of seven banks which provides for loans of up to $50 million at any one time outstanding through 1998. Each bank has the option to discontinue its loans after 1998 upon three years' prior written notice. Without such notice, the loans are automatically extended for one year. Amounts borrowed are guaranteed by the Parents in proportion to their equity interest. Interest rates are determined at the time of each borrowing. The revolving credit agreement serves as support for the Company's commercial paper. In addition to bank lines of credit, an internal money pool accommodates intercompany short-term borrowing needs, to the extent that certain of the Company's affiliates have funds available. At the end of 1993, the Company had outstanding $29,500,000 of money pool borrowings from affiliates. Maturities for long-term debt for the next five years are: 1995, $1,000,000; 1996, $6,375,000; 1997, $10,600,000; 1998, $101,736,000; and 1999, none.

<TABLE> <CAPTION> S-1 SCHEDULE II ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES Valuation and Qualifying Accounts For Years Ended December 31, 1994, 1993, and 1992 Col. A Col. B Col. C Col. D Col. E Additions Balance at Charged to Charged to Balance at beginning costs and other end of Description of period expenses accounts Deductions period (A) (B) Allowance for uncollectible accounts: <S> <C> <C> <C> <C> <C> Year ended December 31, 1994 $ 3 418 261 $14 714 000 $ 3 060 544 $ 9 840 131 $11 352 674 Year ended December 31, 1993 $ 3 364 104 $ 5 732 000 $ 2 546 341 $ 8 224 184 $ 3 418 261 Year ended December 31, 1992 $ 3 744 270 $ 5 160 000 $ 2 253 279 $ 7 793 445 $ 3 364 104 (A) Recoveries. (B) Uncollectible accounts charged off. </TABLE>

<TABLE> <CAPTION> S-2 SCHEDULE II MONONGAHELA POWER COMPANY Valuation and Qualifying Accounts For Years Ended December 31, 1994, 1993, and 1992 Col. A Col. B Col. C Col. D Col. E Additions Balance at Charged to Charged to Balance at beginning costs and other end of Description of period expenses accounts Deductions period (A) (B) Allowance for uncollectible accounts: <S> <C> <C> <C> <C> <C> Year ended December 31, 1994 $ 1 084 037 $ 2 240 000 $ 667 910 $ 2 081 342 $ 1 910 605 Year ended December 31, 1993 $ 1 056 010 $ 1 210 000 $ 604 387 $ 1 786 360 $ 1 084 037 Year ended December 31, 1992 $ 1 080 499 $ 1 215 000 $ 597 147 $ 1 836 636 $ 1 056 010 (A) Recoveries. (B) Uncollectible accounts charged off. </TABLE>

<TABLE> <CAPTION> S-3 SCHEDULE II THE POTOMAC EDISON COMPANY Valuation and Qualifying Accounts For Years Ended December 31, 1994, 1993, and 1992 Col. A Col. B Col. C Col. D Col. E Additions Balance at Charged to Charged to Balance at beginning costs and other end of Description of period expenses accounts Deductions period (A) (B) Allowance for uncollectible accounts: <S> <C> <C> <C> <C> <C> Year ended December 31, 1994 $ 1 207 979 $ 1 624 000 $ 1 007 652 $ 2 664 194 $ 1 175 437 Year ended December 31, 1993 $ 1 178 009 $ 1 412 000 $ 790 089 $ 2 172 119 $ 1 207 979 Year ended December 31, 1992 $ 1 214 562 $ 1 325 000 $ 684 931 $ 2 046 484 $ 1 178 009 (A) Recoveries. (B) Uncollectible accounts charged off. </TABLE>

<TABLE> <CAPTION> S-4 SCHEDULE II WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES Valuation and Qualifying Accounts For Years Ended December 31, 1994, 1993, and 1992 Col. A Col. B Col. C Col. D Col. E Additions Balance at Charged to Charged to Balance at beginning costs and other end of Description of period expenses accounts Deductions period (A) (B) Allowance for uncollectible accounts: <S> <C> <C> <C> <C> <C> Year ended December 31, 1994 $ 1 126 244 $10 850 000 $ 1 384 982 $ 5 094 594 $ 8 266 632 Year ended December 31, 1993 $ 1 130 085 $ 3 110 000 $ 1 151 865 $ 4 265 706 $ 1 126 244 Year ended December 31, 1992 $ 1 449 209 $ 2 620 000 $ 971 201 $ 3 910 325 $ 1 130 085 (A) Recoveries. (B) Uncollectible accounts charged off. </TABLE>

<TABLE> <CAPTION> Supplementary Data Quarterly Financial Data (Unaudited) (Thousands of Dollars) Income Before Electric Operating Cumulative Effect of 1994 Revenues Operating Income Accounting Change Quarter ended Reported Restated Reported Restated Reported Restated APS <C> <C> <C> <C> <C> <C> <C> March 1994 $704 332 $697 299 $118 157 $115 118 $ 78 904 $ 75 865 June 1994 569 261 561 217 83 498 79 717 43 148 39 367 September 1994 595 313 591 123 92 946 90 855 51 898 49 807 December 1994 582 778 602 045 93 540 102 451 45 801 54 712 March 1993 614 678 107 524 67 609 June 1993 552 380 83 292 44 358 September 1993 583 311 94 119 54 527 December 1993 581 157 89 704 49 262 Monongahela March 1994 187 909 24 294 17 580 June 1994 157 940 16 855 10 222 September 1994 165 932 20 613 13 523 December 1994 168 349 25 473 18 611 March 1993 165 542 24 289 18 252 June 1993 145 241 17 174 11 571 September 1993 165 489 22 038 15 787 December 1993 165 572 22 802 16 088 Potomac Edison March 1994 226 901 223 648 39 028 37 350 32 285 30 607 June 1994 177 038 171 047 23 976 20 934 16 102 13 060 September 1994 180 971 179 114 24 359 23 109 16 278 15 028 December 1994 174 455 185 556 24 959 30 929 17 318 23 288 March 1993 196 182 33 963 26 779 June 1993 170 732 24 852 17 514 September 1993 172 780 23 605 17 372 December 1993 172 891 19 296 11 802 West Penn March 1994 324 831 321 051 43 501 42 139 34 027 32 665 June 1994 266 000 263 946 31 616 30 877 22 745 22 006 September 1994 276 491 274 161 36 417 35 578 27 584 26 745 December 1994 260 920 269 084 30 360 33 300 16 659 19 599 March 1993 280 018 37 151 27 647 June 1993 259 873 29 284 20 311 September 1993 271 466 36 475 26 121 December 1993 273 620 38 442 27 982 AGC March 1994 22 431 11 509 7 085 June 1994 21 869 11 253 6 771 September 1994 22 337 11 551 7 087 December 1994 24 385 13 202 8 774 March 1993 23 423 12 818 7 219 June 1993 23 730 12 745 7 478 September 1993 23 391 12 555 7 365 December 1993 20 062 10 371 5 120 </TABLE>

<TABLE> <CAPTION> Supplementary Data (continued) Quarterly Financial Data (Unaudited) (Thousands of Dollars) Earnings Per Share Before Cumulative Effect of 1994 Net Income Accounting Change Earnings Per Share Quarter ended Reported Restated Reported Restated Reported Restated APS <C> <C> <C> <C> <C> <C> <C> March 1994 $ 78 904 $119 311 $ .67 $ .65 $ .67 $ 1.02 June 1994 43 148 39 367 .37 .33 .37 .33 September 1994 51 898 49 807 .44 .42 .44 .42 December 1994 45 801 54 712 .38 .46 .38 .46 March 1993 67 609 .59 .59 June 1993 44 358 .39 .39 September 1993 54 527 .48 .48 December 1993 49 262 .42 .42 Monongahela March 1994 17 580 25 525 June 1994 10 222 10 222 September 1994 13 523 13 523 December 1994 18 611 18 611 March 1993 18 252 June 1993 11 571 September 1993 15 787 December 1993 16 088 Potomac Edison March 1994 32 285 47 078 June 1994 16 102 13 060 September 1994 16 278 15 028 December 1994 17 318 23 288 March 1993 26 779 June 1993 17 514 September 1993 17 372 December 1993 11 802 West Penn March 1994 34 027 51 696 June 1994 22 745 22 006 September 1994 27 584 26 745 December 1994 16 659 19 599 March 1993 27 647 June 1993 20 311 September 1993 26 121 December 1993 27 982 AGC March 1994 7 085 June 1994 6 771 September 1994 7 087 December 1994 8 774 March 1993 7 219 June 1993 7 478 September 1993 7 365 December 1993 5 120 </TABLE>

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE For APS and the Subsidiaries, none.

<TABLE> <CAPTION> PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS APS, Monongahela, Potomac Edison, West Penn, and AGC. Reference is made to the Executive Officers of the Registrants in Part I of this report. The names, ages, and the business experience during the past five years of the directors of the System companies are set forth below: Business Experience during Director since date shown of Name the Past Five Years Age APS MP PE WP AGC <S> <C> <C> <C> <C> <C> <C> Eleanor Baum See below (a) 54 1988 1988 1988 1988 William L. Bennett See below (b) 45 1991 1991 1991 1991 Klaus Bergman System employee (1) 63 1985 1985 1985 1979 1982 Stanley I. Garnett, II System employee (1) 51 1990 1990 1990 1990 Benjamin H. Hayes* System employee (1) 60 1992 Wendell F. Holland** See below (c) 42 1994 1994 1994 1994 Kenneth M. Jones System employee (1) 57 1991 Phillip E. Lint See below (d) 65 1989 1989 1989 1989 Edward H. Malone See below (e) 70 1985 1985 1985 1985 Frank A. Metz, Jr. See below (f) 60 1984 1984 1984 1984 Clarence F. Michalis*** See below (g) 72 1973 1973 1973 1973 Alan J. Noia System employee (1) 47 1994 1994 1987 1994 1994 Jay S. Pifer System employee (1) 57 1995 1995 1992 Steven H. Rice See below (h) 51 1986 1986 1986 1986 Gunnar E. Sarsten See below (i) 57 1992 1992 1992 1992 Peter L. Shea See below (j) 62 1993 1993 1993 1993 Peter J. Skrgic System employee (1) 53 1990 1990 1990 1989 (1) See Executive Officers of the Registrants in Part I of this report for further details. (a) Eleanor Baum. Dean of The Albert Nerken School of Engineering of The Cooper Union for the Advancement of Science and Art. Director of Avnet, Inc. and United States Trust Company. Commissioner of the Engineering Manpower Commission, a fellow of the Institute of Electrical and Electronic Engineers, member of Board of Governors, New York Academy of Sciences and President, American Society of Engineering Education. (b) William L. Bennett. Chairman, Director and Chief Executive Officer of Noel Group, Inc. Director of Belding Heminway Company, Inc., Global Natural Resources Inc., Lincoln Snacks Company, Simmons Outdoor Corporation, Sylvan, Inc. and TDX Corporation. Formerly, general partner, Discovery Funds, a venture capital affiliate of Rockefeller & Company, Inc. (c) Wendell F. Holland. Of Counsel, Law Firm of Reed, Smith, Shaw & McClay. Formerly, Partner, Law Firm of LeBoeuf, Lamb, Greene & MacRae, and Commissioner of the Pennsylvania Public Utility Commission. (d) Phillip E. Lint. Retired. Formerly, partner, Price Waterhouse. (e) Edward H. Malone. Retired. Formerly, Vice President of General Electric Company and Chairman, General Electric Investment Corporation. Director of Fidelity Group of Mutual Funds, General Re Corporation, and Mattel, Inc. (f) Frank A. Metz, Jr. Retired. Formerly, Senior Vice President, Finance and Planning, and Director, International Business Machines Corporation. Director of Monsanto Company and Norrell Corporation. (g) Clarence F. Michalis. Chairman of the Board of Directors of Josiah Macy, Jr. Foundation, a tax-exempt foundation for medical research and education. Director of Schroder Capital Funds Inc. (h) Steven H. Rice. Bank consultant and attorney-at-law. Director and Vice Chairman of the Board of Stamford Federal Savings Bank. Formerly, President and Chief Operating Officer and Director of The Seamen's Bank for Savings and Director of Royal Group, Inc. (The Royal Insurance Companies). (i) Gunnar E. Sarsten. Chairman and Chief Executive Officer of MK International. Formerly, President and Chief Operating Officer of Morrison Knudsen Corporation, President and Chief Executive Officer of United Engineers & Constructors International, Inc., (now Raytheon Engineers & Constructors, Inc.), and Deputy Chairman of the Third District Federal Reserve Bank in Philadelphia. (j) Peter L. Shea. Managing director of Hydrocarbon Energy, Inc., a privately owned oil and gas development drilling and production company and an Individual General Partner of Panther Partners, L.P., a closed-end, non-diversified, management company. * Benjamin H. Hayes retired effective January 1, 1995. ** Wendell F. Holland became a director effective September 8, 1994. *** Clarence F. Michalis retired effective May 1, 1994. </TABLE>

<TABLE> <CAPTION> ITEM ll. EXECUTIVE COMPENSATION During 1994, and for 1993 and 1992, the annual compensation paid by each of the System companies, APS, APSC, Monongahela, Potomac Edison, West Penn, and AGC directly or indirectly for services in all capacities to such companies to their Chief Executive Officer and each of the four most highly paid executive officers of each such company whose cash compensation exceeded $100,000 was as follows: Summary Compensation Tables APS Annual Compensation (a) Other All Name Annual Other and Compen- Compen- Principal sation sation Position Year Salary($) Bonus($)(b) ($)(c) ($)(d)(e) <S> <C> <C> <C> <C> <C> Klaus Bergman, 1994 485,004 120,000 91,458 Chief Executive 1993 460,008 90,000 46,889 Officer (f) 1992 445,008 80,000 13,529 Alan J. Noia, 1994 236,336 57,000 47,867 President (f)(g) 1993 212,500 37,000 20,107 1992 200,000 38,000 7,975 Stanley I. Garnett, II 1994 219,336 47,000 70,213 Senior Vice President (f) 1993 206,004 40,000 24,006 1992 195,600 35,000 7,939 Peter J. Skrgic 1994 213,336 50,000 57,253 Senior Vice President (f) 1993 185,004 38,000 (h) 18,678 1992 175,008 31,000 (h) 8,325 Nancy H. Gormley 1994 175,008 37,000 22,478 Vice President (f) 1993 162,504 28,000 15,446 1992 150,000 28,000 8,159 (a) APS has no paid employees. All salaries and bonuses are paid by APSC. (b) Incentive awards are based upon performance in the year in which the figure appears but are paid in the second quarter of the following year. The incentive award plan will be continued for 1995. (c) Amounts constituting less than 10% of the total annual salary and bonus are not disclosed. All officers did receive miscellaneous other items amounting to less than 10% of total annual salary and bonus. (d) Effective January 1, 1992, the basic group life insurance provided employees was reduced from two times salary during employment, which reduced to one times salary after 5 years in retirement, to a new plan which provides one times salary until retirement and $25,000 thereafter. Executive officers and other senior managers remain under the prior plan. In order to pay for this insurance for these executives, during 1992 insurance was purchased on the lives of each of them. Effective January 1, 1993, APS started to provide funds to pay for the future benefits due under the supplemental retirement plan (Secured Benefit Plan) as described in note (a) on p. 53. To do this, APS purchased, during 1993, life insurance on the lives of the covered executives. The premium costs of both the 1992 and 1993 policies plus a factor for the use of the money are returned to APS at the earlier of (a) death of the insured or (b) the later of age 65 or 10 years from the date of the policy's inception. The figures in this column include the present value of the executives' cash value at retirement attributable to the current year's premium payment (based upon the premium, future valued to retirement, using the policy internal rate of return minus the corporation's premium payment), as well as the premium paid for the basic group life insurance program plan and the contribution for the 401(k) plan. For 1994, the figure shown includes amounts representing (a) the aggregate of life insurance premiums and dollar value of the benefit to the executive officer of the remainder of the premium paid on the Group Life Insurance program and the Executive Life Insurance and Secured Benefit Plans and (b) 401(k) contributions as follows: Mr. Bergman $86,958 and $4,500; Mr. Noia $43,367 and $4,500; Mr. Garnett $66,253 and $3,960; and Mr. Skrgic $52,753 and $4,500; Ms. Gormley $17,978 and $4,500, respectively. (e) In 1994, the Boards of Directors of APS, APSC and the Operating Subsidiaries implemented a Performance Share Plan (the "Plan") for senior officers which was approved by the shareholders of APS at the annual meeting in May 1994. The first Plan cycle began on January 1, 1994 and will end on December 31, 1996. After completion of that cycle, performance share awards or cash may be granted if a participant has met his or her performance criteria. Since the Plan cycle will not be complete until 1997, no awards have been granted and the amount which any named executive officer will receive has not yet been determined. (f) See Executive Officers of the Registrants for other positions held. (g) Mr. Noia's compensation was paid by Potomac Edison through August 31, 1994, after which time it was paid by APSC. (h) Although less than 10% of total annual salary and bonus, Mr. Skrgic received a $15,000 housing allowance in 1993 and 1992. </TABLE>

