ITEM 1. BUSINESS
Allegheny Power System, Inc. (APS), incorporated in Maryland in 1925, is an electric utility holding company which owns directly and indirectly various regulated subsidiaries (collectively, Allegheny Power), and a nonutility subsidiary, AYP Capital, Inc. (AYP Capital). 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, 1995, Allegheny Power had 5,905 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 347,600 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, 1995, Monongahela had 1,921 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 368,800 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, 1995, Potomac Edison had 1,097 employees. 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.
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 660,000 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, 1995, West Penn had 1,981 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).
APSC, incorporated in Maryland in 1963, is a wholly owned subsidiary of APS which provides various technical, engineering, accounting, administrative, purchasing, computing, managerial, operational, and legal services to the Subsidiaries and AYP Capital at cost. On December 31, 1995, APSC had 906 employees.
AYP Capital, incorporated in Delaware in 1994, is a 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. AYP Capital has no employees. However, as of February 1, 1996, 10 APSC employees are dedicated to AYP Capital activities on a full-time basis. Other APSC employees provide services to AYP Capital as required. AYP Capital reimburses APSC for the use of its employees. APS' total investment in AYP Capital was $1.8 million as of December 31, 1995. APS is currently committed to invest up to an additional $10 million in AYP Capital to fund AYP Capital's investment in two limited partnerships. AYP Capital has agreed to purchase a 50% interest (276 MW) in a generating unit for approximately $170 million. AYP Capital has also formed a limited liability company (APS Cogenex) with EUA Cogenex, a nonutility subsidiary of Eastern Utilities Associates. (See ITEM 1. COMPETITION, for a further description of AYP Capital's activities.)
Allegheny Power has in the past and may in the future 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 (SO[2]) and nitrogen oxides (NO[x]).
Additional concerns include proposals to restructure and to deregulate portions of the industry and to 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. CAPITAL REQUIREMENTS AND FINANCING, RATE MATTERS, and ENVIRONMENTAL MATTERS for information concerning the effect on the Subsidiaries of the CAAA.)
COMPETITION
Competitive forces within the electric utility industry continued to increase in 1995 due to a variety of influences including legislative and regulatory proceedings. Difficult questions including stranded investment recovery, responsibility for service and service reliability, the obligation to serve, recovery of environmental and other social costs, tax implications, and the effect of competition on all classes of customers are being debated. Large industrial users of electricity remain the principal nongovernmental advocates of increased competition, including retail wheeling. In response to the competitive environment that has evolved following the passage of the National Energy Policy Act of 1992 (EPACT), Allegheny Power has developed, and is continuing to develop, a number of strategies to retain and continue to serve its existing customers and to expand its customer base.
In 1995, Allegheny Power began to restructure its operations in an effort to control costs by making more efficient use of resources and streamlining processes. Although certain initiatives have been completed, the process is continuing. (See ITEM 1. RESTRUCTURING for a description of the Allegheny Power reorganization efforts.) In addition, Allegheny Power established and staffed in 1995 a Major Accounts Program to enhance the working relationship between Allegheny Power and its largest customers. In- depth knowledge from the Major Accounts Program is already providing opportunities for potential business ventures and is enhancing Allegheny Power's reputation as an efficient, low cost provider of energy services.
Various states in the Allegheny Power service area have initiated investigations concerning competition, but, except for Maryland, definitive conclusions have not been reached. (See ITEM 1. REGULATION for a discussion of the competitive investigations in Maryland, Ohio, Pennsylvania, and Virginia.)
To help meet the challenges of the new competitive environment and the new opportunities presented in EPACT, AYP Capital was formed in 1994. Its purpose is to pursue and develop new opportunities in unregulated markets to strengthen the long-term competitiveness and profitability of APS. During 1995, AYP Capital funded several investments. They include EnviroTech Investment Fund I, L.P. (EnviroTech), a limited partnership formed to invest in emerging electrotechnologies that promote the efficient use of electricity
and improve the environment. AYP Capital has committed to invest up to $5 million in EnviroTech. AYP Capital has also invested in the Latin American Energy and Electricity Fund I, L.P. (FONDELEC), a limited partnership formed to invest in and develop electric energy opportunities in Latin America. AYP Capital has committed to invest up to $5 million in FONDELEC. Both EnviroTech and FONDELEC may offer AYP Capital opportunities to identify investments in which AYP Capital may coinvest, in excess of its capital commitment in each limited partnership.
AYP Capital is also developing other energy-related service businesses. AYP Capital offers engineering consulting services and project management for transmission and distribution facilities. AYP Capital has also invested in APS Cogenex, a limited liability company formed jointly with EUA Cogenex, a nonutility subsidiary of Eastern Utilities Associates. APS Cogenex provides energy services to improve the energy efficiency of consumer facilities in the five states in which Allegheny Power provides electric service, plus the District of Columbia. AYP Capital intends to provide financing to consumers that undertake capital improvements necessary to achieve energy efficiency.
AYP Capital is moving into the wholesale unregulated power generation market with its agreement to purchase Duquesne Light Company's (Duquesne) 50% interest in Unit No. 1 of the Fort Martin Power Station for about $170 million. AYP Capital intends to utilize its share of the unit as an exempt wholesale generator and sell the output at market price. Obtaining the necessary regulatory approvals will likely take several months. AYP Capital expects a closing in 1996. AYP Capital is also pursuing other opportunities.
In addition, management continues to explore methods of marketing and pricing its core services - electric energy and the transmission thereof - in new and competitive ways, such as bulk sales of each type of service to nonaffiliates, incentive pricing to traditional utility customers, and repackaging of services in nontraditional ways. It is also attempting to reduce costs, particularly capital expenditures, to position Allegheny Power in a more competitive mode.
Fully meeting challenges in the emerging competitive environment will be difficult unless certain outmoded and anti-competitive laws, specifically the Public Utility Holding Company Act of 1935 (PUHCA) and Section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA), are repealed or significantly revised.
Allegheny Power is a member of the PURPA Reform Group, an ad hoc group of utilities seeking repeal or reform of PURPA on the grounds that it is obsolete, anticompetitive and it results in utility customers paying above- market prices for power. This Group supports legislation which has been introduced in both houses of Congress to repeal or reform PURPA. (See ITEM 3. LEGAL PROCEEDINGS for information concerning PURPA-related litigation.)
Allegheny Power, along with the other registered electric public utility holding companies under PUHCA, advocates repeal of PUHCA. PUHCA prevents or significantly disadvantages regulated holding companies from
diversifying into utility-related or nonutility businesses within or outside their service territories, except under limited circumstances. Exempt companies as well as other competitors, on the other hand, can diversify into other types of businesses with generally no greater limitations than any other domestic company. Legislation has been introduced in Congress to repeal PUHCA and grant utility oversight responsibility to the Federal Energy Regulatory Commission (FERC). The Securities and Exchange Commission (SEC) has also recommended repeal of PUHCA. If the problems with PUHCA are not resolved through legislation, restructuring of Allegheny Power to reduce or eliminate the effect of PUHCA is an alternative.
RESTRUCTURING
In the late 1960's and early 1970's, Allegheny Power was one of the first public utility holding company systems to establish a service company, APSC, to increase efficiencies and savings through centralization. APSC was organized into two groups - Bulk Power Supply (BPS) and Central Services. That structure served Allegheny Power and its customers well and is one of the reasons that its electric rates are among the lowest in the region.
The competitive environment emerging in the electric utility industry, however, is requiring Allegheny Power to restructure many of its functions to strengthen its competitive position and improve its cost structure.
The restructuring process is initiated by core teams consisting of selected employees chosen to evaluate existing processes and recommend changes. The core teams receive guidance from review groups, senior management, and consultants. Recommendations are implemented following acceptance by senior management and, in some cases, the Board of Directors.
BPS has been reengineered from its functional groups - Planning, Engineering, Construction, and Operating - to Generation, Transmission, and Planning and Compliance Business Units. Reengineering of the Transmission and Planning and Compliance Business Units has been completed, and process redesign and restructuring now under way in the power stations will complete the reengineering of the Generation Business Unit.
The Business Unit concept adopted in BPS and planned for other parts of Allegheny Power is designed to improve Allegheny Power's ability to compete and to respond to customers. The Business Unit organization is structured to make extensive use of teams including individuals from other Business Units or from other areas of Allegheny Power.
The Generation Business Unit will be responsible for ensuring that adequate generation is available to serve the native load customers of Allegheny Power by employing Allegheny Power generating facilities and third- party generation obtained through its marketing efforts. Its primary responsibilities include ensuring the cost-effective operation and maintenance of Allegheny Power's generating units and providing the most economic mix of generation by available Allegheny Power generating units and off-system purchases and sales.
The Transmission Business Unit will be responsible for ensuring that adequate high voltage network facilities are available and on line to convey power produced from the power production operations run by, or procured by, the Generation Business Unit to serve native load and to engage in wholesale transmission sales to nonaffiliates. It will also engage in marketing efforts for sales of bundled and unbundled transmission services to nonaffiliates and will be responsible for accommodating requests for transmission service submitted by nonaffiliates who qualify as customers for that service under federal regulations. Finally, the Transmission Business Unit will be responsible for maintaining the optimal economic balance on a real time basis between native customer load and the output of the generation resources supplied by the Generation Business Unit.
The Planning and Compliance Business Unit will provide strategic resource planning and engineering analysis of alternate transmission and generation resource options, environmental and regulatory issues management, environmental compliance oversight, research and development, and emerging technology development for Allegheny Power. Much of the work of this Business Unit will be accomplished through multi-functional, cross-organizational teams yielding a more balanced, multiple perspective solution to strategic problems.
Reorganization in the Operating Subsidiaries began early in 1995 and has resulted in a single management team. There are now 18 operating divisions compared with 23 at the beginning of 1995, and functions such as engineering, construction, construction services, as well as marketing functions have been consolidated. An effort is currently under way to redesign all the processes in the Operating Subsidiaries.
In 1995, the Engineering and Construction Departments (E&C) of the Operating Subsidiaries completed a partial reorganization in conjunction with the restructuring of BPS. Some functions in E&C were transferred to the new Business Units, while functions in BPS involving land management, communications, standards, and nonnetwork planning were transferred to E&C. The Construction Services Division of E&C consolidated its General Stores function into two locations and developed a Material Transportation System to serve all locations of the Operating Subsidiaries. Repair and testing of electrical equipment were consolidated. The balance of E&C is undergoing reengineering as part of the core team evaluation of the Operating Subsidiaries.
Corporate Services, including Accounting, Finance, Information Services, Human Resources, and Legal, as well as other support functions, are being reengineered along with other functions in the internal supply chain for materials and services. The Corporate Services and supply chain restructuring will help to eliminate internal barriers to meeting external competition. As part of the restructuring, Allegheny Power consolidated two data processing centers, which resulted in the closing of one center.
As of January 1, 1996, APS and APSC began using the common name, "Allegheny Power." The Operating Subsidiaries will also begin using the "Allegheny Power" name by September 1996, to reflect Allegheny Power's unified
mission and one-company concept. For legal purposes, APS and the Subsidiaries will retain their formal names.
By late 1996, the corporate headquarters of Allegheny Power will move from New York City to Washington County, Maryland. The move will situate Allegheny Power's headquarters in the service territory of the Operating Subsidiaries.
It is currently anticipated that all of the reengineering now under way will be completed by the end of 1996, although Allegheny Power will continue to identify ways to increase efficiencies.
Downsizing was not a specific goal of Allegheny Power's reorganization and reengineering efforts, but as a consequence of process redesign and elimination of duplicate positions, approximately 200 employees have been placed in a staffing force thus far. Employees in the staffing force on January 1, 1996 were offered a separation package. Employees who did not elect to accept the separation package and who are not placed in a regular employment position will be laid-off at the end of 12 months.
In addition, it is currently estimated that about 130 fewer employees will be required in the power station work force by the end of 1997. Employee reductions are also likely to result from reengineering in the Operating Subsidiaries and support functions.
SALES
In 1995, consolidated kilowatt-hour (kWh) sales to the Operating Subsidiaries' retail customers increased 3.9% from those of 1994 as a result of increases of 3.0%, 4.7%, and 4.2% in residential, commercial, and industrial sales, respectively. The increased kWh sales in 1995 reflect both growth in number of customers and higher use. Consolidated revenues from residential, commercial, and industrial sales increased 7.3%, 7.5%, and 5.8%, respectively, primarily because of rate increases (See ITEM 1. RATE MATTERS) and increased kWh sales.
Consolidated kWh sales to and revenues from nonaffiliates under buy/resale agreements increased 36.3% and 16.1%, respectively, due primarily to increased sales of power purchased from nonaffiliated utilities and power brokers, and transmitted through our system to others. Consolidated sales under the Standard Transmission Service Tariff increased from 0.5 billion kWh to 1.5 billion kWh and revenues increased from $3.2 million to $5.6 million.
Allegheny Power's all-time peak load of 7,500 MW, which was higher than that forecast, occurred on February 5, 1996. The peak load in 1995 and 1994 was 7,280 MW and 7,153 MW, respectively. The average System load (yearly net power supply divided by number of hours in the year) was 4,969 MW and 4,776 MW in 1995 and 1994, respectively. More information concerning sales may be found in the statistical sections. (See also ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.)
