Annual Report (Form 10-K), fiscal year 1994

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.
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:
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.
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.



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.

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.

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.
PART II
ITEM 5.

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:
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.

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

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