<TABLE> <CAPTION> Summary Compensation Tables MONONGAHELA Annual Compensation Name All Other and Compen- Principal sation Position Year Salary($) Bonus($)(a) ($)(b)(c) <S> <C> <C> <C> <C> Klaus Bergman, 1994 Chief Executive 1993 Officer (d) 1992 Benjamin H. Hayes, 1994 197,500 58,000 92,880(f) President (e) 1993 189,996 35,000 19,668 1992 180,000 30,000 11,114 Thomas A. Barlow 1994 124,750 19,500 16,687 Vice President 1993 119,496 18,000 12,777 1992 113,247 16,000 7,145 Robert R. Winter 1994 126,000 20,000 35,404 Vice President 1993 119,502 18,000 19,529 1992 112,002 17,000 6,332 Richard E. Myers 1994 116,166 14,000 18,734 Comptroller 1993 110,121 11,000 17,246 1992 104,581 10,000 7,486 (a) Incentive awards are based upon performance in the year in which the figure appears but are paid in the second quarter of the following year. The incentive award plan will be continued for 1995. (b) Effective January 1, 1992, the basic group life insurance provided employees was reduced from two times salary during employment, which reduced to one times salary after 5 years in retirement, to a new plan which provides one times salary until retirement and $25,000 thereafter. Executive officers and other senior managers remain under the prior plan. In order to pay for this insurance for these executives, during 1992 insurance was purchased on the lives of each of them. Effective January 1, 1993, APS started to provide funds to pay for the future benefits due under the supplemental retirement plan (Secured Benefit Plan) as described in note (a) on p. 53. To do this, APS purchased, during 1993, life insurance on the lives of the covered executives. The premium costs of both the 1992 and 1993 policies plus a factor for the use of the money are returned to APS at the earlier of (a) death of the insured or (b) the later of age 65 or 10 years from the date of the policy's inception. The figures in this column include the present value of the executives' cash value at retirement attributable to the current year's premium payment (based upon the premium, future valued to retirement, using the policy internal rate of return minus the corporation's premium payment), as well as the premium paid for the basic group life insurance program plan and the contribution for the 401(k) plan. For 1994, the figure shown includes amounts representing (a) the aggregate of life insurance premiums on the Group Life Insurance program and the Executive Life Insurance and Secured Benefit Plans and (b) 401(k) contributions as follows: Mr. Hayes $47,798 and $4,500; Mr. Barlow $12,947 and $3,740; Mr. Winter $31,627 and $3,777; and Mr. Myers $15,251 and $3,483, respectively. (c) In 1994, the Boards of Directors of APS, APSC and the Operating Subsidiaries implemented a Performance Share Plan (the "Plan") for senior officers which was approved by the shareholders of APS at the annual meeting in May 1994. The first Plan cycle began on January 1, 1994 and will end on December 31, 1996. After completion of that cycle, performance share awards or cash may be granted if a participant has met his or her performance criteria. Since the Plan cycle will not be complete until 1997, no awards have been granted and the amount which any named executive officer will receive has not yet been determined. (d) The total compensation Mr. Bergman received for services in all capacities to APS, APSC and the Subsidiaries is set forth in the Summary Compensation Table for APS. (e) Mr. Hayes retired effective January 1, 1995. (f) Included in this amount is $40,500 representing accrued vacation for which he was paid. </TABLE>

<TABLE> <CAPTION> Summary Compensation Tables POTOMAC EDISON Annual Compensation Name All Other and Compen- Principal sation Position Year Salary($) Bonus($)(a) ($)(b)(c) <S> <C> <C> <C> <C> Klaus Bergman, 1994 Chief Executive 1993 Officer (d) 1992 Alan J. Noia, 1994 President (d)(e) 1993 1992 Robert B. Murdock 1994 139,500 21,500 36,983(g) Vice President(f) 1993 135,000 21,000 12,936 1992 128,914 19,000 8,853 James D. Latimer 1994 136,871 22,500 15,171 Executive Vice President 1993 119,996 17,000 12,971 1992 111,666 15,000 7,625 Thomas J. Kloc 1994 117,000 14,500 13,736 Comptroller 1993 112,500 11,000 11,204 1992 107,004 10,000 5,366 (a) Incentive awards are based upon performance in the year in which the figure appears but are paid in the second quarter of the following year. The incentive award plan will be continued for 1995. (b) Effective January 1, 1992, the basic group life insurance provided employees was reduced from two times salary during employment, which reduced to one times salary after 5 years in retirement, to a new plan which provides one times salary until retirement and $25,000 thereafter. Executive officers and other senior managers remain under the prior plan. In order to pay for this insurance for these executives, during 1992 insurance was purchased on the lives of each of them. Effective January 1, 1993, APS started to provide funds to pay for the future benefits due under the supplemental retirement plan (Secured Benefit Plan) as described in note (a) on p. 53. To do this, APS purchased, during 1993, life insurance on the lives of the covered executives. The premium costs of both the 1992 and 1993 policies plus a factor for the use of the money are returned to APS at the earlier of (a) death of the insured or (b) the later of age 65 or 10 years from the date of the policy's inception. The figures in this column include the present value of the executives' cash value at retirement attributable to the current year's premium payment (based upon the premium, future valued to retirement, using the policy internal rate of return minus the corporation's premium payment), as well as the premium paid for the basic group life insurance program plan and the contribution for the 401(k) plan. For 1994 the figure shown includes amounts representing (a) the aggregate of life insurance premiums on the Group Life Insurance program and the Executive Life Insurance and Secured Benefit Plans and (b) 401(k) contributions as follows: Mr. Murdock $11,172 and $4,081; Mr. Latimer $11,205 and $3,966; and Mr. Kloc $10,226 and $3,510, respectively. (c) In 1994, the Boards of Directors of APS, APSC and the Operating Subsidiaries implemented a Performance Share Plan (the "Plan") for senior officers which was approved by the shareholders of APS at the annual meeting in May 1994. The first Plan cycle began on January 1, 1994 and will end on December 31, 1996. After completion of that cycle, performance share awards or cash may be granted if a participant has met his or her performance criteria. Since the Plan cycle will not be complete until 1997, no awards have been granted and the amount which any named executive officer will receive has not yet been determined. (d) The total compensation Messrs. Bergman and Noia received for services in all capacities to APS, APSC and the Subsidiaries is set forth in the Summary Compensation Table for APS. (e) Mr. Noia's compensation was paid by Potomac Edison through August 31, 1994, after which time it was paid by APSC. See note (d) above. (f) Mr. Murdock retired effective January 1, 1995. (g) Included in this amount is $21,730 representing accrued vacation for which he was paid. </TABLE>

<TABLE> <CAPTION> Summary Compensation Tables WEST PENN Annual Compensation Name All Other and Compen- Principal sation Position Year Salary($) Bonus($)(a) ($)(b)(c) <S> <C> <C> <C> <C> Klaus Bergman, 1994 Chief Executive 1993 Officer (d) 1992 Jay S. Pifer, 1994 189,996 39,000 50,630 President 1993 175,500 25,000 18,093 1992 156,495 28,000 9,870 Thomas K. Henderson, 1994 129,164 20,000 29,223 Vice President 1993 124,004 19,000 17,570 1992 117,838 17,000 6,887 Charles S. Ault, 1994 122,000 18,500 20,249 Vice President 1993 114,419 16,000 12,673 1992 107,129 15,000 6,764 Charles V. Burkley, 1994 118,083 14,500 15,691 Comptroller 1993 112,996 11,000 10,544 1992 106,913 10,000 6,748 (a) Incentive awards are based upon performance in the year in which the figure appears but are paid in the second quarter of the following year. The incentive award plan will be continued for 1995. (b) Effective January 1, 1992, the basic group life insurance provided employees was reduced from two times salary during employment, which reduced to one times salary after 5 years in retirement, to a new plan which provides one times salary until retirement and $25,000 thereafter. Executive officers and other senior managers remain under the prior plan. In order to pay for this insurance for these executives, during 1992 insurance was purchased on the lives of each of them. Effective January 1, 1993, APS started to provide funds to pay for the future benefits due under the supplemental retirement plan (Secured Benefit Plan) as described in note (a) on p. 53. To do this, APS purchased, during 1993, life insurance on the lives of the covered executives. The premium costs of both the 1992 and 1993 policies plus a factor for the use of the money are returned to APS at the earlier of (a) death of the insured or (b) the later of age 65 or 10 years from the date of the policy's inception. The figures in this column include the present value of the executives' cash value at retirement attributable to the current year's premium payment (based upon the premium, future valued to retirement, using the policy internal rate of return minus the corporation's premium payment), as well as the premium paid for the basic group life insurance program plan and the contribution for the 401(k) plan. For 1994 the figure shown includes amounts representing (a) the aggregate of life insurance premiums on the Group Life Insurance program and the Executive Life Insurance and Secured Benefit Plans and (b) 401(k) contributions as follows: Mr. Pifer $46,130 and $4,500; Mr. Henderson $25,348 and $3,875; Mr. Ault $16,589 and $3,660; and Mr. Burkley $12,149 and $3,542, respectively. (c) In 1994, the Boards of Directors of APS, APSC and the Operating Subsidiaries implemented a Performance Share Plan (the "Plan") for senior officers which was approved by the shareholders of APS at the annual meeting in May 1994. The first Plan cycle began on January 1, 1994 and will end on December 31, 1996. After completion of that cycle, performance share awards or cash may be granted if a participant has met his or her performance criteria. Since the Plan cycle will not be complete until 1997, no awards have been granted and the amount which any named executive officer will receive has not yet been determined. (d) The total compensation Mr. Bergman received for services in all capacities to APS, APSC and the Subsidiaries is set forth in the Summary Compensation Table for APS. </TABLE>

<TABLE> <CAPTION> Summary Compensation Tables AGC Annual Compensation (a) Name All Other and Compen- Principal sation Position Year Salary($) Bonus($) ($) <S> <C> (a) AGC has no paid employees. </TABLE>

<TABLE> <CAPTION> DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE Estimated Name and Capacities Annual Benefits Company in Which Served on Retirement (a) APS (b) <S> <C> Klaus Bergman, $242,000 Chairman of the Board and Chief Executive Officer (c) Alan J. Noia, President 183,000 and Chief Operating Officer * (c) Stanley I. Garnett, II, 125,000 Senior Vice President, Finance (c) Peter J. Skrgic, 143,000 Senior Vice President (c) Nancy H. Gormley, 95,900 Vice President (c)(d) Monongahela Klaus Bergman, $ Chief Executive Officer (c)(e) Benjamin H. Hayes, 102,500 President (f) Thomas A. Barlow, 72,700 Vice President (d) Robert R. Winter, 74,000 Vice President (c) Richard E. Myers, 70,000 Comptroller * Elected President and Chief Operating Officer effective September 1, 1994. </TABLE>

<TABLE> <CAPTION> Estimated Name and Capacities Annual Benefits Company in Which Served on Retirement (a) Potomac Edison <S> <C> Klaus Bergman, $ Chief Executive Officer (c)(e) Alan J. Noia, President (c)(e) Robert B. Murdock, 70,500 Vice President (f) James D. Latimer, 90,500 Executive Vice President Thomas J. Kloc, 72,000 Comptroller West Penn Klaus Bergman, $ Chief Executive Officer (c)(e) Jay S. Pifer, 76,500 President (c) Thomas K. Henderson, 68,000 Vice President (c) Charles S. Ault, 77,000 Vice President Charles V. Burkley, 71,800 Comptroller (d) Allegheny Generating Company No paid employees. (a) Assumes present insured benefit plan and salary continue and retirement at age 65 with single life annuity. Under plan provisions, the annual rate of benefits payable at the normal retirement age of 65 are computed by adding (i) 1% of final average pay up to covered compensation times years of service up to 35 years, plus (ii) 1.5% of final average pay in excess of covered compensation times years of service up to 35 years, plus (iii) 1.3% of final average pay times years of service in excess of 35 years. Covered compensation is the average of the maximum taxable Social Security wage bases during the 35 years preceding the member's retirement, except that years before 1959 are not taken into account for purposes of this average. The final average pay benefit is based on the member's average total earnings during the highest-paid 60 consecutive calendar months or, if smaller, the member's highest rate of pay as of any July 1st. Effective July 1, 1994 the maximum amount of any employee's compensation that may be used in these computations was decreased to $150,000. Benefits for employees retiring between 55 and 62 differ from the foregoing. Pursuant to a supplemental plan (Secured Benefit Plan), senior executives of Allegheny Power System companies who retire at age 60 or over with 40 or more years of service are entitled to a supplemental retirement benefit in an amount that, together with the benefits under the basic plan and from other employment, will equal 60% of the executive's highest average monthly earnings for any 36 consecutive months. The supplemental benefit is reduced for less than 40 years service and for retirement age from 60 to 55. It is included in the amounts shown where applicable. In order to provide funds to pay such benefits, effective January 1, 1993 the Company purchased insurance on the lives of the plan participants. The Secured Benefit Plan has been designed that if the assumptions made as to mortality experience, policy dividends, and other factors are realized, the Company will recover all premium payments, plus a factor for the use of the Company's money. The amount of the premiums for this insurance required to be deemed "compensation" by the Securities and Exchange Commission is described and included in the "All Other Compensation" column on pages 46-49. All executive officers are participants in the Secured Benefit Plan. This does not include benefits from an Employee Stock Ownership and Savings Plan (ESOSP) established as a non-contributory stock ownership plan for all eligible employees effective January 1, 1976, and amended in 1984 to include a savings program. Under the ESOSP for 1994, all eligible employees may elect to have from 2% to 7% of their compensation contributed to the Plan as pre-tax contributions and an additional 1% to 6% as post-tax contributions. Employees direct the investment of these contributions into one or more available funds. Each System company matches 50% of the pre-tax contributions up to 6% of compensation with common stock of Allegheny Power System, Inc. Effective January 1, 1994 the maximum amount of any employee's compensation that may be used in these computations was decreased to $150,000. Employees' interests in the ESOSP vest immediately. Their pre-tax contributions may be withdrawn only upon meeting certain financial hardship requirements or upon termination of employment. (b) APS has no paid employees. These executives are employees of APSC. (c) See Executive Officers of the Registrants for other positions held. (d) Mrs. Gormley, Mr. Barlow and Mr. Burkley have elected to retire in 1995. The actual pension amounts which they will receive are set forth in the table. (e) The total estimated annual benefits on retirement payable to Messrs. Bergman and Noia for services in all capacities to APS, APSC and the Subsidiaries is set forth in the table for APS. (f) Mr. Hayes and Mr. Murdock retired effective January 1, 1995. The actual pension amounts which they are receiving are set forth in the table. </TABLE>

Employment Contracts In February 1995, APS entered into employment contracts with certain of the APS System executive officers (Agreements). Each Agreement sets forth (i) the severance benefits that will be provided to the employee in the event the employee is terminated subsequent to a Change in Control of APS (as defined in the Agreements), and (ii) the employee's obligation to continue his or her employment after the occurrence of certain circumstances that could lead to a Change in Control. The Agreements provide generally that unless employment is terminated by APS for Cause, Disability or Retirement or by the employee for Good Reason (each as defined in the Agreements), severance benefits will consist of a cash payment equal to 2.99 times the employee's annualized compensation together with APS maintaining existing benefits for the employee and the employee's dependents for a period of three years. Each Agreement initially expires on December 31, 1997 but will be automatically extended for one year periods thereafter unless either APS or the employee gives notice otherwise. Notwithstanding the delivery of such notice, the Agreements will continue in effect for twenty-four months after a Change in Control.