Consolidated electric operating revenues for 1995 were derived as follows: Pennsylvania, 44.6%; West Virginia, 28.3%; Maryland, 20.6%; Virginia, 5.0%; Ohio, 1.5% (residential, 35.0%; commercial, 18.7%; industrial, 29.1%; nonaffiliated utilities, 14.5%; and other, 2.7%). The following percentages of such revenues were derived from these industries: iron and steel, 6.2%; fabricated products, 3.4%; chemicals, 3.3%; aluminum and other nonferrous metals, 3.1%; coal mines, 3.0%; cement, 1.7%; and all other industries, 8.4%. Revenues from each of 19 industrial customers exceeded $5 million, including one coal customer of both Monongahela and West Penn providing total revenues exceeding $23 million, three steel customers providing revenues exceeding $31 million each, and one aluminum customer providing revenues exceeding $67 million.
During 1995, Monongahela's kWh sales to retail customers increased 4.5% as a result of increases of 5.0%, 6.5%, and 3.5% in residential, commercial, and industrial sales, respectively. Revenues from residential, commercial and industrial customers increased 9.5%, 7.1%, and 5.1%, respectively, and revenues from kWh sales to affiliated and nonaffiliated utilities increased 3.9%. Monongahela's all-time peak load of 1,825 MW occurred on August 17, 1995.
Monongahela's electric operating revenues were derived as follows: West Virginia, 94.6% and Ohio, 5.4% (residential, 28.9%; commercial, 17.2%; industrial, 29.4%; nonaffiliated utilities, 12.6%; and other, 11.9%). Revenues from each of five industrial customers exceeded $11 million, including one steel customer providing revenues exceeding $31 million and one coal customer providing revenues exceeding $20 million.
During 1995, Potomac Edison's kWh sales to retail customers increased 3.3% as a result of increases of 3.9%, 3.6%, and 2.7% in residential, commercial, and industrial sales, respectively. Revenues from such customers increased 7.0%, 6.7%, and 3.0%, respectively, and revenues from kWh sales to affiliated and nonaffiliated utilities increased 17.1%. 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, 66.9%; West Virginia 16.9% and Virginia, 16.2%; (residential, 38.7%; commercial, 17.7%; industrial, 24.5%; nonaffiliated utilities, 15.4%; and other, 3.7%). Revenues from one industrial customer, the Eastalco aluminum reduction plant near Frederick, Maryland, amounted to $67.4 million (8.2% 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 $20.3 million in 1995. This 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 1995, West Penn's kWh sales to retail customers increased 4.0% as a result of increases of 1.4%, 4.4% and 5.8% in residential, commercial, and industrial sales, respectively. Revenues from residential, commercial, and industrial customers increased 6.5%, 8.2%, and 7.9%, respectively, and revenues from kWh sales to affiliated and nonaffiliated utilities increased
17.6%. West Penn's all-time peak load of 3,242 MW occurred on February 5, 1996.
West Penn's electric operating revenues were derived as follows: Pennsylvania, 100% (residential, 32.7%; commercial, 18.3%; industrial, 29.1%; nonaffiliated utilities, 13.7%; and other, 6.2%). Revenues from each of four industrial customers exceeded $11 million, including two steel customers providing revenues exceeding $36 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 very 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 may be willing to sell at prices only slightly in excess of variable costs. At the same time, the Operating Subsidiaries are experiencing higher costs due to compliance with the CAAA and purchases from PURPA projects. (See page 12 for a discussion of PURPA projects, and ITEM 3. LEGAL PROCEEDINGS for a description of litigation and regulatory proceedings concerning PURPA capacity.)
In 1995, the Operating Subsidiaries provided approximately 15.4 billion kWh of energy to nonaffiliated companies, of which 0.78 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 nonaffiliates. The transaction began in mid-1987 and will continue through 2005, unless terminated earlier.
Sales to nonaffiliated companies vary with the needs of those companies for capacity and/or economic replacement power; the availability of generating facilities and excess power, fuel, and regional transmission facilities; and the availability and price of competitive sources of power. Although increases occurred in both sales of power purchased from and transmission services with nonaffiliates in 1995, sales of power generated by Allegheny Power decreased relative to 1994 primarily because of stagnant demand, increased Operating Subsidiaries' native load, and increased number of and willingness of other suppliers to make sales at lower prices. Further decreases in sales by Allegheny Power of power generated from rate-based assets to nonaffiliates are expected in 1996 and beyond. For 1995, substantially all of the benefits of power and transmission service sales to nonaffiliates were 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, 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. Negotiations are currently under way to reach an agreement on an amount of diversity exchange beyond February 1998. 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 which will continue through February 1999 and may be extended beyond that date, 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 distribution facilities leased from Tarentum under a 30-year lease agreement terminating in 1996. In June 1993, Tarentum, which in that year provided 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 and re-enter the retail electric business. The termination of the lease agreement and resulting transfer and sale by West Penn of electric facilities installed by West Penn will result in Tarentum becoming a municipal customer which will purchase electricity on a wholesale basis from West Penn or another supplier. Tarentum has agreed to purchase wholesale electricity from West Penn until at least March 16, 1999. West Penn's sale of electric facilities and discontinuance of its electric service to customers in Tarentum will require Pennsylvania Public Utility Commission (Pennsylvania PUC) approval.
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. In 1995, the FERC continued to develop new policies and procedures to implement EPACT and requested comments on the following: a Notice of Proposed Rulemaking on open access nondiscriminatory transmission services (Mega-NOPR), a Supplemental Notice of Proposed Rulemaking on recovery of stranded costs, a Request for Comments and subsequent Notice of Proposed Rulemaking on Real-Time Information Networks and Standards of Conduct, and an Inquiry concerning alternative power pooling arrangements. Of particular significance to public utilities, on March 29, 1995, the FERC issued the Mega-NOPR with the stated intent of stimulating wholesale (sale for resale) competition among electric utilities and nonregulated electricity generators. The Mega-NOPR encourages wholesale competition by requiring utilities to allow their transmission facilities to be used by sellers or buyers of wholesale power without undue discrimination, as long as sufficient transmission capacity is available to provide service without impairing reliability. To meet the objective of providing nondiscriminatory or comparable wholesale transmission services, the Mega- NOPR, if adopted as proposed, requires that utilities functionally unbundle. Accordingly, the proposed rule if adopted will require separation of public utility systems' operations and marketing functions and will require that wholesale transmission services purchased by the transmission owner must be taken under its filed open access tariffs. In addition, the Mega-NOPR
proposes pro forma open access tariffs containing the terms and conditions for these transmission services. The Mega-NOPR also states that electric utilities would be able to collect stranded costs (costs of facilities made uneconomic by wholesale transmission access) and that it is up to the states to decide if retail wheeling should be adopted and, if so, to address retail stranded costs. FERC has received public input to the Mega-NOPR and is currently reviewing that information before issuing a final rule. (See ITEM 1. REGULATION for a further discussion of the Mega-NOPR.)
In response to both the Mega-NOPR and the continuing evolution of the wholesale power and transmission service markets, Allegheny Power implemented reorganization of its existing wholesale marketing function into separate transmission and generation marketing functions. (See ITEM 1. RESTRUCTURING for further discussion of the restructuring of Bulk Power Supply.) Through rulings issued in various cases, the FERC 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 Allegheny Power's transmission facilities.)
Through 1995, the Operating Subsidiaries provided wholesale transmission services under their FERC-approved Standard Transmission Service Tariff. The tariff stipulated that such service was subordinate in priority to native load and reliability requirements of interconnected systems to avoid adverse effects on regional and Operating Subsidiaries' reliability. Transmission services requiring special arrangements or long-term commitments were provided through specially negotiated, mutually acceptable bilateral agreements that were consistent with and accommodated the Standard Transmission Service Tariff. Effective in 1996 and consistent with the intentions of the FERC under the Mega-NOPR, Allegheny Power submitted a filing to FERC of a set of two new transmission service tariffs which qualify as open access filings pursuant to the Mega-NOPR. As of December 6, 1995, the FERC accepted for filing a Network Transmission Service Tariff and a Point-to-Point Transmission Service Tariff under which the Operating Subsidiaries will sell comparable open access transmission services to eligible wholesale customers. Customers may choose from a range of services that extend from broad use of the transmission network on a firm basis for the life of a customer facility to a fully interruptible energy only service that is available for a one-hour term. The tariffs were accepted subject to modification pending the outcome of the Final Rule in the Mega-NOPR proceeding. The FERC acceptance for filing set the tariffs for hearing during the summer of 1996; in the interim, the Operating Subsidiaries may sell transmission services under the tariffs, subject to refund. With this filing, the need for and applicability of the Standard Transmission Service Tariff was eliminated for new service transactions. Substantially all of the revenues from transmission service sales now arise from transactions with customers located outside the service territory of the Operating Subsidiaries and are passed through to retail customers. As a result, they presently have little effect on net income. In addition, the Operating Subsidiaries have a Standard Generation Service Rate Schedule tariff on file with and accepted by the FERC under which the Operating Subsidiaries make available bundled, nonfirm generation services with associated System transmission services to any customer who executes an
agreement under such tariff. Revenues from this tariff are also passed through to retail customers.
In conjunction with the Mega-NOPR, on December 16, 1995, the FERC issued a notice of proposed rulemaking on Real-Time Information Networks and Standards of Conduct to ensure the separation of service directed by the functional unbundling of wholesale services required by the Mega-NOPR and to assure that all buyers and sellers of transmission services will have equal and timely access to the information needed to transact business. Allegheny Power commented on this proposed rulemaking.
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 consistent with PURPA and ordered by appropriate state commissions. Allegheny Power's total generating capacity includes 299 MW of on-line PURPA capacity. Payments for PURPA capacity and energy in 1995 totaled approximately $129 million at an average cost to Allegheny Power of 5.5 cents/kWh, as compared to Allegheny Power's own generating cost of about 3 cents/kWh. Allegheny Power projects an additional 180 MW (Warrior Run) of PURPA capacity to come on-line in 1999. It is expected that the Warrior Run project will result in increased costs for Potomac Edison's customers. Eighty MW (Burgettstown) of PURPA capacity has been removed from Allegheny Power's projections due to a PURPA project that expired when the project failed to meet its financing closing deadline. (See ITEM 3. LEGAL PROCEEDINGS for a description of the Washington Power lawsuit filed by the Burgettstown developer against West Penn and APS concerning this project.) Lapsed purchase agreements totaling 203 MW (Burgettstown, Shannopin, and Milesburg) and other PURPA related complaints totaling 470 MW (MidAtlantic and South River) are the subject of ongoing litigation and are not included in Allegheny Power's current planning strategy. (See ITEM 3. LEGAL PROCEEDINGS concerning an agreement to resovle the Shannopin lawsuit and for a description of litigation and regulatory proceedings in Pennsylvania and West Virginia.)
ELECTRIC FACILITIES
The following table shows Allegheny Power's December 31, 1995, generating capacity, based on the maximum monthly normal seasonal operating capacity of each unit. Allegheny Power's 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 Allegheny Power's steam stations shown on the following page, based on generating capacity at December 31, 1995, was about
25.6 years. In 1995, their average heat rate was 9,970 Btu's/kWh, and their availability factor was 82.3%.
(a) Excludes 207 MW of West Penn oil-fired capacity at Springdale Power Station and 77 MW of the total MW at Mitchell Power Station, which were placed on cold reserve status as of June 1, 1983. Current plans call for the reactivation of these units in about five years. On December 31, 1994, 82 MW of the total MW at Mitchell Power Station were reactivated.
(b) Where more than one year is listed as a commencement date for a particular source, the dates refer to the years in which operations commenced for the different units at that source.
(c) Capacity entitlement through ownership of AGC, 27%, 28% and 45% by Monongahela, Potomac Edison and West Penn, respectively.
(d) The FERC issued a new license with a 30-year term for Lake Lynn on December 27, 1994. Certain terms of said license are being appealed but do not affect its validity. Potomac Edison's license for hydroelectric facilities Dam #4 and Dam #5 will expire in 2003. Potomac Edison has received 30-year licenses, effective January 1994, for the Shenandoah, Warren, Luray and Newport projects. The FERC accepted Potomac Edison's surrender of the license for the Harper's Ferry Dam No. 3 and issued an order effective October 1994.
(e) Nonutility generating capacity available through state utility commission approved arrangements pursuant to PURPA.
(f) The Warrior Run project of 180 MW has completed its financial closing, is under construction, and is planned to begin providing capacity and energy to Potomac Edison in 1999.
ALLEGHENY POWER MAP
The Allegheny Power Map (Map), which has been omitted, provides a broad illustration of the names and approximate locations of Allegheny Power'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 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 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 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 capcity 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, 1995:
(a) Allegheny Power has a total of 5,831 miles of underground distribution lines.
(b) The substations have an aggregate transformer capacity of 39,207,919 kilovoltamperes.
(c) Total Bath County transmission lines, of which AGC owns an undivided 40% interest and Virginia Power owns the remainder.
Allegheny Power 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 operated near reliability limits because of frequent periods of heavy power flows, predominantly in a west-to-east direction. In 1994 and early 1995, use of the transmission system in aggregate declined and the west- to-east power flows decreased to more comfortable levels. However, in the later months of 1995, west-to-east transfers began to increase, although not to the critical levels commonly seen earlier in the decade. If transfers and customer load continue to increase, along with coincident parallel flows, interregional EHV transmission facilities, including Allegheny Power facilities, will again operate nearer to reliability limits, at which time restrictions on transfers may 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 Allegheny Power's transmission facilities may add to heavy power flows on Allegheny Power's facilities.