Compensation of Directors In 1994, APS directors who were not officers or employees of System companies received for all services to System companies (a) $16,000 in retainer fees, (b) $800 for each committee meeting attended, except Executive Committee meetings which are $200, and (c) $250 for each Board meeting of each company attended. Under an unfunded deferred compensation plan, a director may elect to defer receipt of all or part of his or her director's fees for succeeding calendar years to be payable with accumulated interest when the director ceases to be such, in equal annual installments, or, upon authorization by the Board of Directors, in a lump sum. Effective January 1, 1995, in addition to the fees mentioned above, the Chairperson of each of the Audit, Finance, Management Review, and New Business Committees will receive a further fee of $4,000 per year, and the retainer fee paid outside directors will be increased by 200 shares of APS common stock pursuant to the Restricted Stock Plan for Outside Directors which was adopted, subject to SEC approval, effective January 1, 1995. Also adopted effective January 1, 1995 was a Directors' Retirement Plan which will provide an annual pension equal to the retainer fee paid to the outside director at the time of his or her retirement, provided the director has at least five (5) years of service and, except under special circumstances described in the Plan, serves until age 65.

<TABLE> <CAPTION> ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The table below shows the number of shares of APS common stock that are beneficially owned, directly or indirectly, by each director and named executive officer of APS, Monongahela, Potomac Edison, West Penn, and AGC and by all directors and executive officers of each such company as a group as of January 13, 1995. To the best of the knowledge of APS, there is no person who is a beneficial owner of more than 5% of the voting securities of APS. Executive Shares of Officer or APS Percent Name Director of Common Stock of Class <S> <C> <C> <C> Charles S. Ault WP 4,562 Less than .01% Thomas A. Barlow MP 7,205 " Eleanor Baum APS,MP,PE,WP 2,000 " William L. Bennett APS,MP,PE,WP 2,453 " Klaus Bergman APS,MP,PE,WP,AGC 10,463 " Charles V. Burkley WP 2,469 " Stanley I. Garnett, II APS,MP,PE,WP,AGC 4,390 " Nancy H. Gormley APS, MP 5,604 " Benjamin H. Hayes MP 5,697 " Thomas K. Henderson MP,PE,WP 4,095 " Wendell F. Holland APS,MP,PE,WP 140 " Kenneth M. Jones APS,AGC 4,520 " Thomas J. Kloc PE,AGC 3,210 " James D. Latimer PE 5,324 " Phillip E. Lint APS,MP,PE,WP 600 " Edward H. Malone APS,MP,PE,WP 1,468 " Frank A. Metz, Jr. APS,MP,PE,WP 1,936 " Robert B. Murdock PE 6,530 " Richard E. Myers MP 4,367 " Alan J. Noia APS,MP,PE,WP,AGC 11,202 " Jay S. Pifer MP,PE,WP 7,856 " Steven H. Rice APS,MP,PE,WP 2,148 " Gunnar E. Sarsten APS,MP,PE,WP 5,000 " Peter L. Shea APS,MP,PE,WP 1,400 " Peter J. Skrgic APS,MP,PE,WP,AGC 5,633 " Robert R. Winter MP,PE 3,410 " All directors and executive officers of APS as a group (18 persons) 68,522 Less than .075% All directors and executive officers of MP as a group (22 persons) 92,644 All directors and executive officers of PE as a group (21 persons) 88,664 All directors and executive officers of WP as a group (18 persons) 70,175 All directors and executive officers of AGC as a group (8 persons) 44,994 All of the shares of common stock of Monongahela (5,891,000), Potomac Edison (22,385,000), and West Penn (24,361,586) are owned by APS. All of the common stock of AGC is owned by Monongahela (270 shares), Potomac Edison (280 shares), and West Penn (450 shares). </TABLE>

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS For APS and the Subsidiaries, none. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1)(2) The financial statements and financial statement schedules filed as part of this Report are set forth under ITEM 8. and reference is made to the index on page 43. (b) No reports on Form 8-K were filed by System companies during the quarter ended December 31, 1994. (c) Exhibits for APS, Monongahela, Potomac Edison, West Penn, and AGC are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. ALLEGHENY POWER SYSTEM, INC. By: KLAUS BERGMAN (Klaus Bergman Chief Executive Officer) Date: February 2, 1995 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title Date (i) Principal Executive Officer: Chairman of the Board, 2/2/95 KLAUS BERGMAN Chief Executive Officer (Klaus Bergman) and Director (ii) Principal Financial Officer: STANLEY I. GARNETT, II Senior Vice President, 2/2/95 (Stanley I. Garnett, II) Finance (iii) Principal Accounting Officer: KENNETH M. JONES Vice President 2/2/95 (Kenneth M. Jones) and Comptroller (iv) A Majority of the Directors: *Eleanor Baum *Frank A. Metz, Jr. *William L. Bennett *Steven H. Rice *Klaus Bergman *Alan J. Noia *Wendell F. Holland *Gunnar E. Sarsten *Phillip E. Lint *Peter L. Shea *Edward H. Malone *By: NANCY H. GORMLEY 2/2/95 (Nancy H. Gormley)

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. MONONGAHELA POWER COMPANY By: JAY S. PIFER (Jay S. Pifer, President) Date: February 2, 1995 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Signature Title Date (i) Principal Executive Officer: Chairman of the Board, 2/2/95 KLAUS BERGMAN Chief Executive (Klaus Bergman) Officer, and Director (ii) Principal Financial Officer: NANCY L. CAMPBELL Treasurer 2/2/95 (Nancy L. Campbell) (iii) Principal Accounting Officer: RICHARD E. MYERS Comptroller 2/2/95 (Richard E. Myers) (iv) A Majority of the Directors: *Eleanor Baum *Frank A. Metz, Jr. *William L. Bennett *Alan J. Noia *Klaus Bergman *Jay S. Pifer *Stanley I. Garnett, II *Steven H. Rice *Wendell F. Holland *Gunnar E. Sarsten *Phillip E. Lint *Peter L. Shea *Edward H. Malone *Peter J. Skrgic *By: NANCY H. GORMLEY 2/2/95 (Nancy H. Gormley)

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. THE POTOMAC EDISON COMPANY By: JAY S. PIFER (Jay S. Pifer, President) Date: February 2, 1995 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Signature Title Date (i) Principal Executive Officer: Chairman of the Board, 2/2/95 KLAUS BERGMAN Chief Executive (Klaus Bergman) Officer, and Director (ii) Principal Financial Officer: DALE F. ZIMMERMAN Secretary and 2/2/95 (Dale F. Zimmerman) Treasurer (iii) Principal Accounting Officer: THOMAS J. KLOC Comptroller 2/2/95 (Thomas J. Kloc) (iv) A Majority of the Directors: *Eleanor Baum *Frank A. Metz, Jr. *William L. Bennett *Alan J. Noia *Klaus Bergman *Jay S. Pifer *Stanley I. Garnett, II *Steven H. Rice *Wendell F. Holland *Gunnar E. Sarsten *Phillip E. Lint *Peter L. Shea *Edward H. Malone *Peter J. Skrgic *By: NANCY H. GORMLEY 2/2/95 (Nancy H. Gormley)

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. WEST PENN POWER COMPANY By: JAY S. PIFER (Jay S. Pifer, President) Date: February 2, 1995 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. Signature Title Date (i) Principal Executive Officer: Chairman of the Board, 2/2/95 KLAUS BERGMAN Chief Executive (Klaus Bergman) Officer, and Director (ii) Principal Financial Officer: KENNETH D. MOWL Secretary and 2/2/95 (Kenneth D. Mowl) Treasurer (iii) Principal Accounting Officer: CHARLES V. BURKLEY Comptroller 2/2/95 (Charles V. Burkley) (iv) A Majority of the Directors: *Eleanor Baum *Frank A. Metz, Jr. *William L. Bennett *Alan J. Noia *Klaus Bergman *Jay S. Pifer *Stanley I. Garnett, II *Steven H. Rice *Wendell F. Holland *Gunnar E. Sarsten *Phillip E. Lint *Peter L. Shea *Edward H. Malone *Peter J. Skrgic *By: NANCY H. GORMLEY 2/2/95 (Nancy H. Gormley)

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. ALLEGHENY GENERATING COMPANY By: KLAUS BERGMAN (Klaus Bergman, President and Chief Executive Officer) Date: February 2, 1995 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Signature Title Date (i) Principal Executive Officer: KLAUS BERGMAN President, 2/2/95 (Klaus Bergman) Chief Executive Officer, and Director (ii) Principal Financial Officer: NANCY L. CAMPBELL Treasurer and 2/2/95 (Nancy L. Campbell) Assistant Secretary (iii) Principal Accounting Officer: THOMAS J. KLOC Comptroller 2/2/95 (Thomas J. Kloc) (iv) A Majority of the Directors: *Klaus Bergman *Stanley I. Garnett, II *Kenneth M. Jones *Alan J. Noia *Peter J. Skrgic *By: NANCY H. GORMLEY 2/2/95 (Nancy H. Gormley)

CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Prospectus constituting part of Allegheny Power System, Inc.'s Registration Statement on Form S-3 (Nos. 33-36716 and 33-57027) relating to the Dividend Reinvestment and Stock Purchase Plan of Allegheny Power System, Inc.; in the Prospectus constituting part of Allegheny Power System, Inc.'s Registration Statement on Form S-3 (No. 33-49791) relating to the common stock shelf registration; in the Prospectus constituting part of Monongahela Power Company's Registration Statement on Form S-3 (No. 33-51301); in the Prospectus constituting part of The Potomac Edison Company's Registration Statement on Form S-3 (No. 33-51305); and in the Prospectus constituting part of West Penn Power Company's Registration Statement on Form S-3 (Nos. 33-51303 and 33-56997); of our reports dated February 2, 1995 included in ITEM 8 of this Form 10-K. We also consent to the references to us under the heading "Experts" in such Prospectuses. PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP New York, New York March 15, 1995

POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Power System, Inc., a Maryland corporation, Monongahela Power Company, an Ohio corporation, The Potomac Edison Company, a Maryland and Virginia corporation, and West Penn Power Company, a Pennsylvania corporation, do hereby constitute and appoint NANCY H. GORMLEY and STANLEY I. GARNETT, II and each of them a true and lawful attorney in his or her name, place and stead, in any and all capacities, to sign his or her name to Annual Reports on Form 10-K for the year ended December 31, 1994 under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Companies, and to cause the same to be filed with the Securities and Exchange Commission, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratifies and confirms all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof. Dated: February 2, 1995 ELEANOR BAUM FRANK A. METZ, JR. (Eleanor Baum) (Frank A. Metz, Jr.) WILLIAM L. BENNETT ALAN J. NOIA (William L. Bennett) (Alan J. Noia) KLAUS BERGMAN STEVEN H. RICE (Klaus Bergman) (Steven H. Rice) WENDELL F. HOLLAND GUNNAR E. SARSTEN (Wendell F. Holland) (Gunnar E. Sarsten) PHILLIP E. LINT PETER L. SHEA (Phillip E. Lint) (Peter L. Shea) EDWARD H. MALONE (Edward H. Malone)

POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Monongahela Power Company, an Ohio corporation, The Potomac Edison Company, a Maryland and Virginia corporation, and West Penn Power Company, a Pennsylvania corporation, do hereby constitute and appoint NANCY H. GORMLEY and STANLEY I. GARNETT, II and each of them a true and lawful attorney in his or her name, place and stead, in any and all capacities, to sign his or her name to the Annual Report on Form 10-K for the year ended December 31, 1994 under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Company, and to cause the same to be filed with the Securities and Exchange Commission, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof. Dated: February 2, 1995 JAY S. PIFER (Jay S. Pifer) PETER J. SKRGIC (Peter J. Skrgic)

POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Generating Company, a Virginia corporation, do hereby constitute and appoint NANCY H. GORMLEY and STANLEY I. GARNETT, II and each of them a true and lawful attorney in his or her name, place and stead, in any and all capacities, to sign his or her name to the Annual Report on Form 10-K for the year ended December 31, 1994 under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Company, and to cause the same to be filed with the Securities and Exchange Commission, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof. Dated: February 2, 1995 KLAUS BERGMAN (Klaus Bergman) KENNETH M. JONES (Kenneth M. Jones) ALAN J. NOIA (Alan J. Noia) PETER J. SKRGIC (Peter J. Skrgic)

<TABLE> <CAPTION> E-1 EXHIBIT INDEX (Rule 601(a)) Allegheny Power System, Inc. Incorporation Documents by Reference <S> <C> <C> 3.1 Charter of the Company, Form 10-Q of the Company as amended (1-267), September 1993, exh. (a)(3) 3.2 By-laws of the Company, Form 10-Q of the Company as amended (1-267), June 1990, exh. (a)(3) 4 Subsidiaries' Indentures described below. 10.1 Directors' Deferred Compensation Plan 10.2 Executive Compensation Plan 10.3 Allegheny Power System Incentive Compensation Plan 10.4 Allegheny Power System Supplemental Executive Retirement Plan 10.5 Executive Life Insurance Program and Collateral Assignment Agreement 10.6 Secured Benefit Plan and Collateral Assignment Agreement 10.7 Restricted Stock Plan for Outside Directors 10.8 Retirement Plan for Outside Directors 10.9 Allegheny Power System Performance Share Plan 10.10 Form of Change In Control Form 8-K of the Company (1-267), Employment Contract dated February 15, 1995, exh. 10.1 11 Statement re computation of per share earnings: Clearly determinable from the financial statements contained in Item 8. 18 Letter re: Change in Accounting Principles </TABLE>

<TABLE> <CAPTION> E-1 (Cont'd) EXHIBIT INDEX (Rule 601(a)) Allegheny Power System, Inc. Incorporation Documents by Reference <S> <C> <C> 21 Subsidiaries of APS: Name of Company State of Organization Allegheny Generating Company (a) Virginia Allegheny Power Service Corporation Maryland Monongahela Power Company Ohio The Potomac Edison Company Maryland and Virginia West Penn Power Company Pennsylvania (a) Owned directly by Monongahela, Potomac Edison, and West Penn. 23 Consent of Independent Accountants See page 62 herein. 24 Powers of Attorney See pages 63-65 herein. 27 Financial Data Schedules </TABLE>

Exhibit 10.1 ALLEGHENY POWER SYSTEM Revised Plan for Deferral of Compensation of Directors 1. Any director may elect in a writing delivered to the Secretary of the Company on or before December 31st of any year to defer receipt of all or a specified part of his retainer and attendance fees for services as a director, including without limitation annual retainers and board and committee attendance fees, for the succeeding calendar year and for all succeeding calendar years. 2. An election to defer for a single succeeding calendar year shall be irrevocable. Any election effective for all succeeding years shall remain in effect unless terminated by a communication in writing from the director; such termination shall become effective with respect to all amounts payable in the calendar year commencing after receipt of such communication and shall not affect the treatment of amounts deferred prior to the start of such calendar year. 3. Any person elected to fill a vacancy on the Board of Directors and who was not a director on the preceding December 31st, may make such written election before taking office in which event the election will be effective from the start of his service as director. 4. In his written deferred election, the director may select from the following alternatives for payment of the deferred amounts: (a) Lump sum payment on January 2 of the year following termination of service as director.

(b) Payment in annual installments commencing on such January 2. (Minimum 3 installments) (c) Payment in annual installments equal in number to the number of years of service. Such payment method selection shall be irrevocable unless an alternative selection is made in writing more than 24 months prior to termination of service as a director. If termination of service occurs prior to the passage of 24 months after such action, the alternative selection shall not take effect. Each annual installment payment shall be such portion of the amount credited to his deferred account at the prior December 31 as will be in accordance with his payout selection. 5. The Company shall maintain a separate memorandum account of the amounts deferred by each director and shall credit such account at the end of each quarter with interest at a rate equivalent to the yield on the Company's common stock for the 12 months ended on the last day of that quarter. 6. In the event of a director's death prior to his or her receipt of all of the deferred amounts and interest thereon, such funds shall be paid to a beneficiary designated by him or, if no such designation shall have been made, to his estate in full on the first day of the calendar year following the year in which the director dies. A beneficiary shall be designated in the written election to defer and may be changed from time to time by filing written notice of such change with the Secretary of the Company. 7. The Secretary of the Company shall provide to each director a copy of this Revised Plan together with a form of agreement whereby a director may elect to defer all or any part of his fees, in accordance herewith.