The Operating Subsidiaries have, to date, provided managed contractual access to Allegheny Power's transmission facilities via the provisions of their Standard Transmission Service Tariff, or the terms and conditions of bilateral contracts. As described earlier, for new agreements starting in 1996, managed access will also be governed by the provisions of the Allegheny Power open access tariffs recently accepted provisionally by FERC.
RESEARCH AND DEVELOPMENT
The Operating Subsidiaries spent $9.0 million, $7.7 million, and $4.6 million in 1995, 1994, and 1993, respectively, for research programs. Of these amounts, $6.2 million, $5.9 million, and $3.2 million were for Electric Power Research Institute (EPRI) dues in 1995, 1994, and 1993, respectively. EPRI is an industry-sponsored research and development institution. The Operating Subsidiaries plan to spend approximately $8.5 million for research in 1996, with EPRI dues representing $5.5 million of that total.
Independent research conducted by the 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.
Research is also being directed to help address major issues facing Allegheny Power including electric and magnetic field (EMF) assessment of employee exposure within the work environment, waste disposal and discharges, greenhouse gases, client-server information system prospects, Internet, renewable resources, fuel cells, new combustion turbines and cogeneration technologies. In addition, there is continuing evaluation of technical proposals from outside sources and monitoring of developments in industry- related literature, law, litigation, and standards.
As Allegheny Power continues in its effort to comply with the NOx control requirements of the CAAA, it has entered into a collaborative effort coordinated by EPRI to gain a greater understanding of the formation of ground level ozone and how measures to control NOx and volatile organic compounds affect ozone formation. The North American Research Strategy for Tropospheric Ozone-Northeast is focused on this effort in the Ozone Transport Region (See page 28). With reference to alleged global climate change, a Participation Accord was entered into on behalf of the Operating Subsidiaries with the Department of Energy (DOE) to participate in the DOE's Climate Challenge Program.
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.
Research is being directed into communication systems to develop and demonstrate a high speed advanced power line communication system utilizing existing utility wires to service information needs of the Operating Subsidiaries' customers.
Allegheny Power, in cooperation with the Pennsylvania Department of Environmental Protection and the West Virginia Division of Environmental Protection, continued to investigate the feasibility and cost-effectiveness of injecting fly ash from Allegheny Power's 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 EPRI.
An additional collaborative effort in which Allegheny Power participated through West Penn in 1995 was the Pennsylvania Electric Energy Research Council (PEERC). PEERC was formed in 1987 as a partnership of Pennsylvania based electric utilities to promote technological advancements related to the electric utility industry.
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.
CAPITAL REQUIREMENTS AND FINANCING
Construction expenditures by the Subsidiaries in 1995 amounted to $318.9 million and for 1996 and 1997 are expected to aggregate $278.6 million and $305.2 million, respectively. In 1995, these expenditures included $36.4 million for compliance with the CAAA. The 1996 and 1997 estimated expenditures include $6.7 million and $19.7 million, respectively, to cover the costs of compliance with the CAAA. Expenditures to cover the costs of compliance with the CAAA were much more significant in prior years and may be again in future years if required for Phase II compliance.
* Includes allowance for funds used during construction (AFUDC) for 1995, 1996 and 1997 of: Monongahela $1.4, $1.0 and $2.0; Potomac Edison $1.8, $1.9 and $2.5; and West Penn $5.0, $3.0 and $2.9.
These construction expenditures include major capital projects at existing generating stations, 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) favorable rulings of state commissions allowing the inclusion of carrying costs of construction in rates in lieu of AFUDC; b) the absence of any major construction problems; and c) financing, material and equipment costs lower than expected.
On a collective basis for the Operating Subsidiaries, total expenditures for 1995, 1996, and 1997 include $76 million, $48 million, and $71 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.
Allegheny Power continues 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, increasing the efficiency and availability of Allegheny Power generating facilities, reducing internal 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.)
Current forecasts, which reflect demand-side management efforts and other considerations and assume normal weather conditions, project average annual winter and summer peak load growth rates of 1.56% and 1.57%, respectively, in the period 1996-2006. After considering the reactivation of West Penn capacity in cold reserve (see page 15), 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 Allegheny Power 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, subordinated debt, 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. 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.
AYP Capital has agreed to purchase Duquesne's 50% ownership interest (276 MW) in Fort Martin Unit No. 1 for approximately $170 million. Various financing alternatives for this acquisition are being considered.
In 1995, the Operating Subsidiaries refunded an aggregate of $493.4 million of securities. The securities issued for the refunding had interest rates ranging from 6.05% to 8.00%. Preferred stock issues totaling $155.5 million were refunded with Quarterly Income Debt Securities (QUIDS). QUIDS are subordinated debt instruments which permit deferral of interest payments under certain circumstances for up to 20 consecutive quarters.
In May 1995, the Operating Subsidiaries issued $245 million of first mortgage bonds having interest rates between 7-5/8% and 7-3/4% to refund like securities having interest rates from 8-7/8% to 9-5/8%. Monongahela sold $70 million of 7-5/8% 30-year first mortgage bonds to refund a $70 million 8-7/8% issue due in 2019. Potomac Edison sold $65 million of 7-3/4% 30-year first mortgage bonds to refund a $65 million 9-1/4% issue due in 2019 and $80 million of 7-5/8% 30-year first mortgage bonds to refund an $80 million 9-5/8% issue due in 2020. West Penn sold $30 million of 7-3/4% 30-year first mortgage bonds to refund a $30 million 9% issue due in 2019.
In June 1995, the Operating Subsidiaries issued $92.9 million of tax- exempt bonds having interest rates from 6.05% to 6.15% to refund like securities having interest rates from 6.95% to 9-3/8%. Monongahela sold $25 million of 6.15% 20-year tax-exempt bonds to refund a $25 million 7-3/4% issue. Potomac Edison sold $21 million of 6.15% 20-year tax-exempt bonds to refund a $21 million 7.3% issue. West Penn sold $31.5 million of 6.15% 20- year tax-exempt bonds to refund a $20 million 7% issue and an $11.5 million 6.95% issue. West Penn also sold $15.4 million of 6.05% 19-year tax-exempt bonds to refund a $15.4 million 9-3/8% issue.
In June 1995, the Operating Subsidiaries issued QUIDS to refund an aggregate of $155.5 million of preferred stock. Monongahela sold $40 million of 8% 30-year QUIDS to refund $40 million of preferred stock with rates between 7.36% and 8.8%. Potomac Edison sold $45.5 million of 8% 30-year QUIDS to refund $45.5 million of preferred stock with rates between 7% and 8.32%. West Penn sold $70 million of 8% 30-year QUIDS to refund $70 million of preferred stock with rates between 7% and 8.2%.
In 1995, APS sold 1,407,855 shares of its common stock for $34.6 million through its Dividend Reinvestment and Stock Purchase Plan and its Employee Stock Ownership and Savings Plan.
During 1995, 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 4.75%, 4.71%, 4.249% and 4.292%. The rate set at auction on January 12, 1996, was 4.185%.
At December 31, 1995, short-term debt was outstanding in the following amounts: APS $78.7 million, Monongahela $29.9 million, Potomac Edison $21.6 million, and West Penn $70.2 million, respectively. At December 31, 1995, AGC had $30.6 million of commercial paper outstanding.
The Subsidiaries' ratios of earnings to fixed charges for the year ended December 31, 1995, were as follows: Monongahela, 3.68; Potomac Edison, 3.27; West Penn, 3.58; and AGC, 3.22.
Allegheny Power's consolidated capitalization ratios as of December 31, 1995, were: common equity, 46.6%; preferred stock, 3.7%; and long-term debt, 49.7%, including QUIDS (3.3%). Allegheny Power's long-term objective is to maintain the common equity portion above 45%.
During 1996, the Operating Subsidiaries currently anticipate meeting their capital requirements through a combination of internally generated funds, cash on hand, and short-term borrowing as necessary. APS plans to continue selling common stock through its Dividend Reinvestment and Stock Purchase Plan and Employee Stock Ownership and Savings Plan.
FUEL SUPPLY
Allegheny Power-operated stations burned approximately 15.9 million tons of coal in 1995. Of that amount, 88% was either cleaned (5.2 million tons) or used in stations equipped with scrubbers (8.8 million tons). The use of desulfurization equipment and the cleaning and blending of coal make burning local higher-sulfur coal practical. In 1995 about 97% of the coal received at Allegheny Power-operated 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 11 million tons of coal in 1996. 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 Allegheny Power-operated stations are expected to be met with coal acquired under existing contracts or from known suppliers.
For each of the years 1991 through 1994, the average cost per ton of coal burned was $36.74, $36.31, $36.19 and $35.88, respectively. For the year 1995, the cost per ton decreased to $32.68.
Long-term arrangements, subject to price change, are in effect and will provide for the lime requirements of scrubbers at Allegheny Power's scrubbed stations.
In addition to using ash in various power plant applications such as scrubber by-product 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 also ITEM 1. RESEARCH AND DEVELOPMENT.) In 1995, the Operating Subsidiaries received approximately $459,000 for the sale of 206,609 tons of fly ash and 31,014 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 were issued for Monongahela, Potomac Edison and AGC in 1995.
Monongahela Power
As previously reported, 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 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. On November 9, 1994 the West Virginia PSC affirmed the recommended decision of the Administrative Law Judge (ALJ) which provided for a rate increase of $23.5 million and a 10.85% return on equity (ROE) effective November 16, 1994. This amount was in addition to $6.9 million of CAAA recovery granted effective July 1, 1994, in the Expanded Net Energy Cost (ENEC) recovery proceeding which had been included in Monongahela's $61.3 million request. The West Virginia PSC invited all parties to file petitions for reconsideration which resulted in a second order issued on March 17, 1995. The March 17, 1995 order deferred some of CAAA issues to the 1995 ENEC proceeding. The net result of both the March 17, 1995 base rate order and the ENEC order decreased the previously allowed increase to base rates adopted in the November 9, 1994 order by $1.1 million to $22.4 million and maintained the ROE of 10.85%. The ENEC order permits Monongahela to apply for review of its post-1994 scrubber operation and maintenance expense levels and CAAA investment during the 1996 ENEC proceeding. Monongahela filed a Petition for Appeal with the West Virginia Supreme Court of Appeals challenging the March 17 order. The court declined to hear the appeal.
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 included 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.
On October 20, 1995, a stipulation was submitted by all of the parties to the Ohio PUC. The Ohio PUC approved the stipulation on November 9, 1995 providing for an annual revenue increase of $6.0 million effective November 9, 1995.
Potomac Edison
On January 14, 1994, Potomac Edison filed an application with the West Virginia PSC for a base rate increase of $12.2 million which 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. On November 9, 1994, the West Virginia PSC affirmed the recommended decision of the ALJ providing for a rate increase of $1.5 million and an ROE of 10.85% effective November 11, 1994. This increase was in addition to $1.9 million of CAAA recovery granted effective July 1, 1994, which had been included in Potomac Edison's original request for $12.2 million. The West Virginia PSC invited all parties to file petitions for reconsideration which resulted in a second order issued on March 17, 1995. This order deferred some of the CAAA issues to the 1995 ENEC proceeding. The net result of both the March 17, 1995 base rate order and the ENEC order reduced the original $1.5 million increase in base rates adopted in the November 9, 1994 order by $1.1 million to $.4 million. The ROE was maintained at 10.85%. The order permits Potomac Edison to apply for review of its post- 1994 scrubber operation and maintenance expense levels and CAAA investment during the 1996 ENEC proceeding. Potomac Edison filed a Petition for Appeal with the West Virginia Supreme Court of Appeals challenging the March 17 order. The court declined to hear the appeal.
On June 25, 1995, Potomac Edison implemented two FERC-approved settlement agreements covering wholesale rates in effect for its municipal, co-op, and borderline agreement customers subject to the jurisdiction of the FERC. Each agreement 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 first agreement, with all but one of Potomac Edison's FERC customers, provides for a three-year term of service with an increase in annual revenues of $2.12 million. During this period, a moratorium on further rate changes, except for changes based on fuel costs, taxes, and environmental statutes or regulations, is in effect. This agreement also allows Potomac Edison to seek legitimate and verifiable stranded costs from any customer who terminates service under the tariff. The second agreement, with the one remaining Potomac Edison FERC customer not included under the first agreement, provides for service until January 1, 1997, (approximately eighteen months) with an increase in annual rates of $.15 million. A moratorium on rate increases is also in effect for this time period. However, this agreement contains no provision for recovery of stranded costs from the customer should service be terminated.
AGC
AGC's rates are set by a formula filed with and previously accepted by FERC. The only component which changes is the ROE. In December 1991, AGC
filed for a continuation of the existing ROE of 11.53% and other interested parties filed to reduce the ROE to 10%. Hearings were held and a recommendation was issued by an ALJ on December 21, 1993, for an ROE of 10.83%. Exceptions to this recommendation were filed by all parties for consideration by the FERC. On January 28, 1994, a complaint was filed jointly by several parties 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. A recommendation was issued by an ALJ on December 22, 1994, to dismiss the joint complaint. A settlement agreement for both cases was filed with FERC on January 12, 1995, which would reduce AGC's ROE from 11.53% to 11.13% for the period from March 1, 1992 through December 31, 1994, and increase AGC's ROE to 11.2% for the period from January 1, 1995 through December 31, 1995. This settlement was approved by FERC on March 23, 1995. Refunds were made by AGC of any revenues collected between March 1, 1992 and March 23, 1995 in excess of these levels. A second settlement has been negotiated to address AGC's ROE after 1995. On December 21, 1995, AGC submitted the new settlement to the FERC and action is pending. The interested parties representing less than 2% of AGC's eventual revenues have filed exceptions to the settlement. Under the terms of the settlement, AGC's ROE for 1996 would be 11%. For 1997 and 1998 the ROE would be set by a formula based upon the yields of 10-year constant maturity U.S. Treasury securities. However, the change in ROE from the previous year's value cannot exceed 50 basis points.
Through a filing completed on October 31, 1994, AGC sought FERC approval to add a prior tax payment of approximately $12 million to rate base which would produce about $1.4 million in additional annual revenues. The FERC accepted AGC's filing and ordered the increase to become effective June 1, 1995.
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 $199 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
Allegheny Power currently meets applicable standards as to particulates and opacity at the power stations through high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, and, at times, reduction of output. From time to time minor excursions of opacity, normal to fossil fuel operations, are experienced and are accommodated by the regulatory process.
On July 17, 1995, the West Virginia Division of Environmental Protection (WVDEP), Office of Air Quality (OAQ), issued a Notice of Violation (NOV) regarding the accidental release of particulate matter that occurred on June 17, 1995, at the Pleasants Power Station. Allegheny Power responded on August 11, 1995, and stated that the accidental release of particulate matter was not due to a failure of any of the pollution control equipment, but was a side effect of testing a further reduction of the sulfur dioxide (SO[2]) emissions from the power station. Subsequently, on November 16, 1995, the WVDEP issued a Cease and Desist Order pertaining to the release. In order to minimize the risk of future releases, the station intends to increase the frequency of scheduled stack washing. Also, a consultant has been retained to determine whether any operational or equipment changes can be implemented to reduce the risk of releases in the future.
Allegheny Power meets current emission standards as to SO[2] 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 SO[2] and two million tons of nitrogen oxides (NO[x]) from 1980 emission levels, to be completed in two phases, Phase I and Phase II. Five coal-fired Allegheny Power plants are affected in Phase I and the remaining plants and units reactivated in the future will be affected in Phase II. Installation of scrubbers at the Harrison Power Station was the strategy undertaken by Allegheny Power to meet the required SO[2] emission reductions for Phase I (1995-1999). Continuing studies will determine the compliance strategy for Phase II (2000 and beyond). Studies to evaluate cost effective options to comply with Phase II SO[2] limits, including those which may be available from the use of Allegheny Power's banked emission allowances and from the emission allowance trading market, are continuing. It is expected that burner modifications at possibly all Allegheny Power stations will satisfy the NO[x] 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.
In an effort to introduce market forces into pollution control, the CAAA created SO[2] emission allowances. An allowance is defined as an authorization to emit one ton of SO[2] into the atmosphere. Subject to regulatory limitations, allowances (including bonus and extension allowances) may be sold or banked for future use or sale. Allegheny Power received, through an industry allowance pooling agreement, a total of approximately 554,000 bonus and extension allowances during Phase I. These allowances are in addition to the CAAA Table A allowances of approximately 356,000 per year during the Phase I years. Ownership of these allowances permits Allegheny Power to operate in compliance with Phase I, as well as to postpone a decision on its compliance strategy for Phase II. As part of its compliance strategy, Allegheny Power continues to study the allowance market to determine whether sales or purchases of allowances or participation in certain derivative or hedging allowance transactions are appropriate.
In a case brought by the electric utility industry which disputed the EPA's inclusion of overfire air equipment as well as low NO[x] burners in its definition of "low NO[x] burner technology," the District of Columbia Circuit Court of Appeals on November 29, 1994 vacated and remanded to the EPA the Title IV NO[x] rule. As a result, the January 1, 1995, Phase I NO[x] compliance deadline under Title IV is no longer applicable. On April 13, 1995, the EPA published the revised NO[x] regulation which redefined low NO[x] burner technology as "burners only" and changed the Phase I compliance date from January 1, 1995, to January 1, 1996.
Pursuant to an option in the CAAA and in order to avoid the potential for more stringent NO[x] limits in Phase II, Allegheny Power chose to treat seven Phase II Group 1 boilers (tangential- and wall-fired) as Phase I affected units (Substitution Units) as of January 1, 1995. Additionally, the four Phase II, Group 2 boilers (top- and cyclone-fired) were also made Substitution Units for 1995. The status of all Substitution Units will be evaluated on an annual basis to ascertain the financial benefits. As a result of being Phase I affected, these Substitution Units will also be required to comply with the Phase I SO[2] limits for each year that they are accorded substitution status by Allegheny Power. Phase I NO[x] and SO[2] compliance for these units should not require additional capital or operating expenditures.
Title I of the CAAA established an ozone transport region (OTR) consisting of the District of Columbia, the northern part of Virginia and 11 northeast states including Maryland and Pennsylvania. On October 11, 1995, Pennsylvania petitioned the EPA to remove western Pennsylvania from the OTR. The EPA has not acted on the request. Sources within the OTR will be required to reduce NO[x] 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 NO[x] burners) at all Pennsylvania and Maryland stations has been completed. This is essentially compatible with Title IV NO[x] reduction requirements.
The Ozone Transport Commission (OTC), formed by the states in the OTR and Washington, DC, has determined that Allegheny Power will be required to make additional NO[x] reductions beyond RACT in order for the ozone transport region to meet the ozone NAAQS. Under terms of a Memorandum of Understanding (MOU) among the OTR states, Allegheny Power's power stations located in Maryland and Pennsylvania will be required to reduce NO[x] emissions by 55% from the 1990 baseline emissions, with a compliance date of May 1999. Further reductions of 75% from the 1990 baseline will be required by May 2003, unless the results of modeling studies due to be completed by 1998, indicate otherwise. If Allegheny Power has to make reductions of 75%, it could be very expensive and would depend upon further technological advances. Both Maryland and Pennsylvania must promulgate regulations to implement the terms of the MOU.
During 1995, the Environmental Council of States (ECOS) and the EPA established the Ozone Transport Assessment Group (OTAG) to develop recommendations for the regional control of NO[x] and Volatile Organic Compounds (VOC's) in 31 states east of and bordering the west bank of the
Mississippi River plus Texas. OTAG appears to be similar to the OTC in purpose and organization. OTAG could lead to additional NO[x] controls on certain Allegheny Power generating facilities in West Virginia. There is no assurance that NO[x] control for non-OTR states will be limited to RACT. What occurs in the non-OTR states could also affect whether Allegheny Power generating facilities in Maryland and Pennsylvania would need post-RACT controls. OTAG plans to issue recommendations by the end of 1996.
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 ambient standards for SO[2]. 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 SO[2] 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 the 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 of Allegheny Power's stations and disposal sites are in place. However, NPDES permit renewals for several West Virginia disposal sites contain what Allegheny Power believes are overly stringent discharge limitations. The WVDEP has temporarily stayed the stringent permit limitations while Allegheny Power continues 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 stormwater permitting program required under the 1987 Amendments to the Clean Water Act required implementation in two phases. In Phase I, the EPA and state agencies 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.
In April 1995, EPA promulgated the Phase II stormwater rule which establishes a two-tiered application process for discharges composed entirely of stormwater. Under the rule, sources determined to be significant contributors to water quality problems will be required to apply for a discharge permit within 180 days of receiving notice. The remaining sources are required to apply for permits within six years of the rule's effective date or August 2, 2001 under yet-to-be proposed application requirements.
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 Allegheny Power 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, Allegheny Power jointly filed with American Electric Power Company, Inc. (AEP) 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 through EPRI by all participants, including Allegheny Power. While the justification for the variance requests is being developed, Allegheny Power is 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 Protection (PADEP) 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. PADEP 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 Allegheny Power cannot be predicted.
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, Ohio, Pennsylvania, Virginia and West Virginia have also enacted hazardous and solid waste management regulations that are as stringent as or more stringent than the corresponding EPA regulations.
Allegheny Power is in a continual process of either permitting new or re-permitting existing disposal capacity to meet future disposal needs. All disposal areas are currently operating in compliance with their permits.
Significant costs were incurred during 1995 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 Allegheny Power's facilities. Allegheny Power continues 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.
Allegheny Power continues to actively pursue, with PADEP and WVDEP encouragement, ash utilization projects such as deep mine injection for subsidence and water quality improvement, structural fills for highway and building construction, and soil enhancement for surface mine reclamation.
Potomac Edison received a notice from the Maryland Department of the Environment (MDE) in 1990 regarding a remediation ordered under Maryland law at a facility previously owned by Potomac Edison. The MDE has identified Potomac Edison as a potentially responsible party under Maryland law. Remediation is being implemented by the current owner of the facility which is located in Frederick. It is not anticipated that Potomac Edison's share of remediation costs, if any, will be substantial.
The Operating Subsidiaries are also among a group of potentially responsible parties under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), for the Jack's Creek/Sitkin Smelting Superfund Site in central Pennsylvania. (See ITEM 3. LEGAL PROCEEDINGS for a description of this superfund 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 early 1996. 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 Allegheny Power is unknown at this time.
Reauthorization of the Clean Water Act, CERCLA 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 began 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 by-product 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 Allegheny Power and which is undergoing intense study, is the health effect, if any, of electric and magnetic fields. The financial impact of this issue on Allegheny Power, if any, cannot be assessed at this time.
In connection with President Clinton's Climate Change Action Plan concerning greenhouse gases, Allegheny Power expressed by letter to DOE in August 1993, its 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 Allegheny Power's integrated resource planning process and must not have an adverse effect on its competitive position in terms of costs and rates, or be unacceptable to its 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 established the principles DOE and utilities will operate under to reduce or avoid emission of greenhouse gases. A company-specific agreement was entered into on behalf of the Operating Subsidiaries and DOE in February 1995.
The EPA is required by law to regularly review the National Ambient Air Quality Standards for criteria pollutants. Recent court orders due to litigation by the American Lung Association have expedited these reviews. The EPA is currently reviewing the standards for ozone, SO[2], NO[x], and particulate matter. The impact on Allegheny Power of any revision to these standards is unknown at this time.
REGULATION
Allegheny Power and AYP Capital are subject to the broad jurisdiction of the SEC under PUHCA. APS, as a Maryland corporation, 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. The Subsidiaries and AYP Capital are regulated by the FERC. In addition, they are subject to numerous other city, county, state, and federal laws, regulations, and rules.
In June 1995, the SEC published its report which recommended changes to PUHCA, including a recommendation to Congress to repeal the entire act. A bill has been introduced in Congress to repeal PUHCA. However, Allegheny Power
cannot predict what changes, if any, will be made to PUHCA as a result of these activities.
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking on open access nondiscriminatory transmission service which came to be known as the "Mega-NOPR" due to its size and scope. If adopted by the FERC, the Mega- NOPR will lead to a fundamental restructuring of the business of transmitting wholesale electric power and could potentially influence the future of retail electric sales as well. The FERC's stated objective was to ensure development of a competitive market for wholesale power buyers and sellers while preventing anti-competitive or discriminatory transmission practices. The Mega-NOPR requires all public or investor-owned utilities that own transmission systems and are under FERC's jurisdiction to file nondiscriminatory, open access transmission tariffs available to all wholesale buyers and sellers of electricity and apply these open access tariffs to their own wholesale purchases and sales of electricity. The Mega-NOPR also permits such utilities to recover stranded costs that may result from restructuring of the wholesale electric industry. In a separate notice, FERC proposed the development of a standardized, real-time electronic information network to provide all potential users of a utility's transmission system equal access to information regarding transmission capability and pricing. Allegheny Power has numerous concerns regarding the Mega-NOPR, including the issue of stranded costs, reliability of service and the development of a real-time electronic information network.
The requirements of the Mega-NOPR, if adopted by FERC, would force utilities to functionally unbundle their transmission and generation assets to operate independently of one another, in order to promote nondiscriminatory behavior. In response to the Mega-NOPR and in conjunction with Allegheny Power's reengineering of its Bulk Power Supply functions, Allegheny Power has established separate business units to operate and manage its generation and transmission assets. (See ITEM 1. REORGANIZATION for further discussion of the formation of business units.) Allegheny Power cannot predict when FERC will issue final regulations, nor the specifics thereof, regarding nondiscriminatory open access transmission services and related issues.
Allegheny Power founded and continues to participate in, along with other utilities, an organization (General Agreement on Parallel Paths) whose primary purpose is to develop a mutually acceptable method of resolving the inequities imposed on transmission network owners by parallel power flows.
Section 111 of EPACT requires 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. In 1994, Maryland, Pennsylvania, Virginia, and West Virginia initiated investigations to determine whether to adopt the federal standards, while Ohio summarily issued a final order. Allegheny Power submitted comments in all proceedings. Maryland, Ohio, Virginia and West Virginia have issued final orders. All four states declined to adopt the federal standards,
concluding that existing state regulations adequately address the issues. The outcome in Pennsylvania cannot be predicted.
On December 30, 1995, the Pennsylvania PUC issued its regulations regarding future competitive bidding for purchase of capacity and energy. The regulations specify the rules an electric utility must follow to competitively bid the long-term purchase of capacity and energy.
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. By March 1995, all appeals to the June 1994 order were withdrawn and the order became final.
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 Order.
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 and a number of interested parties, including Monongahela, submitted comments. The Ohio PUC has taken no further action following the filing of comments.
As part of its investigation into market competition and regulatory policies, the Maryland PSC has declared that all new capacity needs in the state will be subject to competitive bidding unless a utility can demonstrate why a particular capacity need should not be bid.