8. All deferral agreements in effect under the Plan prior to adoption of this Revised Plan shall remain in effect, provided, however, that, within 30 days after adoption of this Revised Plan, a director whose termination of service will occur more than 36 months after such adoption may select in writing for previously deferred amounts and future compensation a payment option set forth above in lieu of the option then in effect. 9. It is the intention of the parties that the above arrangements be unfunded for tax purposes and for purposes of Title I of ERISA to the extent that such Title shall be applicable hereto. The director shall have the status of a general creditor of the Company with respect to the amount in his account. The director's rights to payments under the plan are not subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, attachment or garnishment by creditors of the director or the director's benefi- ciaries. 10. The provisions of this Revised Plan may be amended by the Board of Directors at any time provided that no such amendment may be made that would deprive a director of any rights with respect to amounts accrued hereunder as of the date of such amendment without his written consent. March 2, 1995

Election to Defer Receipt of Directors Fees Under the Directors Elective Deferred Fees Plan of Allegheny Power System Pursuant to Section 4 of the captioned Plan, I hereby elect to defer receipt of ________% of all retainer and attendance fees payable to me on and after January 1, 19__. I elect to have my deferred account, with accumulated interest, paid as follows, commencing with the 2nd day of January following the termination of my service as a member of the Board of Directors of Allegheny: In a single lump sum, to be paid within 60 days after such January 2. In annual installment payments of equal amounts (adjusted for interest credits) over _______ years (at least 3) with such installment payments to be made on January 2 of each year. In annual installments of equal amounts (adjusted for interest credits) on January 2 of each year, such annual payments to be equal in number to the number of years of service. In the event of my death prior to receipt of all amounts I have deferred under this Plan, including interest credits, the balance of such deferred funds shall be paid in a lump sum to the following designees who survive me or to my estate in proportion to the percentage shares indicated, and, if I have indicated no designees or if all indicated designees predecease me, entirely to my estate. Designee Address Percentage Share Dated: Signature

Exhibit 10.2 CONFIDENTIAL EXECUTIVE COMPENSATION PLAN OBJECTIVES To attract, hold, and motivate executive personnel. Prior approval of the chief executive officer is required for inclusion in the Plan. QUALIFICATIONS An employee becomes eligible for inclusion when 1. the employee has held a position with a salary grade of 28 or above for at least one year, is assuming the full responsibility of the position, is achieving satisfactory results and has a salary which exceeds the mid point between the minimum and standard amounts of salary grade 28, or 2. the employee has held the position of operating division manager with a salary grade of 18 or above for at least one year, is assuming the full responsibility of the position, is achieving satis- factory results and has a salary which exceeds the mid point between the minimum and standard amounts of salary grade 28. COMPENSATION 1. Life insurance 2. Dependent medical insurance 3. Dependent dental insurance 4. Annual physical examination during employment 5. Five weeks vacation, unless length of service would warrant more.* Participants in the Plan are not entitled to pay for accrued vacation (or to vacation in lieu of such pay) in excess of what they would receive if they were not par- ticipants. *Language clarified.

Exhibit 10.2 (cont'd) 6. Sick pay allowance of one year at full pay and one year at half pay, regardless of length of service. PROCEDURE 1. The president of each of the operating companies, the Executive Director, Central Services and the APS, Inc. vice presidents shall submit to the chief executive officer the names of all eligible employees or reasons why an employee, otherwise eligible, should not be included, not less than 30 days prior to the employee's eligibility date. 2. The Vice President, Employee and Consumer Relations maintains an official list of employees included in the Executive Compensation Plan for all companies. January 1, 1987

Exhibit 10.3 ALLEGHENY POWER SYSTEM, INC. 1993 ANNUAL INCENTIVE PLAN I. PURPOSE OF THE INCENTIVE PLAN To attract and retain first quality managers in a com- petitive job market and to reward superior performance. II. ELIGIBILITY The annual incentive plan is designed to reward participating executives for achieving key goals for the System and for the units for which they are responsible. A prerequisite for participation in the plan shall be an understanding of and commitment to -- The System Management Plan and Policies -- The System's expectation that employees will observe the highest ethical standards in their conduct of System business and stewardship of its property. Eligibility will be determined by the Management Review Committee upon the recommendation of the CEO from among executives whose responsibilities can affect System performance. III. AWARDS Awards will reflect the importance of the participants to the System and the units for which they are responsible. Awards will be paid for the achievement of specific measurable goals set for the System, including goals set the individual and the units for which he or she is responsible. The plan's goals will be: -- Determined and communicated annually -- A reasonable number for each participant

The types of goals which the Board will set with the help of the Management Review Committee include: -- Financial performance (return on equity, earnings, dividends) -- Customer satisfaction (cost, quality, and reliability of service) -- Cost and environmental consciousness (productivity, efficiency, availability and utilization of equipment) and conservation of resources -- Safety -- Development of personnel for management positions, including women and minorities IV. OVERALL LIMITATIONS ON AWARDS The Board of Directors shall not authorize any incentivepayment if, in the Board's opinion, the System's financial performance is less than satisfactory from the perspective of its stockholders. V. PERFORMANCE MEASURES Each year measures to evaluate participants' performance will be determined. They may vary among participants according to whether their principal responsibilities are to: -- The System as a whole -- An Operating Company -- Bulk Power Supply or Central Services. Each category of performance measure will carry appropriate weightings as shown on 1993 Participant Performance Schedule. Examples of possible measures include: For System as a whole -- Quantity and quality of earnings: return on equity, measured against previous year, authorized return on equity and as appropriate peer companies; financial ratings; capital structure, dividend payout ratios and total return -- Productivity, cost control, efficient use of equipment, natural resources, and other environmental considerations -- Quality and reliability of customer service -- Safety

-- Attainment of reasonable rates and maintenance of competitive position For Operating Companies -- Balance for common stock: return on equity -- Safety -- Productivity and efficiency: revenues from regular customers, and administrative, operating, and maintenance expenditures - Per employee, customer, and kwh - Measured against previous year and peer companies -- Customer satisfaction (quality of service): outage rates, speedy restoration of service, customer complaints, employee courtesy, conservation and demand- side management programs -- Cost of service: rate per kwh measured against past period, economic indices, and peer companies -- Community relations and relations with state and local governments and their agencies -- Completion of construction projects on time and within budget -- Adequacy of management development programs For Bulk Power Supply and Central Services -- Adequacy of planning and accuracy of forecasts -- Completion of assignments and projects on time and within budget -- Availability, efficiency, and reliability of generating units and transmission systems -- Safety -- Cost consciousness (avoidance of excessive staffing and waste of work space and receptivity to cost saving techniques) -- Minimizing adverse effects in the environment -- User satisfaction -- Adherence to System Purchasing Policy and success in buying material, equipment, and supplies at the best possible price.

For Individual Performance -- Initiative -- Resourcefulness -- Responsiveness -- Identifiable results -- Other VI. CALCULATION OF AWARDS Target Incentive Awards and Total Estimated Cost -- No awards will be paid for any year unless the Board of Directors finds that the System's financial performance is satisfactory from the perspective of its stockholders -- 100% of a target incentive award will be paid to a participant only if System, Responsibility Unit, and Individual target performance measures are fully achieved Performance Schedules -- The Performance Schedule describes ratings and weightings for each performance measure at all levels of performance -- As soon as practicable each year, Participant Performance Schedules for that year will be issued Performance Ratings -- Target performance represents the full and complete attainment of expectations in the performance area; it is rated 1.0 -- Performance that is acceptable but does not fully meet expectations can earn a rating but, of course, less than 1.0 -- Exceeding expectations can result in a performance rating as high as 1.25 -- Unacceptable individual performance will result in no award regardless of System or Unit Performance. Weightings -- Weightings will be established each year for System, Unit and Individual performance measures.

Calculation of Award -- A participant's award, if any, will be determined by multiplying the participant's assigned incentive percentage times his/her rounded total performance rating times his/her salary at the close of the year prior to the year for which the award is to be made. The Management Review Committee or the Board of Directors,at its discretion, may supplement or decrease any partici-pant's calculated award to reflect extraordinary circumstances provided that it records its reason for doing so. VII. FORM AND TIMING OF PAYOUT Calculation of awards will be made as soon as practicable after the close of books for the year measured, but no award will be paid until it has been approved by the Management Review Committee or the Board of Directors, as appropriate. Payment will be in current cash unless the Management Review Committee or the Board at its discretion provides for deferral. VIII. TERMINATION AND TRANSFER PROVISIONS Termination Provisions -- Awards may at the discretion of the Management Review Committee or the Board be calculated on the basis of a full year's performance and prorated to the number of whole months actually served, except in the case of voluntary termination (other than retirement after the second quarter of the year) or termination by the company (with or without cause), in which case no award is made for year of termination. Designation of "Unit" in cases of transfer among Operating Companies, Central Services, Bulk Power Supply, and New York -- Weighting will be based on the number of months participant was in each unit. IX. PLAN ADMINISTRATION Administration of the plan is the responsibility of the Management Review Committee of the Board of Directors. -- The Committee is responsible for review and administration of all Systemwide goals and has final approval over these and other matters involving the plan, including eligibility.

Exhibit 10.4 ALLEGHENY POWER SYSTEM SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN (Effective July 1, 1990)

ALLEGHENY POWER SYSTEM SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN 1. Purpose of the Plan: The purpose of the Plan, the "Allegheny Power System Supplemental Executive Retirement Plan" (hereinafter referred to as the "Plan") is to provide for the payment of supplemental retirement benefits to or in respect of senior executives of Allegheny Power System companies (hereinafter sometimes referred to as a "Company" or the "Companies") as part of an integrated executive compensation program which is intended to assist the Companies in attracting, motivating and retaining executives of superior ability, industry, and loyalty. 2. Eligibility to Participate in the Plan: Each employee of a Company who was a participant in the Predecessor Plan or who on or after the Effective Date is assigned 1990 salary grade 28 or higher shall be a participant in the Plan. 3. Definitions: A. Average Compensation - shall mean 12 times the highest average monthly earnings (including overtime and other salary payments actually earned, whether or not payment thereof is deferred) for any 36 consecutive months. B. Committee - shall mean the Finance Committee of the Board of Directors of Allegheny Power System, Inc. C. Effective Date - shall mean July 1, 1990. D. Participant - shall mean an employee who meets the eligibility requirements of Section 2. Retired Participant shall mean a Participant who has retired from service after at least 10 years of service with one or more Companies and on or after his/her 55th birthday. E. Plan Year - shall mean the 12-month period on which the fiscal records of the Plan are kept, which is now the period from July 1st to June 30th. F. Predecessor Plan - shall mean the Allegheny Power System Supplemental Executive Retirement Plans effective July 1, 1982 and July 1, 1988.

G. Supplemental Retirement Benefit Reduction - shall mean the retirement benefit payable to the Participant under the Allegheny Power System Retirement Plan excluding any increases in this benefit which become effective after the Participant has retired. H. Years of Service - shall mean the Participant's Years of Service, and fractional parts thereof, as computed under the terms of the Allegheny Power System Retirement Plan. 4. Supplemental Retirement Benefits: A. Eligibility for Benefits - A Participant shall be eligible for a benefit from this Plan only (a) if he/she has at least 10 Years of Service with one or more of the Companies and (b) on or after his/her 55th birthday: provided that, if a Participant is discharged from employment for cause or terminates employment with the Companies prior to retirement under the Allegheny Power System Retirement Plan for any reason whatsoever, other than death, such eligibility will terminate and no benefit shall be payable to such Participant from this Plan. A Participant who dies in active employment on or after his/her 55th birthday shall be deemed to have retired one day before his/her death. B. Amount of Benefits - (1) Subject to paragraph (2) of this Subsection, an eligible Participant will be entitled to receive a supplemental retirement benefit under this Plan equal to his/her Average Compensation multiplied by the sum of: (a) 2% times his/her number of Years of Service up to 25 years, (b) 1% times his/her number of Years of Service from 25 to 30 years, and (c) 1/2% times his/her number of Years of Service from 30 to 40 years less (x) such Participant's Supplemental

Retirement Benefit Reduction and (y) 2% per year for each year that a Participant retires prior to his/her 60th birthday. (2) The supplemental retirement benefits contemplated by paragraph (1) of this Subsection shall be payable only to the extent such benefits, together with (i) all retirement benefits payable to the Participant by reason of employment with another employer (other than a benefit payable under the Federal Social Security Act) converted to the same form as the benefit paid under this Plan by using the actuarial equivalence factors of the Allegheny Power System Retirement Plan and (ii) the retirement benefit payable to the Participant under the Allegheny Power System Retirement Plan excluding any increases in this benefit which become effective after the Participant has retired do not exceed sixty percent (60%) of his/her Average Compensation, less 2% per year for each year the Participant retires prior to his/her 60th birthday.

C. Form and Time of Payment - A benefit payable under this Plan shall be paid in such form as the Participant shall elect from those available, and at the same time as the retirement benefit payable to the Retired Participant, under the Allegheny Power System Retirement Plan. If the Benefit payable under this Plan is paid other than as a life annuity, the amount of the benefit when paid in such other form shall be determined by using the actuarial equivalence factors of the Allegheny Power System Retirement Plan. 5. Vesting: A Participant shall have no vested interest in the Plan until he/she becomes eligible to receive benefits under Section 4A. In the event such eligible Participant is discharged from employment for cause or terminates employment, other than by death or retirement under the Allegheny Power System Retirement Plan, any such interest which may have vested shall be discontinued and forfeited. 6. Funding: The Plan shall be unfunded. Benefits of a Participant shall be paid from the general assets of the Company employing the Participant at the time of his/her retirement and a Participant shall have no interest in any such assets under the terms of this Plan until he/she becomes a Retired Participant. An eligible Participant shall be an unsecured creditor of the Company as to the payment of any benefit under this plan. 7. Administration and Governing Law: This Plan will be administered by and under the direction of the Committee. The Committee shall adopt, and may from time to time modify or amend, such rules and guidelines consistent herewith as it may deem necessary or appropriate for carrying out the provisions and purposes of the Plan, which, upon their adoption and so long as in effect, shall be deemed a part hereof to the same extent as if set forth in the Plan (hereinafter referred to as the "Rules and Guidelines"). Any interpretation and construction by the Committee of any provision of, and the determination of any question arising under, the Plan or the Rules and Guidelines shall be final, conclusive, and binding upon the Participant, his/her surviving spouse and all other persons. The provisions of the Plan shall be construed, administered, and enforced according to and governed by the laws of the United States and the State of New York. 8. Entire Agreement: This Plan shall not be deemed to constitute a contract between any Company and any employee or other person in the employ of any Company, nor shall

anything herein contained be deemed to give any employee or other person in the employ of any Company any right to be retained in the employ of any Company or to interfere with the right of any Company to discharge any employee or such other person at any time and to treat an employee without regard to the effect which such treatment might have upon such employee as a Participant in the Plan. 9. Non-Assignability: Neither a Participant, nor his beneficiary or any other person, shall have any right to commute, sell, assign, transfer, or otherwise convey the right to receive any payments hereunder; which payments and the right thereto are expressly declared to be nonassignable and nontransferable. In the event of any attempted assignment or transfer, the Companies shall have no further liability hereunder. Nor shall any payments be subject to attachment, garnishment, or execution, or be transferable by operation of law in the event of bankruptcy or insolvency, except to the extent otherwise provided by applicable law. 10. Termination or Amendment: This Plan may be terminated as to any Company at any time and amended from time to time by the Board of Directors of that Company; provided that neither termination nor amendment of the Plan may reduce or terminate any benefit to or in respect of a Participant eligible to receive benefits under Section 4A.