Virginia has not mandated compulsory competitive bidding for capacity additions.
On September 20, 1994, the Maryland PSC 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 described the issues on which they requested comment by the utilities and interested persons. Potomac Edison submitted comments. After legislative hearings were held and comments were filed, the Maryland PSC issued an order. In its order dated August 18, 1995 the Commission found that while competition in the electric wholesale market should be encouraged, retail competition is not in the public interest at this time. The Commission also announced in its order that in the future it would be flexible and allow utilities to implement
special rates and contracts including cost-based economic development rates as appropriate.
By order dated September 18, 1995, the Virginia State Corporation Commission began an investigation reviewing Commission policy regarding restructuring of and competition in the electric utility industry. The Commission staff has been directed to investigate and file a report on competitive issues by March 29, 1996. Comments by utilities and other interested persons on the staff report are due by May 31.
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. These discussions are being undertaken pursuant to an Ohio Energy Strategy issued in April 1994. The Ohio PUC is pursuing an incremental approach to competition by holding roundtable meetings. As a first step, the meetings have resulted in a set of guidelines on interruptible rates which are now pending before the Ohio PUC.
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 and reply comments have been filed. The Pennsylvania PUC staff issued a report advising against instituting retail wheeling at this time. Thereafter, the Pennsylvania PUC held hearings in December 1995, January 1996, and February 1996. The Pennsylvania PUC has set a target of April 1996 to issue a final report to the Governor and the Pennsylvania Legislature.
In August 1994, the Pennsylvania PUC instituted a proposed rulemaking relating to Pennsylvania PUC review of siting and construction of electric transmission lines. 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 1995, the Staff of the Maryland PSC issued draft regulations concerning the construction of generating stations and overhead transmission lines by nonutility generators (NUGS), applications covering modifications of electric generating stations by utilities and by NUGs, and changes to current regulations relating to whether certificates of public convenience and necessity must be obtained prior to modifying existing overhead transmission lines. Potomac Edison commented on the proposed changes in November 1995, and cannot predict what, if any, modifications might be made to current regulations.
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 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. The Pennsylvania PUC has appealed the case to the Pennsylvania Supreme Court.
During 1995, Potomac Edison continued its participation in the Collaborative Process for demand-side management in Maryland. Potomac Edison's two programs, the Commercial and Industrial Lighting Rebate Program and the Power Saver/Comfort Home Program for new residential construction continued. Through December 31, 1995, Potomac Edison had approved applications for $15.2 million in rebates related to the commercial lighting program and $2.6 million in rebates related to the residential new construction program. The peak demand reductions from these two programs through the end of 1995 should reduce future generation requirements by about 18.4 and 3.3 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. Potomac Edison filed a request to change the method used to allocate demand-side management costs to customers as part of the surcharge. The requested change was denied by a Hearing Examiner but has been appealed to the full Commission. Potomac Edison is awaiting the Commission's decision on this allocation issue.
West Penn implemented a two-year Low Income Payment and Usage Reduction Pilot Program in 1994. This program 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 nonprofit, 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 of the indenture 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 ALLEGHENY POWER MAP.)
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
On September 16, 1994, Duquesne Light Company (Duquesne) initiated a proceeding before the FERC by filing a request for an order requiring the Operating Subsidiaries to provide 300 MW of transmission service at parity with native load customers from interconnection points with Allegheny Power to Allegheny Power's points of interconnection with the Pennsylvania-New Jersey- Maryland Interconnection. On May 16, 1995, the FERC issued a preliminary order directing the Operating Subsidiaries to provide 300 MW of transmission service as requested by Duquesne. The order established further procedures for the development of rates, terms, and conditions of service by the parties. The parties have completed the procedural schedule and await a final order from the FERC. On October 6, 1995, the Operating Subsidiaries filed open access tariffs under which they intend to provide comparable wholesale transmission services to all potential customers, including Duquesne. Consequently, on October 23, 1995, the Operating Subsidiaries filed a motion asking FERC to suspend further proceedings in the Duquesne docket and to consolidate it with the open access docket. The FERC has chosen not to consolidate the proceedings for the present time.
In 1979, National Steel Corporation (National Steel) filed suit against APS and 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 APS and the Subsidiaries was rendered in June 1991. National Steel has filed a motion for a new trial, which is still pending before the Circuit Court of Hancock County. APS and the Subsidiaries believe the motion is without merit; however, they cannot predict the outcome of this case.
In 1987, West Penn entered into separate Electric Energy Purchase Agreements (EEPAs) with developers of three PURPA projects: Milesburg (43 MW), Burgettstown (80 MW), and Shannopin (80 MW). The EEPAs provided for the purchase of each project's power over 30 years or more at rates generally approximating West Penn's estimated avoided cost at the time the EEPAs were
negotiated. Each EEPA 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 EEPA. Thereafter the Pennsylvania PUC issued orders that significantly modified the EEPAs. Since that time, all three EEPAs as modified 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 Advanced Materials Company and Allegheny Ludlum Corporation, 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, acting upon a pending petition of Shannopin, entered an order calculating capacity costs to be paid to the project. West Penn and its two largest industrial customers appealed this order to the Pennsylvania Commonwealth Court. On July 20, 1995, the Pennsylvania Commonwealth Court reversed part of the PUC order by reducing the maximum avoided capacity cost rate to be paid to the project from 8.0151 cents per kWh to 5.5933 cents per kWh. On October 23, 1995, West Penn filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court. A cross petition for Allowance of Appeal was subsequently filed by Shannopin. These appeals are pending.
West Penn and the developers of the Shannopin project reached an agreement on January 25, 1996, which provides that West Penn will buy out the Shannopin EEPA and terminate the project and all pending litigation associated with the Shannopin project. The agreement provides for a buy out price of $31 million. The buy out agreement is subject to Pennsylvania PUC approval of West Penn's full pass through of the buy out price to West Penn's customers through the energy cost rate by no later than March 31, 1999. Once the Pennsylvania PUC order is final and no longer subject to appeal, both parties will withdraw their pending Pennsylvania Supreme Court appeals. Because the buy out agreement is conditioned on full pass through of the buy out price to customers, it will not have a material effect on West Penn's net income. However, the buy out will significantly aid West Penn's customers by eliminating a requirement to purchase unneeded, above market cost power for 30 years. The agreement was filed with the Pennsylvania PUC on February 13, 1996, along with a request for expedited approval.
On February 27, 1995, the Milesburg developers filed with the Pennsylvania PUC a Petition for Recalculation of capacity cost to be paid to the project in accordance with the July 1990 order of the Commonwealth Court. These matters have since been stayed at the request of Milesburg and West Penn for the purpose of pursuing settlement discussions.
The Pennsylvania PUC orders relating to recalculated rates and adjusted milestone dates for Burgettstown became final and no longer subject to appeal 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 rescind its orders regarding these projects because they
were not in accord with PURPA and were no longer in the public interest. On December 16, 1994, the Pennsylvania PUC dismissed the complaint. West Penn appealed the order to the Pennsylvania Commonwealth Court. By order entered May 25, 1995, the Pennsylvania Commonwealth Court affirmed the Pennsylvania PUC order.
In November 1994, Washington Power (I), Inc. and Air Products and Chemicals, Inc., trading as Washington Power Company, L.P. (Washington Power), the developer of Burgettstown, filed a complaint against West Penn in the Court of Common Pleas of Washington County, Pennsylvania. The complaint requested equitable relief in the form of specific performance, declaratory and injunctive relief, and also sought monetary damages for breach of contract and for tortious interference with Burgettstown's contractual relations with others. The Court set April 3, 1995 as the trial date for the specific performance remedy only. The trial was cancelled at the request of Washington Power. On May 5, 1995, at the request of Washington Power, the Court entered an order discontinuing the case without prejudice.
On March 10, 1995, West Penn filed a petition for issuance of a declaratory order with FERC. This petition sought a declaration that the orders of the Pennsylvania PUC requiring West Penn to purchase capacity from Burgettstown at rates and pursuant to the terms in the Pennsylvania PUC Orders violated PURPA and FERC's PURPA regulations and thus West Penn had no obligation to purchase capacity from Burgettstown. On May 8, 1995, FERC denied the petition.
The Burgettstown EEPA automatically terminated in accordance with its terms, as the financing closing had not occurred by May 8, 1995, as required by the Pennsylvania PUC orders. Burgettstown did not request an extension.
On May 2, 1995, Washington Power filed a complaint against West Penn, APS and APSC in the United States District Court for the Western District of Pennsylvania asserting claims of treble damages for monopolization and attempts to monopolize in violation of the federal antitrust laws, unfair competition, breach of contract, intentional interference with contract and interference with prospective business relations. West Penn, APS and APSC cannot predict the outcome of this litigation.
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 of power 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. On August 2, 1995, these proceedings, with the exception of discovery, were stayed due to South River's appeal to the Commonwealth Court of an order of the Pennsylvania PUC requiring South River to bear the cost associated with providing notice of the proceedings to West Penn's customers. West Penn cannot predict the outcome of this proceeding.
Two previously reported complaints had been filed with the West Virginia PSC by developers of PURPA cogeneration projects in Marshall County, West Virginia (MidAtlantic) and Barbour County, West Virginia, seeking to require Monongahela and Potomac Edison to purchase capacity from the projects.
Following a meeting in February, 1994, and an exchange of correspondence in the spring and summer of 1994, no further contact was had with the developers of the Barbour County project until, following a request by the PSC for a status report, Barbour County reported it was ready to go forward and discuss substantial modifications to the project. Potomac Edison and Monongahela responded on May 8, 1995, recommending the West Virginia PSC require evidence that a new project would be a qualifying facility (QF) under PURPA, that Barbour County provide a plan for resolving its QF status, and that any meeting with Staff be open to representatives of all parties. By Order dated June 15, 1995, the West Virginia PSC dismissed the Barbour County complaint on the basis that the project was undefined and contrary to the public interest.
The developers of the MidAtlantic project contacted Potomac Edison and Monongahela in September 1994 proposing a new, two-phased gas turbine facility. Following an exchange of letters, on January 10, 1995 MidAtlantic filed with the West Virginia PSC a Motion to Compel Potomac Edison to enter into an agreement, alleging bad faith negotiations. Potomac Edison and Monongahela filed a response on January 30, 1995, denying bad faith and noting numerous problems with MidAtlantic's new proposed project, including its plan to have West Virginia customers pay 100% of costs of the first phase, contrary to an order entered by the West Virginia PSC on March 5, 1993. On March 20, 1995 the West Virginia PSC issued an order rejecting MidAtlantic's plan to charge 100% of its Phase I project to West Virginia customers; directing MidAtlantic to obtain from FERC a resolution of its QF status; and requiring MidAtlantic to advise the West Virginia PSC within 30 days if it intended to pursue its complaint.
MidAtlantic filed a response to the West Virginia PSC order on April 19, 1995, together with a motion for extension of time to respond to the question whether it would continue with the project, citing withdrawal of its financial partner (Babcock and Wilcox) from the project. Following a grant of an extension of time, on June 26, 1995, MidAtlantic filed a letter informing the West Virginia PSC that it would not pursue its project further, blaming APS for its inability to obtain a financial partner. The West Virginia PSC dismissed the MidAtlantic complaint by order dated June 29, 1995.
On September 7, 1995, MidAtlantic sued Monongahela, Potomac Edison, and APS in state court in Marshall County, West Virginia for failure to comply with PURPA regulations in refusing to purchase capacity and energy from the proposed project; interference with MidAtlantic's contract with Babcock and Wilcox; causing and/or aiding Babcock and Wilcox in breaching a fiduciary duty; defamation; and undermining PURPA in an anti-competitive civil conspiracy with Babcock and Wilcox. The MidAtlantic suit was also filed against Babcock and Wilcox for breach of contract, breach of fiduciary duty, and conspiring with Allegheny Power to undermine PURPA. MidAtlantic seeks compensatory and punitive damages. Monongahela, Potomac Edison and APS filed
an answer on October 24, 1995, and Babcock and Wilcox filed an answer, counterclaim and motion for summary judgment, alleging that MidAtlantic had released Babcock and Wilcox from all obligations arising from their development agreement. The court heard oral argument on the summary judgment motion on January 19, 1996. Monongahela, Potomac Edison and APS cannot predict the outcome of this litigation.
On August 24, 1995, American Bituminous Power Partners, L.P. (ABPP), owner and operator of the Grant Town project, an operating 80 MW waste coal PURPA project located in Marion County, West Virginia (see page 14), filed a Petition to Reopen and for Emergency Interim Relief with the West Virginia PSC against Monongahela. ABPP seeks modifications to the EEPA that will result in an unspecified increase in the cap of the Tracking Account and a retroactive restoration of the price for project energy to 1.9 cents/kWh. The West Virginia PSC issued an order on November 29, 1995, which set a schedule for briefing of issues. In its brief, ABPP advised for the first time that the modifications it is seeking are only for interim relief and that if such relief is granted, it intends to petition the West Virginia PSC to further amend the EEPA to permanently increase the avoided energy cost. On December 20, 1995, ABPP requested additional briefing to clarify the relief sought. On January 5, 1996, the West Virginia PSC granted ABPP's request and set a schedule for additional briefs which concluded on January 26, 1996. Monongahela cannot predict the outcome of this proceeding.
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 were filed. Effective June 1, 1995, West Virginia enacted a new method of calculating the B & O Tax, assessing the tax on a capacity rather than a generation basis and effective January 31, 1996, included a lower rate for generating units with flue-gas desulfurization systems (scrubbers). As a result of these changes, this litigation ended.