Exhibit 10.5 AGREEMENT EXECUTIVE LIFE INSURANCE PROGRAM AND COLLATERAL ASSIGNMENT THIS AGREEMENT is entered into this day of , 19 , by and between Allegheny Power System, Inc., (hereinafter called "the Employer" in Part I or "Assignee" in Part II), and (hereinafter called "the Employee"). WHEREAS the Employee is currently a valued employee and Executive of Employer; Whereas the Employer wishes to assist the Employee with his (or her) personal life insurance program and the Employee desires to accept such assistance; and WHEREAS in consideration of the Assignee agreeing to pay all of the premiums, the Owner agrees to grant the Assignee a security for the recovery of the Assignee's premium outlay. NOW, THEREFORE for value received, the Employer and the Employee agree as follows: PART I - Individual Life Insurance Agreement A. Description of Policy - Policy Ownership In furtherance of the purposes of the Agreement, The Employee will purchase and own a certain policy of life insurance on his own life, being Policy No. issued by Security Life of Denver Insurance Company. Said policy is hereinafter called "the Policy" and said life insurance company is hereinafter called "the Insurer". The Employee's ownership of the Policy shall be subject to all the terms and conditions set forth in this Agreement. B. Payment of Premiums The Employer shall pay the entire annual premium for the Policy directly to the Insurer. C. Collateral Assignment and Possession of Policy To secure repayment of premiums paid by the Employer provided for in Section B, above, Part II of this Agreement includes an assignment of the policy or the Employee's interest therein

(hereinafter called "Collateral Assignment") and provides for the transfer of possession of the Policy to the Employer during the term specified in Part II of this Agreement. Except as provided in or as otherwise consistent with the provisions of this Agreement, the Employer covenants that it will not exercise its rights under the Collateral Assignment provisions of this Agreement in such a manner as to defeat the rights of the Employee or the policy beneficiary under this Agreement. Specifically, the Employer covenants that it will not surrender the Policy unless Part I of the Agreement has terminated as provided in Section F and there has been a default in Employee's obligation under Section G of this Part I. The Employer shall have possession of the Policy during the period that the Employer makes premium payments and until all such payments are repaid. The Employer shall make the Policy available to the Insurer in order to make any change desired by the Employee as to the designation of beneficiary or the selection of a settlement option, subject, however, to the Collateral Assignment provisions hereof. D. Beneficiary Designation and Payment of Policy Proceeds The Employee shall be entitled to a death benefit from the Policy equal to one (1) times his base salary, excluding bonuses, until his retirement. At retirement, his death benefit shall increase to two (2) times salary for the next 12 months, then shall decrease by 20% of final salary each year until the earlier of the fifth anniversary of retirement or age 70, at which time it will be one (1) times salary. The Employee shall have the right to name the Policy beneficiary. However, in the event of the Employee's death, the Employer shall have an interest in the Policy proceeds equal to the total Policy proceeds in excess of the amount due to the Employee pursuant to this Section above. E. Procedure at Employee's Death Upon the death of the Employee while the policy and this Agreement are in force and subject to the provisions of Parts I and II hereof, the Employer shall promptly take all necessary steps, including rendering of such assistance as may reasonably be required by the Employee's beneficiary, to obtain payment from the Insurer of the amounts payable under the Policy to the respective parties, as provided under Section D, above.

F. Termination of Agreement Part I of this Agreement shall terminate when the first of any of the following events occur: 1. Termination of the Employee's employment with the Employer prior to retirement; 2. The later of the Employee's actual retirement or ten years from the date of issuance of the Policy; 3. Performance of the Agreement's terms following the death of the Employee; 4. Failure by the Employer, for any reason, to make the premium contributions required under Section B of this Agreement; G. Disposition of Policy Upon Termination of Agreement Upon the termination of Part I of this Agreement for any reason other than Section F3 above, the Employee shall have a thirty (30) day option to satisfy the Collateral Assignment regarding the policy held by the Employer in accordance with the terms of this Paragraph G. The amount necessary to satisfy such Collateral Assignment shall be an amount equal to the total premium payments made, from time to time, greater than the amount of cash value under the Policy and, at the option of the Employee, either shall be paid directly by the Employee or through the Employer's collection from the cash value under the policy. If the Policy shall then be encumbered by assignment, policy loan, or other means which have been the result of the Employer's actions, the Employer shall either remove such encumbrance, or reduce the amount necessary to satisfy the Collateral Assignment by the total amount of indebtedness outstanding against the Policy. If the Employee exercises his option to satisfy the Collateral Assignment, the Employer shall execute all necessary documents required by the Insurer to remove and satisfy the Collateral Assignment outstanding on the Policy. If the Employee does not exercise his option to satisfy the Collateral Assignment outstanding on the Policy, the Employee shall execute all documents necessary to transfer ownership of the Policy to the Employer. Such Transfer shall constitute satisfaction of any obligation the Employee has to the Employer with respect to this Agreement. The Employer shall then pay to the Employee the amount, if any, by which the cash surrender value of the Policy exceeds the amount necessary to satisfy the Collateral Assignment. H. Employee's Right to Assign His/Her Interest The Employee shall have the right to transfer his/her entire interest in the Policy (other than rights assigned to the Employer pursuant to this

Agreement and subject to the obligations of any outstanding Collateral Assignment). If the Employee makes such a transfer, all his/her rights shall be vested in the Transferee and the Employee shall have no further interest in the Policy and Agreement. Any assignee shall be subject to all obligations of the Employee under both Parts I and II of this Agreement. I. Insurer's Obligations The Insurer is not party to this Agreement. It is understood by the parties hereto that in issuing such Policy of insurance, the Insurer shall have no liability except as set forth in the Policy and except as set forth in any assignment of the Policy filed at its Home Office and in Section J of this Agreement. Except as set forth in Section J, the Insurer shall not be bound to inquire into, or take notice of, any of the covenants herein contained as to the Policy of insurance or as to application of proceeds of such Policy. Upon the death of the Insured and payment of the proceeds in accordance with Section J of this Agreement, the insurer shall be discharged of all liability. J. Claims Procedure The following claims procedure shall apply to the Policy and the Executive Life Insurance Program: 1. Filing of a claim for benefits. The Employee or the beneficiary of the Policy shall make a claim for the benefits provided under the Policy in the manner provided in the Policy. 2. Claim denial. With respect to a claim for benefits under said Policy, the Insurer shall be the entity which reviews and makes decisions on claim denials according to the terms of the Policy. 3. Notification to claimant of decision. If a claim is wholly or partially denied, notice of the decision, meeting the requirements of Section J4, following shall be furnished to the claimant within a reasonable period of time after a claim has been filed. 4. Content of notice. The Insurer shall provide, to any claimant who is denied a claim for benefits, written notice setting forth in a manner calculated to be understood by the claimant, the following: a. The specific reason or reasons for the denial; b. Specific reference to pertinent Policy provisions or provisions of this Agreement on which the denial is based; c. A description of any additional material or information necessary for the claimant to perfect the claim and an explanation of which such material or

information is necessary; and d. An explanation of this Agreement's claim review procedure, as set forth in Sections J5 and J6. 5. Review procedure. The purpose of the review procedure set forth in this subsection and subsection 6, following, is to provide a method by which a claimant under the Policy may have a reasonable opportunity to appeal a denial of claim for a full and fair review. To accomplish that purpose, the claimant or his/her duly authorized representative: a. May request a review upon written application to the Insurer; b. May review the Policy; and c. May submit issues and comments in writing. A claimant, (or his/her duly authorized representative), shall request a review by filing a written application of review at any time within sixty (60) days after receipt by the claimant of written notice of the denial of the claim. 6. Decision on review. A decision on review of a denial of a claim shall be made in the following matter; a. The decision on review shall be made by the Insurer which may, at its discretion, hold a hearing on the denied claim. The Insurer shall make its decision promptly, unless special circumstances (such as the need to hold a hearing) require an extension of time for processing, in which case a decision shall be rendered as soon as possible, but not later than on hundred twenty (120) days after receipt of the request for review. b. The decision on review shall be in writing and shall include specific reasons for the decision, written in a manner calculated to be understood by the claimant, and specific references to the pertinent Policy provision or provision of this Agreement on which the decision is based. Notwithstanding any provision of the Agreement or the Policy, no Employee, assignee or beneficiary may commence any action in any court regarding the Policy prior to pursuing all rights of an Employee under this Section J.

PART II - Assignment of Life Insurance Policy as Collateral A. For value received and in specific consideration of the premium payments made by the Employer as set forth in Section B of Part I hereof, the Employee hereby assigns, transfers and sets over to the Employer (herein in this Part II called the "Assignee"), its successors and assigns, the Policy issued by the Insurer upon the life of Employee and all claims, options, privileges, rights, titles and interest therein and thereunder (except as provided in Paragraph C hereof), subject to all terms and conditions of the Policy and to all superior liens, if any, which the Insurer may have against the Policy. The Employee by this instrument agrees and the Assignee by the acceptance of this assignment agrees to the conditions and provisions herein set forth. B. It is expressly agreed that, without detracting from the generality of the foregoing, the following specific rights are included in this Agreement and Collateral Assignment and inure to the Assignee by virtue hereof: 1. The sole right to collect from the Insurer the net proceeds of the Policy in excess of the proceeds due the Employee under Part I, Section D when it becomes a claim by death or maturity; 2. The sole right to surrender the Policy and receive the surrender value thereof at any time provided by the terms of the Policy and at such other times as the Insurer may allow; 3. The sole right to obtain one or more loans or advances on the policy, either from the Insurer or, at any time, from other persons, and to pledge or assign the Policy as security for such loans or advances; 4. The sole right to collect and receive all distributions or share of surplus, dividend deposits or additions to he Policy now or hereafter made or apportioned thereto, and to exercise any and all options contained in the Policy with respect thereto; provided, that unless and until the Assignee shall notify the Insurer in writing to the contrary, the distributions or share of surplus, dividend deposits and additions shall continue on the Policy in force at the time of this assignment; and 5. The sole right to exercise all nonforfeiture rights permitted by the terms of the Policy or allowed by the Insurer and to receive all benefits and advantages derived therefrom. C. It is expressly agreed that the following specific rights, so long as the Policy has not been surrendered, are reserved and excluded from this Agreement and Collateral Assignment and do not pass by virtue hereof:

1. The right to designate and change the beneficiary; 2. The right to elect any optional mode of settlement permitted by the Policy or allowed by the Insurer; provided, however, that the reservation of these rights shall in no way impair the right of the Assignee to surrender the Policy completely with all its incidents or impair any other right of the Assignee hereunder, and any designation or change of beneficiary or election of a mode of settlement shall be made subject to this Agreement and Collateral Assignment and to the rights of the Assignee hereunder. D. This Collateral Assignment is made and the Policy is to be held as collateral security for any and all liabilities of the Employee to the Assignee arising under this Agreement (all of which liabilities secured to or to become secured are herein called "Liabilities"). It is expressly agreed that all sums received by the Assignee hereunder either in event of death of the Insured, the maturity or surrender of the Policy, the obtaining of a loan or advance on the Policy, or otherwise, shall first be applied to the payment of the liability for premiums paid by the Assignee on the Policy. E. The Assignee covenants and agrees with the Employee as follows: 1. That any balance of sums, if any, received hereunder from the Insurer remaining after payment of the existing Liabilities, matured or unmatured, shall be paid by the Assignee to the persons entitled thereto under the terms of the policy had this Collateral Assignment not been executed: 2. That the Assignee will not exercise either the right to surrender the Policy or the right to obtain policy loans from the Insurer, until there has been either default in any of the Liabilities pursuant to this Agreement or termination of Part I of said Agreement as therein provided; and 3. That the Assignee will, upon request, forward without reasonable delay to the Insurer the Policy for endorsement of any designation or change of beneficiary or any election of an optional mode of settlement. F. The Employee declares that no proceedings in bankruptcy are pending against him/her and that his/her property is not subject to any assignment for the benefit of creditors.

PART III - Provisions Applicable to Parts I an II A. Amendments Amendments may be added to this Agreement by a written agreement signed by each of the parties and attached hereto. B. Choice of Law This agreement shall be subject to, and construed according to, the laws of the State of . C. A Binding Agreement This Agreement shall bind the Employer and the Employer's successors and assigns, the Employee and his/her heirs, executors, administrators, and assigns, and any Policy beneficiary. D. Provision The Employer and the Employee agree that if any provision of this Agreement is determined to be invalid or unenforceable, in whole or part, then all remaining provisions of this Agreement and, to the extent valid or enforceable, the provision in question shall remain valid, binding and fully enforceable as if the invalid or unenforceable provisions, to the extent necessary, was not a part of this Agreement. IN WITNESS WHEREOF, parties hereto have executed this Agreement, including the provisions regarding Collateral Assignment, on the day and year first above written. Witness Employee Address Employer (Title)

Exhibit 10.6 AGREEMENT SECURED BENEFIT PLAN AND COLLATERAL ASSIGNMENT THIS AGREEMENT is entered into this _____ day of __________, 1992 by and between Allegheny Power Service Corporation (hereinafter called the "Employer" in Part I or "Assignee" in Part II), and ___________________________ (hereinafter called the "Employee"). WHEREAS the Employee is currently a valued employee and Executive of Employer; WHEREAS the Employer wishes to assist the Employee with his (or her) personal future financial program and the Employee desires to accept such assistance; and WHEREAS in consideration of the Employer agreeing to pay all of the premiums, the Employee agrees to grant the Employer security for the recovery of the Employer's premium outlay and the excess, if any, over the amounts due the Employee under Part I of this Agreement. NOW, THEREFORE, for value received, the Employer and the Employee agree as follows: Part I - Individual Life Insurance Agreement A. Description of Policy - Policy Ownership In furtherance of the purposes of the Agreement, the Employee will purchase and own a certain policy of life insurance on his own life, being Policy No. _____, issued by Pacific Mutual Life Insurance Co. Said policy is hereinafter called the "Policy" and said life insurance company is hereinafter called the "Insurer". The Employee's ownership of the Policy shall be subject to all the terms and conditions set forth in this Agreement. B. Payment of Premiums The Employer shall pay the entire annual premium for the Policy directly to the Insurer. C. Collateral Assignment and Possession of Policy To secure repayment of premiums paid by and amounts due to the Employer provided for in Section B, above, and Sections D and E, below, Part II of this Agreement includes an assignment of the policy or the Employee's interest therein (hereinafter called "Collateral Assignment") and provides for the transfer of possession of the policy, and the right to receive from the carrier and possess billings and policy statements, to the

Employer during the term specified in Part II of this Agreement. Except as provided in or as otherwise consistent with the provisions of this Agreement, the Employer covenants that it will not exercise its rights under the Collateral Assignment provisions of this Agreement in such a manner as to defeat the rights of the Employee or the policy beneficiary under this Agreement. Specifically, the Employer covenants that it will not surrender the Policy unless Part I of the Agreement has terminated as provided in Section G and there has been a default in Employee's obligation under Section H of this Part I. The Employer shall have possession of the Policy during the period that the Employer makes premium payments and until all amounts due the Employer are repaid. The Employer shall make the Policy available to the Insurer in order to make any change desired by the Employee as to the designation of beneficiary or the selection of a settlement option, subject, however, to the provisions of this Agreement and the Collateral Assignment. D. Beneficiary Designation and Payment of Policy Proceeds The Employee shall be entitled to a death benefit from the Policy in the amount required to provide an annuity equal to (under then current annuity settlement rates from the Insurer) the supplemental retirement benefit that would be provided under Sections 4A and 4B of the Allegheny Power System Supplemental Executive Retirement Plan effective July 1, 1990, attached hereto as Appendix I, excluding the provision in Section 4A that states, "...provided that, if a Participant is discharged from employment for cause or terminates employment with the Companies prior to retirement under the Allegheny Power System Retirement Plan for any reason whatsoever, other than death, such eligibility will terminate and no benefit shall be payable to such Participant from this Plan." The Employer shall be the sole beneficiary of the policy until such time as the Employee has at least 10 years of service and is at least 55 years old. After that time and while this Agreement is in force, the following shall occur: 1. the beneficiary of the Employee's death benefit shall be the employee's spouse; 2. in the event of the Employee's death, the Employer shall be entitled to Policy proceeds equal to the total Policy proceeds in excess of the amount due to the Employee pursuant to this Section, above; and 3. if the employee is not married, he/she is entitled to no death benefit while this agreement is in force. E. Policy Cash Values The Employee shall be entitled to cash values of the Policy in excess of the premiums paid by the Employer pursuant to Section B, Above, but not to exceed the death benefits to which he/she is entitled under Section D, above. If the Employee is not married, he/she shall be entitled to cash values determined as if he/she were married. The Employer shall be entitled to Policy cash values in excess of the amount due to the Employee under this Section, above.