As of March 8, 1996, Monongahela has been named as a defendant along with multiple other defendants in a total of 5,564 pending asbestos cases involving one or more plaintiffs. Potomac Edison and West Penn have been named as defendants along with multiple other defendants in a total of 2,749 of those cases. Because these cases are filed in a "shot-gun" format whereby multiple plaintiffs file claims against multiple defendants in the same case, it is presently impossible to determine the actual number of cases in which plaintiffs make claims against the Operating Subsidiaries. However, based upon past experience and available data, it is estimated that about one-
third of the total number of cases filed 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. With very few exceptions, plaintiffs claiming exposure at stations operated by the Operating Subsidiaries were employed by third-party contractors, not the Operating Subsidiaries. Three plaintiffs are known to be either present or former employees of Monongahela. Each plaintiff generally seeks compensatory and punitive damages against all defendants in amounts of up to $1 million and $3 million, respectively; in those cases which include a spousal claim for loss of consortium, damages are generally sought against all defendants in an amount of up to an additional $1 million. Because there are multiple defendants, the Operating Subsidiaries believe their relative percentage of potential liability is a small percentage of the total amount of the damages sought. A total of 94 cases have been previously settled and/or dismissed as against Monongahela for an amount substantially less than the anticipated cost of defense. While the Operating Subsidiaries believe that all of the cases are without merit, they cannot predict the outcome nor are they able to determine whether additional cases will be filed.
On June 10, 1994, Allegheny Power filed a declaratory judgment action in the Superior Court of New Jersey against its 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. On January 27, 1995, the Court granted the CGL insurers' motion which dismissed the complaint, without prejudice, on procedural grounds. On the same day, Allegheny Power recommenced action in the Court of Common Pleas of Westmoreland County, Pennsylvania where it is currently pending. To date, two insurers have settled. However, the final outcome of this proceeding cannot be predicted.
On December 13, 1995, APSC, Monongahela, and Potomac Edison filed a civil complaint in the Court of Common Pleas of Westmoreland County, Pennsylvania against Industrial Risk Insurers (IRI) seeking damages in excess of $5 million for breach of an insurance contract covering physical damage to property at Unit No. 1 of Fort Martin Power Station. IRI previously denied coverage under an all risk insurance policy in effect at the time of the property damage. The outcome of the litigation or the amount of damages, if any, that may be recovered 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 (RI/FS) prepared by the EPA indicates remedial alternatives which range as high as $113 million, to be shared by all responsible parties. A PRP Group has been formed and has submitted an addendum to the RI/FS which proposes a substantially less expensive cleanup remedy. 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 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 reaching 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
APS, Monongahela, West Penn and AGC did not submit any matters to a vote of shareholders during the fourth quarter of 1995.
The holder of all the outstanding common stock of Potomac Edison consented in writing on October 23, 1995, to the amendment of the Charter of the Corporation to reclassify shares that had been purchased pursuant to a mandatory sinking fund.
(a) All officers and directors are elected annually. (b) Retired effective September 1, 1995. (c) Retired effective December 1, 1995. (d) Resigned effective December 1, 1995. (e) Retired effective January 1, 1996.
(a) All officers and directors are elected annually. (b) Retired effective January 1, 1996.
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, 1995, there were 63,290 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 1, 1996 were $30-1/2 and $28. The last reported sale on that date was at $30.
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 48 Monongahela 51 Potomac Edison 53 West Penn 55 AGC 57
[a] To record unbilled revenues, net of income taxes. [b] Reflects a two-for-one common stock split effective November 4, 1993. [c] Excludes the cumulative effect of the accounting change in 1994. [d] Capability available through contractual arrangements with nonutility generators. [e] Preliminary.
(a) To record unbilled revenues, net of income taxes. (b) Excludes the cumulative effect of the accounting change in 1994.
*Capability available through contractual arrangements with nonutility generators.
(a) To record unbilled revenues, net of income taxes. (b) Excludes the cumulative effect of the accounting change in 1994.
(a) To record unbilled revenues, net of income taxes. (b) Excludes the cumulative effect of the accounting change in 1994.
(*) Capability available through contractual arrangements with nonutility generators.
*Reflects a balance sheet reclassification of $12 million from deferred charges to plant for a prior tax payment.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Page No.
APS 59 Monongahela 68 Potomac Edison 77 West Penn 87 AGC 95
APS Management Discussion & Analysis of Financial Condition and Results of Operations Review of Utility Operations Earnings
Earnings in 1995 increased to $240 million ($2.00 per share) compared with $220 million ($1.86 per share) in 1994, excluding in 1994 the cumulative effect of an accounting change to record unbilled revenues. The increase resulted primarily from additional retail revenues due to increased kilowatt-- hour (kWh) sales and previously reported rate increases. These revenue increases were offset in part by restructuring charges and inventory write-offs in 1995 of $14.1 million after tax ($.12 per share) and higher expenses. Earnings in 1994 included a charge of $5.3 million after tax ($.05 per share) related to asset write-offs. Consolidated net income in 1993 was $216 million ($1.88 per share). Consolidated net income in 1994 also reflects higher retail revenues from increased kWh sales and rate increases, offset in part by higher expenses.
Restructuring activities in 1995 were initiated by the System in response to the competitive environment emerging in the electric utility industry. The subsidiaries are restructuring many of their functions to strengthen their competitive position and improve their cost structure. During 1995, reenginee- ring of the Bulk Power Supply department was substantially completed and process redesign is expected to be substantially completed in 1996 for the remainder of the System. Downsizing was not a specific goal of the restructur- ing efforts but, as a consequence of process redesign and elimination of duplicate positions, approximately 200 employees have been placed in a staffing force pending reassignment or layoff. In addition, about 130 fewer employees will be required in the power station work force by the end of 1997, and employee reductions are also likely to result from reengineering in other areas. The charges recorded in 1995 in connection with restructuring activi- ties reflect estimated liabilities related to staffing force employees' separation costs, inventory write-offs in connection with changes in inventory management objectives, and certain other costs. These costs will be recovered through future cost savings.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial customers are shown on page 50. Such kWh sales increased 3.9% and 2.8% in 1995 and 1994, respectively. The increases in revenues from sales to residential, commercial, and industrial customers resulted from the following:
Changes from Prior Year
(Millions of Dollars) 1995 1994 Increased kWh sales $ 56.2 $ 23.6 Rate changes: Pennsylvania 50.2 22.7 Maryland 17.7 11.9 West Virginia 19.3 9.7 Virginia (1.8) 8.5 Ohio .5 85.9 52.8 Fuel and energy cost adjustment clauses* (2.8) 48.3 Other .6 4.3 $139.9 $129.0
* Changes in revenues from fuel and energy cost adjustment clauses have little effect on consolidated net income.
The increase in kWh sales in 1995 was largely attributable to industrial and commercial sales. Industrial sales increased 4.2% and 4.4% in 1995 and 1994, respectively. The 4.7% increase in commercial sales in 1995 and the 2.2% increase in 1994 reflect growth in the number of customers and in 1995 also reflects increased customer usage. These increases continue to reflect a trend of economic growth in the service territory. In 1995 the subsidiaries implemented a new Major Accounts Program which focuses on enhancing the working relationships with the System's largest customers. The goal of the program is to assure, through superior service, that Allegheny Power remains the energy supplier for these major customers.
Residential kWh sales increased 3% in 1995 and .9% in 1994. The rate of growth in the number of residential customers has remained constant at 1.2% annually in 1995, 1994, and 1993. However, the impact of weather on customer usage continues to produce fluctuations in residential sales. In 1995, decreased sales due to mild weather in the first and second quarters were more than offset by extremely hot summer weather and cooler than normal winter weather in November and December as compared to 1994. The 1994 residential use was down slightly from 1993 levels reflecting a decrease in both heating and cooling degree days.
Rate case decisions in all jurisdictions, representing revenue increases in excess of $125 million on an annual basis, have been obtained, most of them effective in late 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. Additional base rate increases are not expected to be necessary for the next several years. However, future purchased power expenses related to a qualified facility under the Public Utility Regulatory Policies Act of 1978 (PURPA), to be completed in late 1999, may make it necessary to increase rates at that time.
KWh sales to and revenues from nonaffiliated utilities are comprised of the following items:
Sales from subsidiaries' generation in 1995 decreased because of growth in kWh sales to retail customers, which reduced the amount available for sale, and because of continuing price competition. The generation tax imposed in West Virginia, which in prior years was a significant factor affecting the subsidiaries' ability to compete in the market for sales to nonaffiliated utilities, was favorably amended effective in June 1995 to change the basis of the tax from generation to generating capacity. Sales of purchased power vary depending on the availability of other utilities' generating equipment, demand for energy, and price competition. In the future, some of these transactions may be made under new transmission tariffs described below. About 95% of the aggregate benefits from sales to nonaffiliated utilities are passed on to retail customers and have little effect on consolidated net income.
The increase in other revenues in 1995 and 1994 resulted primarily from increased revenues from wholesale customers (cooperatives and municipalities who own their own distribution systems and who buy all or part of their bulk power needs from the subsidiaries under regulation by the Federal Energy Regulatory Commission). Under the National Energy Policy Act of 1992, these customers obtained the ability to choose the bulk power supplier of their choice by the requirement that transmission-owning utilities must provide transmission service. In 1995, rate cases for wholesale customers were completed with the result that such customers, with revenues representing about 97% of the $46 million in annual wholesale revenues, agreed to negotiat- ed rate increases and signed contracts to remain as System customers for periods ranging from three to seven years. One customer representing the remaining 3% of annual revenues selected an 18-month contract at higher rates. In the event that this customer selects another supplier, the subsidiaries would retain transmission revenues with the result that any reduction in consolidated net income would not be significant.
Other revenues in 1995 also reflect an increase in standard transmission service revenues. See page 66 under Competition in Core Business for informa- tion about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the Federal Energy Regulatory Commission (FERC) in 1995. Effective in 1996, pursuant to the intentions of the Mega-NOPR, the subsidiaries eliminated their Standard Transmission Service tariff for new service transactions, and began using two new transmission service tariffs which qualify as required open access tariffs - - a Network tariff and a Point-to-Point tariff. The FERC accepted the filing of the new tariffs subject to hearings in the summer of 1996 and modification pending final Mega-NOPR rules. The subsidiaries are using the new tariffs in the interim, subject to refund. In addition, the subsidiaries have a Standard Generation Service tariff accepted by the FERC under which the subsidiaries make available bundled, nonfirm generation services with associated transmis- sion services. Substantially all of the benefits of these sales of transmis- sion and generation services to customers outside the service territory are passed through to retail customers and, as a result, have little effect on consolidated net income. While this procedure will continue to apply to similar sales under the new tariffs, the subsidiaries may petition to revise the procedure in the future.
Operating Expenses
The 7% decrease in fuel expenses in 1995 was primarily the result of renegotiations of long-term fuel contracts which reduced fuel prices effective in January 1995, and the ability to use lower-cost, high-sulfur coal at the Harrison Power Station because of the new scrubbers. 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 purchases from qualified facilities under PURPA, and is comprised of the following items:
The amount of power purchased from other utilities for use by subsidiaries and for resale to other utilities depends upon the availability of subsidiar- ies' 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 decrease in purchases from PURPA generation in 1995 was due primarily to a contractual reduction in the energy rate effective in June 1995 for the Grant Town PURPA project. American Bituminous Power Partners, L.P., the developer of the Grant Town project, has filed an emergency petition with the Public Service Commission of West Virginia for interim relief to have its former energy rate reinstated. Monongahela Power has filed objections to this petition. The increase in purchases from PURPA generation in 1994 reflects generation from the Grant Town PURPA project beginning in late 1993. As reported under Sales and Revenues, an agreement has been reached with a proposed facility to commence purchasing generation in 1999. This project and others may significantly increase the costs of power purchases passed on to customers. None of the subsidiaries' purchased power contracts is capitalized since there are no minimum payment requirements absent associated kWh generation. Other purchased power continued to increase in 1995 because of increased sales to retail customers and the availability of more economic energy. 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.
In January 1996, West Penn and the developers of a proposed Shannopin PURPA project reached agreement to terminate the project and all pending litigation, at a buy out price of $31 million. The agreement is subject to Pennsylvania Public Utility Commission (PUC) approval of recovery of the buy out price by West Penn by no later than March 31, 1999. The agreement was filed with the PUC in February 1996 along with a request for expedited approval.
The increase in other operation expense in 1995 resulted primarily from restructuring charges which are described in Note B to the consolidated financial statements on page 112. Additional restructuring charges will be incurred in 1996 as the subsidiaries complete their reengineering process. Other operation expense in 1996 and thereafter is expected to reflect the benefits of savings related to the restructuring activities. The 1994 increase in other operation expense 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 in 1994 due to an increase in aged outstanding receivables caused primarily by Pennsylvania rate regulations which make it difficult if not impossible to curtail service to non-paying customers. It is expected that the allowance for these uncollectible accounts will be increased in the future because of increasing accounts receivables in arrears. The increase in pension expense occurred because the subsidiaries in 1994 discontinued the practice of deferring pension expense in Pennsylvania and West Virginia to reflect rate case decisions in those states. Pension expense in 1994 also includes a charge of $3.1 million for write-off of prior deferrals in West Virginia because recovery of those deferrals was denied.