F. Procedure at Employee's Death Upon the death of the Employee while the Policy and this Agreement are in force and subject to the provisions of Parts I and II hereof, the Employer shall promptly take all necessary steps, including rendering of such assistance as may reasonably be required, to obtain payment from the Insurer of the amounts payable under the Policy to the respective parties, as provided under Section D, above. G. Termination of Agreement Part I of this Agreement shall terminate when the first of any of the following events occur: 1. Termination of the Employee's employment with the Employer prior to retirement; 2. The later of the Employee's actual retirement or ten years from the date of issuance of the policy; 3. Performance of the Agreement's terms following the death of the Employee; 4. Failure by the Employer, for any reason, to make the premium contributions required under Section B of this Agreement. H. Disposition of Policy Upon Termination of Agreement Upon the termination of Part I of this Agreement for any reason other than Section G3 above, the Employee shall have a thirty (30) day option to satisfy the Collateral Assignment regarding the policy held by the Employer in accordance with the terms of this Paragraph H. The amount necessary to satisfy such Collateral Assignment shall be an amount equal to the total premium payments made by the Employer, plus any excess amounts as determined in Section E, above, but no greater than the amount of cash value under the Policy and, at the option of the Employee, either shall be paid directly by the Employee or through the Employer's collection from the cash value of the Policy. If the Policy shall then be encumbered by assignment, policy loan, or other means which have been the result of the Employer's actions, the Employer shall either remove such encumbrance, or reduce the amount necessary to satisfy the Collateral Assignment by the total amount of indebtedness outstanding against the Policy. If the Employee exercises his option to satisfy the Collateral Assignment, the Employer shall execute all necessary documents required by the Insurer to remove and satisfy the Collateral Assignment outstanding on the Policy. If the Employee does not exercise his option to satisfy the Collateral Assignment outstanding on the Policy, the Employee shall execute all documents necessary to transfer ownership of the Policy to the Employer. Such transfer shall constitute satisfaction of any obligation the Employee has to the Employer with respect to this Agreement. The Employer shall then pay to the Employee the amount, if any, by which the cash surrender value of the Policy exceeds the amount necessary to satisfy the Collateral Assignment.

I. Employee's Right to Assign His/Her Interest Employee agrees not to sell, assign, surrender or otherwise terminate the policy while this Agreement is in effect without the consent of the Employer. J. Insurer's Obligations The Insurer is not a party to this Agreement. It is understood by the parties hereto that in issuing such Policy of insurance, the Insurer shall have no liability except as set forth in the Policy and except asset forth in any assignment of the Policy filed at it Home Office and in Section K of this Agreement. Except as set forth in Section K, the Insurer shall not be bound to inquire into, or take notice of, any of the covenants herein contained as to the Policy of insurance or as to application of proceeds of such policy. Upon the death of the Insured and payment of the proceeds in accordance with Section K of this Agreement, the Insurer shall be discharged of all liability. K. Claims Procedure The following claims procedure shall apply to the Policy and the Secured Benefit Plan: 1. Filing of a claim for benefits. The Employee or the Beneficiary shall make a claim for the benefits provided under the policy in the manner provided in the Policy. 2. Claim denial. With respect to a claim for benefits under said Policy, the Insurer shall be the entity which reviews and makes decisions on claim denials according to the terms of the Policy. 3. Notification to claimant of decision. If a claim is wholly or partially denied, notice of the decision, meeting the requirements of Section K4, following, shall be furnished to the claimant within a reasonable period of time after a claim has been filed. 4. Content of notice. The insurer shall provide, to any claimant who is denied a claim for benefits, written notice setting forth in a manner calculated to be understood by the claimant, the following: a. The specific reason or reasons for the denial; b. Specific reference to pertinent Policy provisions or provisions of this Agreement on which the denial is based; c. A description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary; and d. An explanation of this Agreement's claim review procedure, as set forth in Sections K5 and K6.

5. Review procedure. The purpose of the review procedure set forth in this subsection and subsection 6, following, is to provide a method by which a claimant under the Policy may have a reasonable opportunity to appeal a denial of claim for a full and fair review. To accomplish that purpose, the claimant or his/her duly authorized representative: a. May request a review upon written application to the Insurer; b. May review the Policy; and c. May submit issues and comments in writing. A claimant, (or his/her duly authorized representative), shall request a review by filing a written application of review at any time within sixty (60) days after receipt by the claimant of written notice of the denial of the claim. 6. Decision on review. A decision on review of a denial of a claim shall be made in the following matter: a. The decision on review shall be made by the Insurer which may, at its discretion, hold a hearing on the denied claim. The Insurer shall make its decision promptly, unless special circumstances (such as the need to hold a hearing) require an extension of time for processing, in which case a decision shall be rendered as soon as possible, but not later than one hundred twenty (120) days after receipt of the request for review. b. The decision on review shall be in writing and shall include specific reasons for the decision, written in a manner calculated to be understood by the claimant, and specific references to the pertinent Policy provision or provision of this Agreement on which the decision is based. Notwithstanding any provision of the Agreement or the Policy, no Employee, assignee or beneficiary may commence any action in any court regarding the Policy prior to pursuing all rights of an Employee under this Section K.

END OF PART I Part II - Assignment of Life Insurance Policy as Collateral A. For value received and in specific consideration of the premium payments made by the Employer as set forth in Section B of Part I hereof, the Employee hereby assigns, transfers and sets over to the Employer (herein this Part II called the "Assignee"), its successors and assigns, the Policy issued by the Insurer upon the life of Employee and all claims, options, privileges, rights, titles and interest therein and thereunder (except as provided in Paragraph C hereof), subject to all terms and conditions of the Policy and to all superior liens, if any, which the Insurer may have against the Policy. The Employee by this instrument agrees and the Assignee by the acceptance of this Assignment agrees to the conditions and provisions herein set forth. B. It is expressly agreed that, without detracting from the generality of the foregoing, the following specific rights are included in this Agreement and Collateral Assignment and inure to the Assignee by virtue hereof: 1. The sole right to collect from the Insurer the net proceeds of the Policy in excess of the proceeds due the Employee under Part I, Section D, when it becomes a claim by death or maturity; 2. The sole right to surrender the Policy and receive the surrender value thereof at any time provided by the terms of the Policy and at such other times as the Insurer may allow; 3. The sole right to obtain one or more loans or advances on the policy, either from the Insurer or, at any time, from other persons, and to pledge or assign the Policy as security for such loans or advances; 4. The sole right to exercise all nonforfeiture rights permitted by the terms of the Policy or allowed by the Insurer and to receive all benefits and advantages derived therefrom; 5. The sole right to direct investment of cash values as provided under the insurance contract, and to make changes and transfers in such fund allocations. C. It is expressly agreed that the following specific rights, so long as the Policy has not been surrendered, are reserved and excluded from this Collateral Assignment and do not pass by virtue hereof: 1. The right to designate and change the beneficiary; 2. The right to elect any optional mode of settlement permitted by the Policy or allowed by the Insurer; provided, however, that the reservation of these rights shall in no way impair the right of the Assignee to surrender the Policy completely with all its incidents or impair any other right of the Assignee hereunder, and any designation or change of beneficiary or election of a mode of settlement shall be made subject to this Agreement and Collateral Assignment and to the rights of the Assignee hereunder. D. This Collateral Assignment is made, and the Policy is to be held as collateral security for, any and all liabilities of the Employee to the Assignee arising under this Agreement (all of which liabilities secured or to become secured are herein called "Liabilities"). It is expressly agreed that all sums received by the Assignee hereunder either in the event of death of the Insured, the maturity or surrender of the Policy, the obtaining of a loan or advance on the Policy, or otherwise, shall first be applied to the payment of the liability for premiums paid by the Assignee on the Policy and other amounts due to Assignee under Part I of this Agreement.

E. The Assignee covenants and agrees with the Employee as follows: 1. That any balance of sums, if any, received hereunder from the Insurer remaining after payment of the existing Liabilities, matured or unmatured, shall be paid by the Assignee to the persons entitled thereto under the terms of the policy had this Collateral Assignment not be executed; 2. That the Assignee will not exercise either the right to surrender the Policy or the right to obtain policy loans from the Insurer, until there has been either default in any of the Liabilities pursuant to this Agreement or termination of part I of said Agreement as therein provided; and 3. That the Assignee will, upon request, forward without unreasonable delay to the Insurer the Policy for endorsement of any designation or change of beneficiary or any election of an optional mode of settlement. F. The Employee declares that no proceedings in bankruptcy are pending against, him/her and that his/her property is not subject to any assignment for the benefit of creditors. Part III - Provisions Applicable to Parts I and II A. Amendments Amendments may be added to this Agreement by a written agreement signed by each of the parties and attached hereto. B. Choice of Law This Agreement shall be subject to, and construed according to, the laws of the State of Maryland. C. Binding Agreement This Agreement shall bind the Employer and the Employer's successors and assigns, the Employee and his/her heirs, executors, administrators, and assigns, and any Policy beneficiary. D. Validity of Provisions The Employer and the Employee agree that if any provision of this Agreement is determined to be invalid or unenforceable, in whole or part, then all remaining provisions of the Agreement and, to the extent valid or enforceable, the provision in question shall remain valid, binding and fully enforceable as if the invalid or unenforceable provisions, to the extent necessary, was not a part of this Agreement. IN WITNESS WHEREOF, parties hereto have executed this Agreement, including the provisions regarding Collateral Assignment, on the day and year first above written. ________________________ _________________________ Witness Employee ____________________________ _____________________________ Address Allegheny Power Service Corporation By: ____________________________ Richard J. Gagliardi Vice President

Exhibit 10.7 ALLEGHENY POWER SYSTEM, INC. RESTRICTED STOCK PLAN FOR OUTSIDE DIRECTORS 1. Purpose. The purpose of this Restricted Stock Plan for Outside Directors (the "Plan") is to enable Allegheny Power System, Inc. ("APS") and its controlled subsidiaries ("Subsidiaries") to attract and retain persons of outstanding competence to serve on the Boards of Directors of APS and its Subsidiaries by paying such persons a portion of their retainer fee in APS Common Stock pursuant to the terms hereof. 2. Definitions. (a) The term "Change in Control" shall be deemed to mean, and to occur at, the time when either (i) any entity, person or group (other than APS, any subsidiary, or any savings, pension or other benefit plan for the benefit of employees of APS or its subsidiaries) which theretofore owned less than 20% of the APS Common Stock then outstanding acquires shares of Common Stock in a transaction or series of transactions that results in such entity, person or group directly or indirectly owning beneficially 20% or more of the outstanding Common Stock or (ii) the election or appointment, within a twelve-month period, of persons to the APS Board of Directors who were not directors of APS at the beginning of such twelve-month period, whose election or appointment was not voted or approved in advance by a majority of those persons who were directors at the beginning of such period, and which newly elected or appointed directors shall constitute a majority of the APS Board of Directors. (b) The term "Outside Director" or "Participant" means a member of the Boards of Directors of APS and its Subsidiaries who is not, at any time during his service as a director, an employee (within the meaning of Section 3(6) of the Employee Retirement Income Security Act of 1974) of APS or any of its Subsidiaries. (c) The term "Subsidiary" means any corporation 50% or more of the outstanding Common Stock of which is owned, directly or indirectly, by APS. (d) The term "Service" shall mean service as an Outside Director. 3. Eligibility. All who serve as Outside Directors of APS and any of its Subsidiaries after calendar year 1994 shall be eligible to receive stock awards hereunder.

4. Stock Awards. (a) A total of 25,000 shares of APS Common Stock shall be available for awards under the Plan. Such shares shall be shares of APS Common Stock previously unissued or previously issued and reacquired by APS. Any restricted shares awarded under this Plan with respect to which the restrictions do not lapse and which are forfeited as provided herein shall be transferred into the record name of APS and again be available for other awards under the Plan. (b) Unless he or she chooses otherwise pursuant to Section 4(e), each Outside Director shall receive an annual award of 200 shares of APS Common Stock with respect to each calendar year or portion thereof during which he or she serves as an Outside Director beginning with the calendar year 1995. Awards shall be made in January of each year or as soon thereafter as all necessary regulatory approvals have been received. However, for the calendar year in which an Outside Director commences Service, the award of shares to such Outside Director for such year shall be made in the month in which his or her Service commences, if his or her Service commences after January 31 of such year. All awards of shares made hereunder shall be subject to the restrictions set forth in Section 5. (c) Subject to the provisions of Section 5, certifi- cates representing shares of APS Common Stock awarded hereunder shall be registered in the name of the respective Participants. During the period of time such shares are subject to the restrictions set forth in Section 5, such certificates shall be endorsed with a legend to that effect, and shall be held by APS or an agent therefor. The Participant shall, nevertheless, have all the other rights of a shareholder, including the right to vote and the right to receive all cash dividends paid with respect to such shares. Subject to the requirements of applicable law, certificates representing such shares shall be delivered to the Participant within 30 days after the lapse of the restrictions to which they are subject. (d) If as a result of a stock dividend, stock split, recapitalization (or other adjustment in the stated capital of APS) or as the result of a merger, consolidation, or other reorganization, the common shares of APS are increased, reduced, or otherwise changed, the number of shares available and to be awarded hereunder shall be appropriately adjusted, and if by virtue thereof a Participant shall be entitled to new or additional or different shares, such shares to which the Participant shall be entitled shall be subject to the terms, conditions, and restrictions herein contained relating to the original shares. In the event that warrants or rights are awarded with respect to shares awarded hereunder, and the recipient exercises such rights or warrants, the shares or securities issuable upon such exercise shall be likewise subject to the terms, conditions, and restriction herein contained relating to the original shares.

(e) (i) Each Outside Director may choose prior to the effective date of the Plan or prior to his/her initial election as a Director and annually thereafter to receive Alternate Shares in lieu of the annual award of shares subject to the restrictions set forth in Section 5. If the Director chooses to receive Alternate Shares, he/she shall receive certificates representing 200 shares of APS Common Stock free of the restrictions set forth in Section 5(a) and (b) but subject to the restriction set forth in Section 5(c). (ii) Any such choice will be effective only if made in a writing delivered to the Secretary of APS prior to the effective date of the Plan or, with respect to awards for years subsequent to 1995, prior to the date of the APS stockholders meeting held prior to the calendar year of the award. An Outside Director elected other than at an annual meeting who desires to choose not to receive shares restricted by Section 5 shall do so in a writing delivered to the APS Secretary prior to his/her election. Any choice so made shall continue in effect until the Outside Director shall timely deliver to the Secretary a writing revoking the prior choice. 5. Restrictions. (a) Shares are awarded to a Participant on the condi- tion that he or she serves as an Outside Director until: (i) the Participant's death or disability; or (ii) the Participant's failure to stand for re-election at the end of the term during which the Participant reaches age 65; or (iii) the Participant's resignation or failure to stand for re-election prior to the end of the term during which the Participant reaches age 65 with the consent of the Board, i.e., approval thereof by at least 80% of the Directors voting thereon, with the affected Director abstaining; or (iv) the Participant's failure to be re- elected after being duly nominated.

For purposes of this Plan, "disability" shall mean a Participant's complete and permanent inability, by reason of illness or accident, to perform his or her duties as a member of the Board, as determined by the Administration Committee based on medical evidence acceptable to it. Termination of Service of a Participant for any other reason, including, without limitation, any involuntary termination effected by Board action, shall result in forfeiture of all shares awarded. Notwithstanding the foregoing, upon the occurrence of a Change in Control, the restrictions set forth in this Section 5 to which any shares awarded to a Participant are then still subject shall lapse, and termination of the Participant's Service for any reason at any time after the occurrence of such Change in Control shall not result in the forfeiture of any such shares. (b) Shares awarded hereunder may not be sold, assigned, exchanged, transferred, pledged, hypothecated, made subject to gift, or otherwise disposed of (herein, "Transferred") other than to APS pursuant to Section 4(a) during the period commencing on the date of the award of such shares and ending on the date of termination of the Outside Director's Service; provided, however, that in no event, may any shares awarded hereunder be Transferred for a period of six months following the date of the award thereof, except in the case of the recipient's death or disability, other than to APS pursuant to Section 4(a) hereof. (c) Each Participant shall represent and warrant to and agree with APS that he or she (i) takes any shares awarded under the Plan for investment only and not for purposes of sale or other disposition and will also take for investment only and not for purposes of sale or other disposition any rights, warrants, shares or securities which may be issued on account of ownership of such shares, and (ii) will not sell or transfer any shares awarded or any shares received upon exercise of any such rights or warrants except in accordance with (A) an opinion of counsel for APS (or other counsel acceptable to APS) that such shares, rights, warrants or other securities may be disposed of without registration under the Securities Act of 1933, or (B) an applicable "no action" letter issued by the Staff of the Securities and Exchange Commission. 6. Administration Committee. An Administration Committee (the "Committee") shall have full power and authority to construe and administer the Plan. Any action taken under the provisions of the Plan by the Committee arising out of or in connection with the administration, construction, or effect of the Plan or any rules adopted thereunder shall, in each case, lie within the discretion of the Committee and shall be conclusive and binding upon APS and upon all Participants, and all persons claiming under or through any of them. Notwithstanding the foregoing, any determination made by the Committee after the occurrence of a Change in Control that denies in whole or in part any claim made by any individual for benefits under the Plan shall be subject to judicial review, under a "de novo", rather than a deferential, standard. The Committee shall have as members the Chief Executive Officer of APS and two officers of APS or its Subsidiaries designated by the Chief Executive Officer. In the absence of such designation, the other members of the Committee shall be, in order of automatic designation, the Vice President Administration and the Secretary of APS.

7. Successor Corporation. The obligations under this Plan shall be binding upon any successor corporation or organization resulting from the merger, consolidation or other reorganization of APS, or upon any successor corporation or organization succeeding to substantially all of the assets and business of APS. APS agrees that it will make appropriate provision for the preservation of Participants' rights under this Plan in any agreement or plan which it may enter into or adopt to effect any such merger, consolidation, reorganization or transfer of assets. 8. Right to Continued Service. Neither this Plan nor any action taken hereunder shall be construed as giving any employee any right to continued service as a Director of APS. 9. No Liability of Committee Members. No member of the Committee shall be personally liable by reason of any contract or other instrument executed by such member or on his or her behalf in his or her capacity as a member of the Committee nor for any mistake of judgment made in good faith, and APS shall indemnify and hold harmless each member of the Committee, and each employee, officer, director or trustee of APS or any of its Subsidiaries to whom any duty or power relating to the administration or interpretation of this Plan may be allocated or delegated, against any cost or expense (including counsel fees) or liability (including any sum paid in settlement of a claim with the approval of the Board of Directors) arising out of any act or omission to act in connection with this Plan unless arising out of such person's own fraud or bad faith. 10. Governing Law. This Plan shall be governed by and construed in accordance with the laws of the state of incorporation of APS, without reference to the principles of conflicts of law thereof. 11. Approval: Effective Date. The Plan is subject to the approval of the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. Upon receipt of such approval, the Plan shall be effective January 1, 1995.

12. Amendment and Termination. The Plan may be amended or terminated by the Board of Directors of APS, provided that, if any such amendment requires shareholder approval to meet the requirements of the then applicable rules under Section 16(b) of the Securities Exchange Act of 1934, such amendment shall require the approval of a majority of the holders of APS's Common Stock present and entitled to vote at a meeting of shareholders, and provided that such action shall not adversely affect any Participant's rights under the Plan with respect to awards which were made prior to such action. Notwithstanding the foregoing, Section 4(b) of the Plan may not be amended more often than once every six months other than to comport with changes in the Internal Revenue Code or the Employee Retirement Income Security Act, or the rules thereunder.

Exhibit 10.8 ALLEGHENY POWER SYSTEM BOARD OF DIRECTORS RETIREMENT PLAN (Effective January 1, 1995)

ALLEGHENY POWER SYSTEM BOARD OF DIRECTORS RETIREMENT PLAN 13. Purpose of the Plan: The purpose of the Plan, the "Allegheny Power System Board of Directors Retirement Plan" (hereinafter referred to as the "Plan") is to provide for the payment of retirement benefits to the outside directors of Allegheny Power System, Inc. (hereinafter sometimes referred to as "Company") and its controlled subsidiaries (the "Subsidiaries") as part of their overall directors' remuneration package. This will help to assist the Companies in attracting, motivating and retaining directors of superior ability, and loyalty. 14. Eligibility to Participate in the Plan: Each person who is a Director of the Company and the Subsidiaries on January 1, 1995 or, thereafter becomes a Director and who is not, at any time during his/her service as a Director, an employee of the Company or any Subsidiary shall be eligible to participate in the Plan. Any person who on January 1, 1995 is, or thereafter becomes, eligible to receive a benefit under any present or future basic pension plan established for the benefit of employees of the Company or of any Subsidiary shall not be eligible to participate in the Plan; and any Participant who becomes an employee of the Company or a Subsidiary and eligible to receive a benefit under such basic pension plan shall cease to be eligible for benefits under this Plan and shall forfeit any benefits that the Participant may then have become entitled to under the Plan without regard to his age or Plan Years of Service.

15. Definitions: A. Retainer - shall mean the aggregate of the annual Director's retainer fees being paid on the date of the Participant's retirement by the Company and those Subsidiaries of which the Participant is a Director. B. Committee - shall mean the Management Review Committee of the Board of Directors of the Company ("the Board") and such other committee to which the Board may, from time to time, assign the Committee's responsibilities. C. Effective Date - shall mean January 1, 1995. D. Participant - shall mean any Director who meets the eligibility requirements of Section 2. E. Plan Year - shall mean the approximately 12-month period be- tween annual meetings of the stockholders of the Company. F. Plan Years of Service - shall mean the Participant's years of service as a Company Director measured from the date of first election as a Company Director, whether occurring before or after the Effective Date.

16. Plan Retirement Benefits: A. Eligibility for Benefits - I. Subject to the provisions of Section 5A, a Participant shall be eligible to receive upon retirement after attaining age 65 a benefit from this Plan upon completion of 5 Plan Years of Service as a Director of the Company; provided that, if a Participant ceases to serve as a Director of the Company prior to attaining age 65 for any reason whatsoever other than because of the occurrence of a Special Event (as defined below), such eligibility will terminate forthwith and no benefit shall be payable to such Participant or such Participant's spouse under this Plan. II. (a) A Special Event shall be deemed to have occurred if, before attaining age 65, a Participant shall (a) Die after serving as a Director for 5 Plan Years. (b) Become disabled after serving as a Director for 5 Plan Years. (c) With the consent of 80% of the Directors voting thereon (with the Participant

abstaining) resign or fail to stand for reelection. For purposes of this Plan, "disability" shall mean a Participant's complete and permanent inability, by reason of illness or accident, to perform his or her duties as a Director, as determined by the Committee based on medical evidence acceptable to it. B. Amount of Benefits - I. An eligible Participant retired other than by reason of a Special Event will be entitled to receive during his/her life an annual pension benefit equal to his/her Retainer; and upon his/her death, his/her surviving spouse shall be entitled to receive during his/her life an annual benefit equal to 50% of that payable to the Participant. II. In the event a Director dies after serving as a Director for 5 Plan Years but before attaining age 65 the Director shall be deemed to have retired one day before the date of his death and the surviving spouse shall be eligible to receive an annual pension benefit equal to that which would have been payable to the surviving spouse of an eligible Participant who had retired on the day

before the date of death of the deceased Participant. III. In the event a Director shall retire because of disability after serving as Director for 5 Plan Years but before attaining age 65, the Participant shall retain his/her eligibility [and his/her pension benefit (and the 50% benefit payable to the Participant's surviving spouse) shall commence in the month following his retirement and be paid as provided in Section 4C] [for a deferred annual pension benefit commencing when he/she attains age 65 in the amount of the annual retainer fees being paid him at the termination of his/her service and the Participant's spouse at the time of such termination shall receive an annual benefit equal to 50% of such amount commencing at the later of the Participant's death or the date on which the Participant would have attained age 65.] IV. A Participant who, with the consent of the Board, resigns or fails to stand for reelection prior to attaining age 65 shall be eligible for a deferred annual pension benefit commencing when he/she

attains age 65 in the amount of the annual retainer fees being paid him at the termination of his/her service, and the Participant's spouse at the time of such termination shall receive an annual benefit equal to 50% of such amount commencing at the later of the Participant's death or the date on which the Participant would have attained age 65. C. Form and Time of Payment - The annual pension benefit payable under this Plan shall be paid by the Company with the Subsidiaries contributing in proportion to their respective retirement retainer amounts in equal monthly payments on the first day of the month, commencing with the month following the month in which the Participant's retirement occurs. 17. Vesting: A. Absence of Vesting - A Participant shall have no vested interest in the Plan. In the event that a Participant ceases for any reason other than the occurrence of a Special Event to be a Director of the Company prior to attaining age 65, any entitlement to benefits shall end, and all his/her rights under the Plan shall terminate without regard to

whether the Participant has served as a Director for 5 Plan Years. B. Change of Control Vesting - Notwithstanding Section 5A, a Participant shall become eligible for Plan Retirement Benefits upon the occurrence of a change of control regardless of the Participant's then age or Plan Years of Service, and Benefits shall be payable to the Participant and his/her spouse in the amounts provided in Section 4B at such time as the Participant ceases to be a Director or dies. A "change in control" is deemed to occur at the time when either (i) any entity, person or group (other than the Company, any Subsidiary or any savings, pension or other benefit plan for the benefit of employees of the Company or its subsidiaries) which theretofore beneficially owned less than 20% of the Company's Common Stock then outstanding acquires shares of Common Stock in a transaction or series of transactions that results in such entity, person or group directly or indirectly owning beneficially 20% or more of the outstanding Common Stock or (ii) the election or appointment, within a twelve-month period, of persons to the Company's Board of Directors who were not directors of the Company at the beginning of such twelve-month period, whose election or appointment was not voted or approved

in advance by a majority of those persons who were directors at the beginning of such period, and which newly elected or appointed Directors shall constitute a majority of the Board of Directors of the Company. 18. Funding: The Plan shall be unfunded and a Participant shall have no interest in any assets of the Company or any Subsidiary. Benefits shall be paid from the general assets of the Company and the Subsidiaries and the rights of a Participant and his/her spouse shall be limited to those of an unsecured general creditor of the Company and the Subsidiaries. No special or separate fund shall be established or other segregation of assets made to assure such payments; provided, however, that the Company and the Subsidiaries may establish a bookkeeping reserve to meet its obligations hereunder. Nothing contained in the Plan, and no action taken pursuant to the provisions of the Plan, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company, the Subsidiaries or the Committee, and any Director or other person. It is the intention of the parties that this Plan shall constitute a mere promise by the Company to make payments in the future of the benefits provided for herein.

19. Administration and Governing Law: This Plan will be administered by and under the direction of the Committee on behalf of the Company and the Subsidiaries. The Committee may adopt, and may from time to time modify or amend, such rules and guidelines (hereinafter referred to as the "Rules and Guidelines") consistent herewith as it may deem necessary or appropriate for carrying out the provisions and purposes of the Plan, which, upon their adoption and so long as in effect, shall be deemed a part hereof to the same extent as if set forth in the Plan. The Committee may also adopt any amendment to this Plan which may be necessary or appropriate to facilitate the administration, management and interpretation of this Plan, provided that any such amendment does not have a material effect on the Plan's cost. Any interpretation and construction by the Committee of any provision of, and the determination of any question arising under, the Plan or the Rules and Guidelines shall be final, conclusive, and binding upon the Company, the Subsidiaries, each Participant and his/her surviving spouse. The provisions of the Plan shall be construed, administered, and enforced according to and governed by the laws of the State of New York. 20. Limitation on Scope of Plan: The Plan shall not be deemed to constitute a contract be- tween the Company or any Subsidiary and any Director of the Company, nor shall anything herein contained be deemed to give any Director of the Company or a

Subsidiary any right to be re-elected or otherwise continue to serve as Director or deny to the Company or any Subsidiary the right to remove any Director at any time. Notwithstanding the preceding sentence, in the event of a change of control of the Company, as defined in Section 5B, the Plan shall be deemed to have created on the effective date of such change of control, a contract binding upon the Company and the Subsidiaries to pay the Plan Retirement Benefits deemed vested by Section 5B. 21. Non-Assignability: It is the intention of the parties that this Plan shall constitute a mere promise by the Company to make payments in the future of the benefits provided for herein. The rights of a Participant and his/her surviving spouse hereunder are not subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, attachment or garnishment by creditors of the Participant or creditors of the Participant's spouse. In the event of any attempted assignment or transfer, the Company shall have no further liability hereunder. Nor shall any payments be transferable by operation of law in the event of bankruptcy or insolvency, except to the extent otherwise provided by applicable law. 22. Tax Withholding: The Company shall withhold from all amounts payable under this Plan all federal, state, local or other taxes

required by law to be withheld with respect to such amounts. 23. Successors and Assigns: Subject to the limitations and restrictions expressed herein, this Plan shall be binding upon and inure to the benefit of the Company and its successors and assigns and the Participants, or their successors, assigns, designees and estates. This Plan shall also be binding upon any successor corporation or organization succeeding to substantially all the assets and business of the Company, but nothing in this Plan shall preclude the Company from merging or consolidating into or with, or transferring all or substantially all of the assets to, another corporation which assumes this Plan and all obligattions of the Company hereunder. Subject to the continuing effectiveness of Sections 5A and 6, the Company agrees to make appropriate provision for the continuation of this Plan and preservation of Participants' rights under this Plan in any agreement or plan which it may enter into to effect any merger, consolidation, reorganization, or transfer of assets and assumption. On the occurrence of such event, the term "Company" shall refer to such other corporation and this Plan shall continue in full force and effect. 24. Termination or Amendment: This Plan may be amended, suspended or terminated, in whole or in part, with prospective or retroactive effect

by action of the Board of Directors of the Company, acting on behalf of the Company and the Subsidiaries, at any time without the consent of any Participant or beneficiary; provided, however, that no such amendment, suspension or termination nor amendment of the Plan shall reduce or terminate any benefit to or in respect of a Participant who has attained age 65 and served five years as Director.

Exhibit 10.9 ALLEGHENY POWER SYSTEM PERFORMANCE SHARE PLAN 1. PURPOSE AND ADMINISTRATION To more directly relate the compensation of the executives of the Allegheny Power System Companies (the "Companies") to the financial results and operating performance of the Companies and to attract and retain key executives in a competitive job market, it is desirable and necessary to create a long-term incentive plan to supplement the Companies' salary and short-term incentive plans. The Allegheny Power System Performance Share Plan (the "Plan") was adopted by the Boards of Directors of the Companies on __________________, and will be submitted to shareholders for approval at the next annual meeting of Allegheny Power System, Inc. (the Company). The Plan is designed to more directly relate the compensation of participants to the long-term performance of the Companies, to provide incentive rewards for the achievement of the long-term performance which benefits both the customers and shareholders of the Companies. The Plan will be administered by the Management Review Committee of the Board of Directors of the Company (the "Committee"). The Plan will become effective, upon approval by shareholders, as of January 1, 1994, and will expire on December 3l, 2007, unless otherwise suspended or terminated pursuant to Article 10 hereof.

2. DESIGN OF THE PLAN The Plan will be made up of performance cycles: (1) which may overlap (2) which shall be described in Performance Cycle Guidelines (Guidelines) detailing the appropriate terms, conditions and performance criteria governing award payments for each performance cycle and (3) which shall be approved by the Boards of Directors, upon recommendation of the Committee. Each performance cycle shall be for a period of not less than three (3) or more than five (5) calendar years. The Boards shall approve the participants in each cycle, the performance criteria and performance shares to be covered by each cycle based on recommendations submitted by the Committee. The first performance cycle shall, subject to approval of the Plan by shareholders, begin on January 1, 1994. Future cycles shall commence on such date as the Boards shall approve, upon the recommendation of the Committee, but no future cycle shall begin sooner than January 1, 1995, nor end on a date after December 31, 2007, and shall be governed by the Guidelines adopted for that cycle.

3. PARTICIPANTS Participation in the Plan will be restricted to senior officers of the Companies as approved by the Boards. The Committee shall determine, in advance of each cycle, the specific senior officers to be included in that performance cycle. It is expected that not more than 15 officers will participate in any performance cycle. The Committee will report named proxy executive officers participating in any performance cycle to the Board for approval. 4. SHARES COVERED BY THE PLAN The total number of shares of common stock of the Company that may be granted under this Plan shall be 500,000. The number of designated shares shall be adjusted to reflect stock splits, stock dividends, and other similar matters affecting the number of outstanding shares of the Company's common stock. In the event any performance shares granted are not paid, whether by reason of the participant's termination of employment, failure to meet performance criteria or otherwise, such shares will be available for grants to participants with respect to other performance cycles under the Plan. 5. PERFORMANCE SHARE GRANTS AND PERFORMANCE The Committee will approve the granting of performance shares to participants in any performance cycle as provided in this Plan. Actual shares of common stock of the Company shall not be issued at the time of grant, but the grant of such shares shall represent the participant's right to receive such shares (or their equivalent value), and dividends credited in shares, with respect to such shares, upon achievement of performance criteria during each performance cycle, measured relative to performance standards and other conditions established by the Committee, and set forth in the Guidelines for that cycle, pursuant to which the shares are granted. The performance cycle over which the Companies' performance is to be measured relative to these performance standards will be determined by the Committee and approved by the Boards at the time of grant. During any performance cycle, dividends will be credited on all performance shares granted, and will be converted into additional shares payable when the underlying performance shares are paid. Payment of any shares granted is contingent on the participant's continued employment during the performance cycle or such other terms as the Committee shall specify in the event of the participant's death, disability, retirement, or involuntary termination following a change in ownership and/or control of the Company.