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, and the amount of work found necessary when the equipment is dismantled. Maintenance expense in 1995 includes a charge of about $7 million for inventory write-offs described in
Note B to the consolidated financial statements on page 112 and $3 million due to maintenance expense for the Harrison scrubbers which went into service in late 1994. Maintenance expense for the scrubbers is expected to increase since the warranty period has expired.
Depreciation expense increases resulted primarily from additions to electric plant. The subsidiaries began depreciating the Harrison scrubbers in mid-Nove- mber 1994, amounting to $32 million annually. Future depreciation expense increases for utility operations are expected to be less than historical increases because of reduced levels of proposed capital expenditures.
The increase in taxes other than income in 1995 and 1994 was due primarily to increases in gross receipts taxes resulting from higher revenues from retail customers. In 1995 this increase was offset in part by a decrease in West Virginia Business and Occupation (B&O) taxes resulting from an amendment in the B&O tax law effective June 1995, which changed the basis for this tax from generation to generating capacity.
The net increase of $24 million in federal and state income taxes in 1995 resulted primarily from an increase in income before taxes ($16 million) and an increase in reversals of prior year depreciation benefits for which deferred taxes were not then provided ($6 million). The net increase in 1994 of $2 million resulted primarily from an increase in income before taxes. Note C to the consolidated financial statements provides a further analysis of income tax expenses.
The combined decreases in allowances for funds used during construction in 1995 and 1994 of $11 million and $2 million, respectively, reflect decreases in construction expenditures upon substantial completion of the compliance program for Phase I of the CAAA. The increase in other income, net, of $5 million in 1995 was due primarily to income from demand-side management programs. During 1995, Potomac Edison continued its participation in the collaborative process for demand-side management in Maryland. Program costs, including lost revenues and rebates, are deferred as a regulatory asset and are being recovered through an energy conservation surcharge over a seven-year period. The balance in the regulatory asset for this program is $16 million as of December 31, 1995. Other income, net, in 1994 reflects 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.
In 1995 interest on long-term debt increased $14 million due primarily to the new security issues in 1994 and the timing of the refinancing of $245 million of first mortgage bonds and $93 million of pollution control revenue notes in 1995. Dividends on preferred stock decreased $5 million in 1995 due primarily to the redemption of preferred stock issues refinanced with $155.5 million of Quarterly Income Debt Securities. Other interest expense reflects changes in the levels of short-term debt maintained by the companies through- out the year, as well as the associated interest rates.
Environmental and Other Issues
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 in Liquidity and Capital Requirements. The CAAA, among other things, require an annual reduction in total utility emissions within the United States of 10 million tons of sulfur dioxide and two million tons of nitrogen oxides (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 and units reactivated in the future will be affected in Phase II. Installation of scrubbers at the Harrison Power Station was the strategy undertaken to meet the required SO[2] emission reductions for Phase I (1995-1999). Continuing
studies will determine the compliance strategy for Phase II (2000 and beyond). Studies to evaluate cost effective options to comply with Phase II SO[2] limits, including those which may be available from the use of the subsidiaries' banked emission allowances and from the emission allowance trading market, are continuing. It is expected that burner modifications at possibly all 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.
The subsidiaries previously reported that the Environmental Protection Agency had identified them and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. The subsidiaries have also been named as defendants along with multiple other defendants in pending asbestos cases involving one or more plaintiffs. The subsidiaries believe that provisions for liabilities and insurance recoveries are such that final resolution of these claims will not have a material effect on their financial position.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. SFAS No. 121 establishes standards for the impairment of long-lived assets and certain identifiable intangibles and requires companies to recognize an impairment loss if the expected future undiscounted cash flows are less than the carrying amount of an asset. The Company and its subsidiar- ies do not believe at this time that adoption of this standard will have a materially adverse effect on their financial position.
Financial Condition and Requirements Liquidity and Capital Requirements
To meet the System companies' need for cash for operating expenses, the payment of interest and dividends, retirement of debt and certain preferred stocks, and for their construction programs, the companies have used internal- ly 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.
Construction expenditures of the regulated subsidiaries in 1995 were $319 million and for 1996 and 1997 are estimated at $279 million and $305 million, respectively. In 1995, these expenditures included $36 million for compliance with the CAAA. The 1996 and 1997 estimated expenditures include $7 million and $20 million, respectively, for additional CAAA compliance costs. The Harrison scrubbers, which were constructed for compliance with Phase I of the CAAA, were completed on schedule in late 1994 and the final cost was approximately 24% below the original budget. Expenditures in the future to cover the costs of compliance with Phase II of the CAAA may be significant. Based on current forecasts and considering the reactivation of capacity in cold reserve, peak diversity exchange arrangements, demand-side management and conservation programs, and contracted PURPA capacity, it is not anticipated that the regulated subsidiaries will require new generating capacity until the year 2000 or beyond. The regulated subsidiaries also have additional capital requirements for debt maturities (see Note H to the consolidated financial statements). The Company will have additional capital requirements in the future related to nonutility investments of AYP Capital which are described under Nonutility Business on page 67.
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $281 million in 1995 compared with $246 million in 1994. Because of the new rate case authorizations effective in late 1994 and 1995 and reduced levels of capital expenditures, the regulated subsidiaries were able to finance approximately 88% of their capital expenditure program through internal cash generation in 1995, as compared to 48% in 1994. This ratio is expected to continue to increase over the next several years for utility investments. See page 67 for a description of future nonutility investments. Dividends paid on common stock in 1995 increased to $1.65 per share compared with $1.64 in 1994. However, the dividend payout ratio decreased from 88%, excluding the cumulative effect of the accounting change in 1994, to 83% in 1995.
As capital-intensive electric utilities, the regulated subsidiaries are affected by the rate of inflation. The inflation rate over the past several years has been relatively low and has not materially affected their financial position. However, since utility revenues are based on rate regulation that generally only recognizes historical costs, cash flows based on recovery of historical plant may not be adequate to replace plant in future years.
Fuel inventory provided a source of cash in 1995 ($12 million), primarily related to lower fuel prices attained through renegotiations of fuel contracts effective in January 1995 and the ability to use lower-cost, high-sulfur coal at the Harrison Power Station because of the new scrubbers. In 1994, fuel inventory represented a use of cash ($13 million) as it returned to a higher level after selective mine shutdowns during contract renegotiations in 1993. The decrease in operating and construction inventory in 1995 resulted from the write-off of obsolete and slow-moving inventory. In connection with ongoing restructuring activities and consolidation of facilities, the subsidiaries are reevaluating inventory management objectives to take advantage of centralized storerooms serving several facilities and to improve turnover ratios.
Financings
During 1995, the Company issued 1,407,855 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. The subsidiaries refinanced $338 million of debt securities with new debt securities having lower interest rates and refinanced preferred stock issues totaling $155.5 million with Quarterly Income Debt Securities (QUIDS). Under certain circum- stances the interest payments on QUIDS may be deferred for a period of up to 20 consecutive quarters. Debt redemption costs of refinancings are amortized over the life of the associated new securities. Due to the significant number of refinancings which have occurred over the past four years, this balance is now $57 million. Reduced future interest expense will more than offset these expenses. Preferred stock redemption costs of $5.5 million were charged directly to retained earnings.
Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. Short-term debt increased $74 million to $200 million in 1995. At December 31, 1995, unused lines of credit with banks were $173 million. In addition, a multi-year credit program established in 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 1995. During 1996, the subsidiaries anticipate meeting their capital requirements through a combination of internally generated funds, cash on hand, and short-term borrowing as necessary. 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. See page 67 for information on financing requirements for proposed nonutility investments.
Changes in the Electric Utility Industry
Competitive forces within the electric utility industry continued to increase in 1995. As in the past, utilities must compete for siting of new industrial and commercial customers and for retaining existing customers in the franchised territory. Electric utilities must also compete with suppliers of other forms of energy. Growing competitive challenges due to legislative, economic, and technological changes, and Allegheny Power's ability to meet these challenges, have been a major focal point in 1995.
Competition in Core Business
Competition in the wholesale market for electricity was enhanced by the National Energy Policy Act of 1992 (EPACT), which permits wholesale genera- tors, utility-owned and otherwise, and wholesale customers to request from owners of bulk power transmission facilities a commitment to supply transmis- sion services. EPACT is the first legislative action to permit wholesale customers within a utility's franchised service territory to seek alternative providers of energy.
The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995 which intends to stimulate wholesale competition among electric utilities and unregulated electricity generators. The Mega-NOPR encourages wholesale competition by requiring utilities to allow their transmission facilities to be used by sellers or buyers of wholesale power. The Mega-NOPR provides that electric utilities would be able to recover stranded costs (costs of facili- ties made uneconomic by wholesale transmission access). The FERC has not yet issued a final rulemaking on these issues.
State regulators in Ohio, Pennsylvania, and Virginia are in various stages of proceedings to evaluate the feasibility of retail competition. The Maryland commission has completed its investigation and issued an order which found that while competition in the electric wholesale market should be encouraged, retail competition is not in the public interest at this time. The regulated subsidiaries have filed responses in these proceedings which emphasize the need to move cautiously toward retail competition in order to protect the reliability of service to retail customers, and to insure that utilities without excess generating capacity, like the regulated subsidiaries, are not placed at a competitive disadvantage by permitting utilities with excess capacity to dump energy at low marginal cost while keeping their own customers captive through high stranded investment fees. Attempts at variations of retail wheeling have been authorized in some states, and various municipali- ties around the country that are not wholesale customers are exploring ways to become wholesale customers to obtain the ability to choose their electric supplier. In 1995, the Department of Defense proposed that it be granted competitive procurement rights for defense facilities.
Efforts to Maintain and Improve Competitive Position
The emerging competitive environment in generation and wholesale markets and the increasing possibility of retail competition have created greater planning uncertainty and risks for the Company. In response, the Company is continuing to develop a number of strategies to retain its existing customers and to expand its retail and wholesale customer base, including:
1. Restructuring its operations to maintain its relatively low-cost status by controlling costs and operating more efficiently
2. Implementing new marketing strategies
3. Increasing customer and energy services
4. Avoiding future rate increases
5. Expanding core business into nonutility activities (see below)
The Company believes it is taking necessary actions to position itself to meet current and future competitive challenges.
Nonutility Business
To help meet the challenges of the competitive environment in the electric utility industry, Allegheny Power is broadening its operations into nonutility businesses. In 1994, AYP Capital was formed to pursue opportunities in unregulated markets in order to strengthen the long-term competitiveness and profitability of the Company. AYP Capital's primary objectives are to develop new energy-related services businesses and to pursue wholesale unregulated power generation. The most significant project is an agreement with Duquesne Light Company to purchase for about $170 million its 50% interest (276 megawatts) in Unit No. 1 of the Fort Martin Power Station. The rest of the station is owned by the Company's regulated subsidiaries. AYP Capital intends to operate its share of the unit as an exempt wholesale generator and sell the output at market rates. After necessary approvals, AYP Capital expects a closing by late 1996. Various financing alternatives for this acquisition are being considered. Upon commencement of operations, AYP Capital will incur depreciation expense and other operating expenses related to Fort Martin.
AYP Capital has also committed to invest up to $10 million in two limited partnerships. AYP Capital has also invested in APS Cogenex, a joint venture limited liability company which provides services to improve the energy efficiency of consumer facilities in the five states in which Allegheny Power provides electric service plus the District of Columbia. AYP Capital intends to provide financing to consumers that undertake capital improvements necessary to achieve energy efficiency. AYP Capital will continue to evaluate investment opportunities with potentially significant additional capital investments in the future. AYP Capital's total investments as of December 31, 1995, were $1.1 million.
Although nonutility investments offer the potential for earning returns in excess of regulated investments, they generally involve a higher degree of risk. AYP Capital intends to manage these risks by diversifying its invest- ments and by investing where there is an appropriate balance of risk and reward.
The ability of AYP Capital to engage and compete in nonutility businesses will be impeded unless the Public Utility Holding Company Act of 1935 (PUHCA) is repealed or revised. PUHCA prevents or significantly disadvantages the Company and other non-exempt holding companies from diversifying into utility-related or nonutility businesses, a disadvantage not imposed on exempt holding companies and other competitors. The Company has been active in seeking repeal or reform of this law.
Monongahela MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Net Income
Net income in 1995 increased to $66.7 million compared with $59.9 million in 1994, excluding in 1994 the cumulative effect of an accounting change to record unbilled revenues. The increase resulted primarily from additional retail revenues due to increased kilowatt-hour (kWh) sales and previously reported rate increases. These revenue increases were offset in part by restructuring charges and inventory write-offs in 1995 of $3.3 million after tax and higher expenses. Net income in 1993 was $61.7 million. The decrease in 1994 resulted primarily from higher expenses, including taxes, pension expense, and depreciation.
Restructuring activities in 1995 were initiated by the System in response to the competitive environment emerging in the electric utility industry. The System, including the Company, is restructuring many of its functions to strengthen its competitive position and improve its cost structure. During 1995, reengineering of the Bulk Power Supply department in the affiliated Allegheny Power Service Corporation was substantially completed and process redesign is expected to be substantially completed in 1996 for the remainder of the System. Downsizing was not a specific goal of the restruc- turing efforts, but as a consequence of process redesign and elimination of duplicate positions, approximately 200 System employees have been placed in a staffing force pending reassignment or layoff. In addition, about 130 fewer System employees will be required in the power station work force by the end of 1997, and employee reductions are also likely to result from reengineering in other areas. The charges recorded in 1995 in connection with restructuring activities reflect estimated liabilities related to staffing force employees' separation costs, inventory write-offs in connection with changes in inventory management objectives, and certain other costs. It is expected that these costs will be recovered through future cost savings.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial customers are shown on pages 51 and 52. Such kWh sales increased 4.5% and 3.2% in 1995 and 1994, respectively. The increases in revenues from sales to residential, commercial, and industrial customers resulted from the following: Changes from Prior Year 1995 1994 (Millions of Dollars) Increased kWh sales.............................. $21.6 $ 3.8 Rate increases: West Virginia.................................. 17.1 7.9 Ohio........................................... .5 17.6 7.9 Fuel and energy cost adjustment clauses*......... (3.1) 13.0 Other............................................ .6 1.0 $36.7 $25.7
*Changes in revenues from fuel and energy cost adjustment clauses have little effect on net income.