6. PERFORMANCE CRITERIA AND STANDARDS Performance criteria and standards to be included in the Guidelines for each performance cycle shall include: (a) Customer related criteria such as the cost and quality of service provided to residential customers; and (b) Shareholder related criteria. The Committee shall determine appropriate customer related performance standards such as the Companies' residential service cost ranking and/or the change in the Companies' residential service cost ranking measured, in each case, relative to a peer group of utilities selected by the Committee and identified in the Guidelines. The Committee shall select appropriate shareholder related performance criteria such as total return, dividend return, earnings, return on equity, cash flow related goals, or a combination of any such criteria, measured in each case relative to the peer utility companies used during the performance cycle for the proxy stock performance graph required under the Securities and Exchange Commission's proxy rules applicable at the time. The weighting between customer performance and shareholder performance criteria, for purposes of computing overall awards during any performance cycle, shall be determined by the Committee in the appropriate guidelines. 7. PERFORMANCE SHARE PAYMENTS Payment of earned performance shares will be made in actual shares of common stock of the Company, or a combination of cash and shares, as determined by the Committee at time of grant or payment. The Committee will determine the date as of which any conversion of earned performance shares to cash (based on their fair market value) will be made. Regardless of whether earned performance shares are paid in actual shares of common stock of the Company, or a combination of cash and shares, the full number of shares earned will be deducted from the total number of such shares authorized under the Plan. Within sixty days after receiving a grant of performance shares, a participant may make an irrevocable election, following procedures established by the Committee, to have distribution of any amount he may be entitled to receive with respect to such performance shares deferred until such year as he may elect, after the year in which the amount would otherwise be paid to him; at the same time, he may elect to have such deferred amount, including dividends (or a comparable factor), paid to him in annual installments over a specified period of years. Notwithstanding any election of any participant to receive payment under the Plan on a deferred basis as above provided, the Committee, in its sole discretion, may at any time terminate such election and make immediate distribution of the amount to which the participant is entitled.

8. PAYMENT IN COMMON STOCK: SOURCE OF STOCK It is anticipated that any shares of common stock of the Company paid under the Plan will be made from treasury shares acquired prior to or during the term of the Plan. The Committee may also utilize authorized but unissued shares of the Company's common stock. 9. ADDITIONAL PROVISIONS The grant of performance shares to a participant shall create no rights as a shareholder of the Company until such time that shares of the Company's common stock are delivered to the Participant. In the event of stock dividends, stock splits or other similar matters affecting the number of outstanding shares of the Company's common stock, appropriate revision shall be made in performance shares, granted to participants in order to reflect the effect of such action on the grants to the participants under the Plan. No participant in the Plan shall have any right to continue in the employ of the Companies for any period of time. Rights and powers the Companies now have or may have in the future, to dismiss or discharge any participant from employment or to change the assignment of any participant, are expressly reserved to the Companies. The Companies are authorized to withhold from any payments made under the Plan any amount necessary to satisfy income tax withholding requirements in respect of such payments, and for this purpose may withhold cash or shares of the Company's common stock.

10. PLAN AMENDMENT, SUSPENSION, OR TERMINATION The Boards shall have the authority to amend, revise, or suspend, the Plan, provided that no amendments or revisions shall be made without the consent of shareholders if they would materially increase the benefits accruing to participants, increase the number of Shares which may be paid under the Plan pursuant to Article 5, or modify the requirements as to eligibility for Plan participation. The Boards may also terminate or suspend the operation of the Plan and provided further that no such action will adversely affect the rights of participants to payment of performance shares granted prior to termination or suspension of the Plan, without the prior consent of such participants. 11. NON-ASSIGNABILITY Rights under the Plan and in respect of performance shares granted are not transferable and may not be assigned or pledged by any participant at any time.

Exhibit 18 To the Board of Directors Allegheny Power System, Inc. We have audited the consolidated financial statements included in the Annual Report on Form 10-K of Allegheny Power System, Inc. (the "Corporation") for the year ended December 31, 1994 and issued our report thereon dated February 2, 1995. Note A to the consolidated financial statements describes a change in the Corporation's method of accounting for revenues from a cycle billing basis to full recognition of unbilled revenues. It should be understood that the preferability of one acceptable method of revenue recognition over another has not been addressed in any authoritative accounting literature and in arriving at our opinion expressed below, we have relied on management's business planning and judgment. Based on our discussions with management and the stated reasons for the change, we believe that such change represents, in your circumstances, the adoption of a preferable alternative accounting principle for revenue recognition in conformity with Accounting Principles Board Opinion No. 20. PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP New York, New York February 2, 1995

<TABLE> <CAPTION> E-2 Monongahela Power Company Incorporation Documents by Reference <S> <C> <C> 3.1 Charter of the Company, Form S-3, 33-51301, exh. 4(a) as amended and Form 8-K of the Company (1-5164) dated May 12, 1994, exh. 3.1 3.2 Code of Regulations, Form 10-Q of the Company as amended (1-5164), September 1994, exh. (a)(2) 4 Indenture, dated as of S 2-5819, exh. 7(f) August 1, 1945, and S 2-8782, exh. 7(f)(1) certain Supplemental S 2-8881, exh. 7(b) Indentures of the S 2-9355, exh. 4(h)(1) Company defining rights S 2-9979, exh. 4(h)(1) of security holders.* S 2-10548, exh. 4(b) S 2-14763, exh. 2(b)(i) S 2-24404, exh. 2(c); S 2-26806, exh. 4(d); Forms 8-K of the Company (1-268-2) dated August 8, 1989, November 21, 1991, June 4, 1992, July 15, 1992, September 1, 1992 and April 29, 1993 * There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the Commission on its request with copies of such Supplemental Indentures. 10 Employment Contract Form 8-K of the Company of Jay S. Pifer (1-5164) dated February 15, 1995 exh. 10.1 12 Computation of ratio of earnings to fixed charges 18 Letter re: Change in Accounting Principles 21 Subsidiaries: Monongahela Power Company has a 27% equity ownership in Allegheny Generating Company, incorporated in Virginia; and a 25% equity ownership in Allegheny Pittsburgh Coal Company, incorporated in Pennsylvania. 23 Consent of Independent Accountants See page 62 herein. 24 Powers of Attorney See pages 63-65 herein. 27 Financial Data Schedules </TABLE>

EXHIBIT 12 COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES For Year Ended December 31, 1994 (Dollar Amounts in Thousands) Monongahela Power Company Earnings: Income before cumulative effect of accounting change $ 59,936 Fixed charges (see below) 38,871 Income taxes 30,649 Total earnings $129,456 Fixed Charges: Interest on long-term debt $ 35,187 Other interest 2,969 Estimated interest component of rentals 715 Total fixed charges $ 38,871 Ratio of Earnings to Fixed Charges 3.33

Exhibit 18 To the Board of Directors Monongahela Power Company We have audited the financial statements included in the Annual Report on Form 10-K of Monongahela Power Company (the "Corporation") for the year ended December 31, 1994 and issued our report thereon dated February 2, 1995. Note A to the financial statements describes a change in the Corporation's method of accounting for revenues from a cycle billing basis to full recognition of unbilled revenues. It should be understood that the preferability of one acceptable method of revenue recognition over another has not been addressed in any authoritative accounting literature and in arriving at our opinion expressed below, we have relied on management's business planning and judgment. Based on our discussions with management and the stated reasons for the change, we believe that such change represents, in your circumstances, the adoption of a preferable alternative accounting principle for revenue recognition in conformity with Accounting Principles Board Opinion No. 20. PRICE WATERHOUSE LLP New York, New York February 2, 1995

<TABLE> <CAPTION> E-3 The Potomac Edison Company Incorporation Documents by Reference <S> <C> <C> 3.1 Charter of the Company, Form 10-Q of the Company as amended (1-3376-2), September 1993, exh. (a)3 3.2 By-laws of the Company, Form 10-Q of the Company as amended (1-3376-2), June 1990, exh. (a)3 4 Indenture, dated as of S 2-5473, exh. 7(b); Form October 1, 1944, and S-3, 33-51305, exh. 4(d) certain Supplemental Forms 8-K of the Company Indentures of the (1-3376-2) dated June 14, Company defining rights 1989, June 25, 1990, of security holders* August 21, 1991, December 11, 1991, December 15, 1992, February 17, 1993, March 30, 1993 and June 22, 1994 * There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the Commission on its request with copies of such Supplemental Indentures. 10 Employment Contract Form 8-K of the Company of Jay S. Pifer (1-3376-2) dated February 15, 1995 exh. 10.1 12 Computation of ratio of earnings to fixed charges 18 Letter re: Change in Accounting Principles 21 Subsidiaries: The Potomac Edison Company has a 28% equity ownership in Allegheny Generating Company, incorporated in Virginia and a 25% equity ownership in Allegheny Pittsburgh Coal Company, incorporated in Pennsylvania. 23 Consent of Independent See page 62 herein. Accountants 24 Powers of Attorney See pages 63-65 herein. 27 Financial Data Schedules </TABLE>

EXHIBIT 12 COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES For Year Ended December 31, 1994 (Dollar Amounts in Thousands) The Potomac Edison Company Earnings: Income before cumulative effect of accounting change $ 81,983 Fixed charges (see below) 47,329 Income taxes 34,339 Total earnings $163,651 Fixed Charges: Interest on long-term debt $ 44,706 Other interest 1,750 Estimated interest component of rentals 873 Total fixed charges $ 47,329 Ratio of Earnings to Fixed Charges 3.46

Exhibit 18 To the Board of Directors The Potomac Edison Company We have audited the financial statements included in the Annual Report on Form 10-K of The Potomac Edison Company (the "Corporation") for the year ended December 31, 1994 and issued our report thereon dated February 2, 1995. Note A to the financial statements describes a change in the Corporation's method of accounting for revenues from a cycle billing basis to full recognition of unbilled revenues. It should be understood that the preferability of one acceptable method of revenue recognition over another has not been addressed in any authoritative accounting literature and in arriving at our opinion expressed below, we have relied on management's business planning and judgment. Based on our discussions with management and the stated reasons for the change, we believe that such change represents, in your circumstances, the adoption of a preferable alternative accounting principle for revenue recognition in conformity with Accounting Principles Board Opinion No. 20. PRICE WATERHOUSE New York, New York February 2, 1995

<TABLE> <CAPTION> E-4 West Penn Power Company Incorporation Documents by Reference <S> <C> <C> 3.1 Charter of the Company, Form S-3, 33-51303, exh. 4(a) as amended 3.2 By-laws of the Company, Form 8-K of the Company as amended (1-255-2), dated June 9, 1993, exh. (a)(3) 4 Indenture, dated as of S-3, 33-51303, exh. 4(d) March 1, 1916, and certain S 2-1835, exh. B(1), B(6) Supplemental Indentures of S 2-4099, exh. B(6), B(7) the Company defining rights S 2-4322, exh. B(5) of security holders.* S 2-5362, exh. B(2), B(5) S 2-7422, exh. 7(c), 7(i) S 2-7840, exh. 7(d), 7(k) S 2-8782, exh. 7(e) (1) S 2-9477, exh. 4(c), 4(d) S 2-10802, exh. 4(b), 4(c) S 2-13400, exh. 2(c), 2(d) Form 10-Q of the Company (1-255-2), June 1980, exh. D Forms 8-K of the Company (1-255-2) dated June 1989, February 1991, December 1991, August 13, 1993, September 15, 1992, June 9, 1993 and June 1993 * There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the Commission on its request with copies of such Supplemental Indentures. 10 Employment Contract Form 8-K of the Company of Jay S. Pifer (1-255-2) dated February 15, 1995 exh. 10.1 12 Computation of ratio of earnings to fixed charges 18 Letter re: Change in Accounting Principles 21 Subsidiaries: West Penn Power Company has a 45% equity ownership in Allegheny Generating Company, incorporated in Virginia; a 50% equity ownership in Allegheny Pittsburgh Coal Company, incorporated in Pennsylvania; and a 100% equity ownership in West Virginia Power and Transmission Company, incorporated in West Virginia, which owns a 100% equity ownership in West Penn West Virginia Water Power Company, incorporated in Pennsylvania. 23 Consent of Independent See page 62 herein. Accountants 24 Powers of Attorney See pages 63-65 herein. 27 Financial Data Schedules </TABLE>

EXHIBIT 12 COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES For Year Ended December 31, 1994 (Dollar Amounts in Thousands) West Penn Power Company Earnings: Income before cumulative effect of accounting change $101,015 Fixed charges (see below) 61,583 Income taxes 47,085 Total earnings $209,683 Fixed Charges: Interest on long-term debt $ 58,102 Other interest 2,172 Estimated interest component of rentals 1,309 Total fixed charges $ 61,583 Ratio of Earnings to Fixed Charges 3.40

Exhibit 18 To the Board of Directors West Penn Power Company We have audited the consolidated financial statements included in the Annual Report on Form 10-K of West Penn Power Company (the "Corporation") for the year ended December 31, 1994 and issued our report thereon dated February 2, 1995. Note A to the consolidated financial statements describes a change in the Corporation's method of accounting for revenues from a cycle billing basis to full recognition of unbilled revenues. It should be understood that the preferability of one acceptable method of revenue recognition over another has not been addressed in any authoritative accounting literature and in arriving at our opinion expressed below, we have relied on management's business planning and judgment. Based on our discussions with management and the stated reasons for the change, we believe that such change represents, in your circumstances, the adoption of a preferable alternative accounting principle for revenue recognition in conformity with Accounting Principles Board Opinion No. 20. PRICE WATERHOUSE New York, New York February 2, 1995

E-5 Allegheny Generating Company Documents 3.1(a) Charter of the Company, as amended* 3.1(b) Certificate of Amendment to Charter, effective July 14, 1989.** 3.2 By-laws of the Company, as amended* 4 Indenture, dated as of December 1, 1986, and Supplemental Indenture, dated as of December 15, 1988, of the Company defining rights of security holders.*** 10.1 APS Power Agreement-Bath County Pumped Storage Project, as amended, dated as of August 14, 1981, among Monongahela Power Company, West Penn Power Company, and The Potomac Edison Company and Allegheny Generating Company.* 10.2 Operating Agreement, dated as of June 17, 1981, among Virginia Electric and Power Company, Allegheny Generating Company, Monongahela Power Company, West Penn Power Company and The Potomac Edison Company.* 10.3 Equity Agreement, dated June 17, 1981, between and among Allegheny Generating Company, Monongahela Power Company, West Penn Power Company and The Potomac Edison Company.* 10.4 United States of America Before The Federal Energy Regulatory Commission, Allegheny Generating Company, Docket No. ER84-504-000, Settlement Agreement effective October 1, 1985.* 12 Computation of ratio of earnings to fixed charges 23 Consent of Independent See page 62 herein. Accountants 24 Powers of Attorney See pages 63-65 herein. 27 Financial Data Schedules * Incorporated by reference to the designated exhibit to AGC's registration statement on Form 10, File No. 0-14688. ** Incorporated by reference to Form 10-Q of the Company (0-14688) for June 1989, exh. (a). *** Incorporated by reference to Forms 8-K of the Company (0-14688) for December 1986, exh. 4(A), and December 1988, exh. 4.1.

EXHIBIT 12 COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES For Year Ended December 31, 1994 (Dollar Amounts in Thousands) Allegheny Generating Company Earnings: Net Income $ 29,717 Fixed charges (see below) 17,809 Income taxes 14,743 Total earnings $ 62,269 Fixed Charges: Interest on long-term debt $ 16,863 Other interest 946 Estimated interest component of rentals ---- Total fixed charges $ 17,809 Ratio of Earnings to Fixed Charges 3.50

WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.

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