The increase in kWh sales in 1995 was largely attributable to commercial and industrial sales. Industrial sales increased 3.5% and 6.1% in 1995 and 1994, respectively. The 6.5% increase in commercial sales in 1995 and the 1.2% increase in 1994 reflect growth in the number of customers and in 1995 also increased customer usage. These increases continue to reflect a trend of economic growth in the service territory. In 1995, the Company implemented a new Major Accounts Program which focuses on enhancing the working relationships with its largest customers. The goal of the program is to assure, through superior service, that the Company remains the energy supplier for these major customers.
Residential kWh sales increased 5.0% in 1995 and decreased .6% in 1994. The rate of growth in the number of residential customers has remained constant at 1% annually in 1995, 1994, and 1993. However, the impact of weather on customer usage continues to produce fluctuations in residential sales. In 1995, decreased sales due to mild weather in the first and second quarters were more than offset by extremely hot summer weather and cooler than normal winter weather in November and December as compared to 1994. The 1994 residential use was down slightly from 1993 levels reflecting a decrease in both heating and cooling degree days.
Rate case decisions in all jurisdictions, representing revenue increases in excess of $35 million on an annual basis, have been obtained. About $29 million became effective in 1994 and $6 million in Ohio became effective on November 9, 1995. 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. Additional base rate increases are not expected to be necessary for the next several years.
KWh sales to and revenues from nonaffiliated utilities are comprised of the following items:
1995 1994 1993 KWh sales (Billions): From Company generation................. .1 .3 .3 From purchased power.................... 3.1 2.1 2.8 3.2 2.4 3.1 Revenues (Millions): From Company generation................. $ 2.7 $ 7.7 $ 8.4 From sales of purchased power................................. 88.2 72.0 77.6 $90.9 $79.7 $86.0
Sales to nonaffiliated companies from the Company's generation in 1995 decreased because of growth in kWh sales to retail customers which reduced the amount available for sale and because of continuing price competition. The generation tax imposed in West Virginia, which in prior years was a signifi- cant factor affecting the Company's ability to compete in the market for sales to nonaffiliated companies, was favorably amended effective in June 1995 to change the basis of the tax from generation to generating capacity. Sales of purchased power vary depending on the availability of other companies'
generating equipment, demand for energy, and price competition. In the future, some of these transactions may be made under new transmission tariffs described below. About 90% of the aggregate benefits from sales to nonaffili- ated companies and to affiliates included in other revenues described below, are passed on to retail customers and have little effect on net income.
The decrease in other revenues in 1995 resulted primarily from a decrease in sales of energy and spinning reserve to affiliated companies, offset in part by increased revenues from wholesale customers (cooperatives and municipalities who own their own distribution systems and who buy all or part of their bulk power needs from the Company under regulation by the Federal Energy Regulatory Commission). Under the National Energy Policy Act of 1992, these customers obtained the ability to choose the bulk power supplier of their choice by the requirement that transmission-owning utilities must provide transmission service. In 1994, a rate case for wholesale customers was completed with the result that such customers, representing about $4.5 million in annual wholesale revenues, agreed to negotiated rate increases and signed contracts to remain as the Company's customers for five years. The increase in 1994 resulted from continued increases in sales of capacity, energy, and spinning reserve to affiliated companies because of additional capacity and energy available from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA).
Other revenues in 1995 also reflect an increase in standard transmis- sion service revenues. See page 76 under Competition in Core Business for information about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the Federal Energy Regulatory Commission (FERC) in 1995. Effective in 1996, pursuant to the intentions of the Mega-NOPR, the Company eliminated its Standard Transmission Service tariff for new service transactions, and began using two new transmission service tariffs which qualify as required open access tariffs - a Network tariff and a Point-to-Point tariff. The FERC accepted the filing of the new tariffs subject to hearings in the summer of 1996 and modification pending final Mega-NOPR rules. The Company is using the new tariffs in the interim, subject to refund. In addition, the Company has a Standard Generation Service tariff accepted by the FERC under which the Company makes available bundled, nonfirm generation services with associated transmission services. About 90% of the benefits of these sales of transmis- sion and generation services to customers outside the service territory are passed through to retail customers and as a result have little effect on net income. While this procedure will continue to apply to similar sales under the new tariffs, the Company may petition to revise the procedure in the future.
Operating Expenses
The 9% decrease in fuel expenses in 1995 was primarily the result of renegotiations of long-term fuel contracts which reduced fuel prices effective in January 1995, and the ability to use lower-cost, high-sulfur coal at the Harrison Power Station because of the new scrubbers. Fuel expenses increased 4% in 1994 due primarily to an increase 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 purchases from qualified facilities under PURPA, capacity charges paid to Allegheny Generating Company (AGC), an affiliate partially owned by the Company, and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and is comprised of the following items:
1995 1994 1993 (Millions of Dollars) Nonaffiliated transactions: Purchased power: For resale to other companies........ $ 79.1 $ 63.7 $ 68.6 From PURPA generation................ 64.6 68.3 55.7 Other................................ 11.6 9.4 8.1 Power exchanges, net................... .1 (.2) (.6) Affiliated transactions: AGC capacity charges................... 20.6 20.1 23.3 Energy and spinning reserve charges...................... .4 .5 .5 $176.4 $161.8 $155.6
The amount of power purchased from nonaffiliated companies for use by the Company and for resale to nonaffiliated companies 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 companies from which such purchases are made. The primary reason for the fluctuations in purchases for resale to nonaffiliated companies is described under Sales and Revenues above. The decrease in purchases from PURPA generation in 1995 was due primarily to a contractual reduction in the energy rate effective in June 1995 for the Grant Town PURPA project. American Bituminous Power Partners, L.P., the developer of the Grant Town project, has filed an emergency petition with the Public Service Commission of West Virginia for interim relief to have its former energy rate reinstated. The Company has filed objections to this petition. The increase in purchases from PURPA generation in 1994 reflects generation from the Grant Town PURPA project beginning in late 1993. None of the Company's purchased power contracts is capitalized since there are no minimum payment requirements absent associated kWh generation. Other purchased power continued to increase in 1995 because of increased sales to retail customers and the availability of more economic energy. 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 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 increase in other operation expense in 1995 resulted primarily from restructuring charges which are described in Note B to financial statements on page 125. Additional restructuring charges will be incurred in 1996 as the Company and its affiliates complete their reengineering process. Other operation expense in 1996 and thereafter is expected to reflect the benefits of savings related to the restructuring activities. The 1994 increase in other operation expense 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 pension expense in West Virginia to reflect a rate case decision in that state, and wrote off $2.5 million of prior deferrals in West Virginia because recovery of those deferrals was denied.
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, and the amount of work found necessary when the equipment is dismantled. Maintenance expense in 1995 includes a charge of about $1.4 million for inventory write-offs described in Note B to the financial statements on page 125. Maintenance expense for the Harrison scrubbers which went into service in late 1994 is expected to increase since the warranty period has expired.
The depreciation expense decrease in 1995 was the net result of a decrease in depreciation rates in West Virginia concurrent with the West Virginia base rate case effective in November 1994, offset by additions to electric plant. The Company began depreciating the Harrison scrubbers in mid- November 1994 amounting to approximately $8 million annually. 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.
The decrease in taxes other than income in 1995 was primarily due to a decrease in West Virginia Business and Occupation Taxes (B&O) resulting from an amendment in the B&O tax law effective June 1995, which changed the basis for this tax from generation to generating capacity. The 1994 increase in taxes other than income was primarily due to an increase in B&O taxes resulting from prior period adjustments recorded in 1993.
The net increase of $11 million in federal and state income taxes in 1995 resulted from an increase in income before taxes ($7 million) and changes in the provisions for prior years ($4 million). The net decrease in 1994 of $3 million resulted primarily from a decrease in income before taxes. Note C to the financial statements provides a further analysis of income tax expenses.
The combined decreases in allowances for borrowed and other than borrowed funds used during construction (AFUDC) in 1995 and 1994 of $2 million and $3 million, respectively, reflect decreases in construction expenditures upon substantial completion of the compliance program for Phase I of the CAAA. The increase in other income, net, of $1 million in 1995 reflects an increase in the deferral of carrying charges on CAAA expenditures in Ohio until the base rate increase became effective in November 1995, proceeds from the sale of timber, and interest income on a tax refund. The changes in other income,
net, in 1994 resulted primarily from the Company's share of earnings of AGC (see Note E to the financial statements).
In 1995, interest on long-term debt increased $2 million due primarily to the new security issues in 1994 and the timing of the refinancing of $70 million of first mortgage bonds and $25 million of pollution control revenue notes in 1995. The increase also reflects interest on $40 million of Quarterly Income Debt Securities issued in 1995 to refund preferred stock issues. 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.
Environmental and Other Issues
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 in Liquidity and Capital Requirements. The CAAA, among other things, require an annual reduction in total utility emissions within the United States of 10 million tons of sulfur dioxide (SO[2]) and two million tons of nitrogen oxides (NOx) from 1980 emission levels, to be completed in two phases, Phase I and Phase II. Four coal-fired Company plants are affected in Phase I and the remaining plants will be affected in Phase II. Installation of scrubbers at the Harrison Power Station was the strategy undertaken to meet the required SO[2] emission reductions for Phase I (1995-1999). Continuing studies will determine the compliance strategy for Phase II (2000 and beyond). Studies to evaluate cost effective options to comply with Phase II SO[2] limits, including those which may be available from the use of the Company's banked emission allowances and from the emission allowance trading market, are continuing. It is expected that burner modifications at possibly all 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 Pennsylvania (where the Company has ownership in a station) for ozone nonattainment (Title I) reasons. Continuous emission monitoring equipment has been installed on all Phase I and Phase II units.
The Company previously reported that the Environmental Protection Agency had identified the Company and its affiliates and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. The Company has also been named as a defendant along with multiple other affiliated and nonaffiliated defendants in pending asbestos cases involving one or more plaintiffs. The Company believes that provisions for liabilities and insurance recoveries are such that final resolution of these claims will not have a material effect on its financial position.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. SFAS No. 121 establishes standards for the impairment of long-lived assets and certain identifiable intangibles and
requires companies to recognize an impairment loss if the expected future undiscounted cash flows are less than the carrying amount of an asset. The Company does not believe at this time that adoption of this standard will have a materially adverse effect on its financial position.
FINANCIAL CONDITION AND REQUIREMENTS
Liquidity and Capital Requirements
To meet the Company's need for cash for operating expenses, the payment of interest and dividends, retirement of debt and certain preferred stocks, and for its construction program, 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.
Construction expenditures in 1995 were $75 million and for 1996 and 1997 are estimated at $66 million and $75 million, respectively. In 1995, these expenditures included $8 million for compliance with the CAAA. The 1996 and 1997 estimated expenditures include $2 million and $7 million, respective- ly, for additional CAAA compliance costs. The Harrison scrubbers, which were constructed for compliance with Phase I of the CAAA, were completed on schedule in late 1994 and the final cost was approximately 24% below the original budget. Expenditures in the future to cover the costs of compliance with Phase II of the CAAA may be significant. Based on current forecasts and considering peak diversity exchange arrangements, demand-side management and conservation programs, a power supply agreement with affiliates, and contract- ed PURPA capacity, it is not anticipated that the Company will require new generating capacity until the year 2000 or beyond. The Company also has additional capital requirements for 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 $93 million in 1995 compared with $67 million in 1994. Because of the new rate case authorizations effective in late 1994 and 1995 and reduced levels of capital expenditures, the Company was able to finance 100% of its capital expenditure program through internal cash generation in 1995, as compared to 64% in 1994. This ratio is expected to remain close to 100% over the next several years.
As a capital-intensive electric utility, the Company is affected by the rate of inflation. The inflation rate over the past several years has been relatively low and has not materially affected the Company's financial position. However, since utility revenues are based on rate regulation that generally only recognizes historical costs, cash flows based on recovery of historical plant may not be adequate to replace plant in future years.
Fuel inventory provided a source of cash in 1995 ($3 million), primarily related to lower fuel prices attained through renegotiations of fuel contracts effective in January 1995 and the ability to use lower-cost, high- sulfur coal at the Harrison Power Station because of the new scrubbers. In 1994, fuel inventory represented a use of cash ($4 million) as it returned to a higher level after selective mine shutdowns during contract renegotiations in 1993. The decrease in operating and construction inventory in 1995 resulted from the write-off of obsolete and slow-moving inventory. In connection with ongoing restructuring activities and consolidation of facilities, the Company is reevaluating inventory management objectives to take advantage of centralized storerooms serving several facilities and to improve turnover ratios.
Financings
During 1995, the Company refinanced $95 million of debt securities with new debt securities having lower interest rates and refinanced preferred stock issues totaling $40 million with Quarterly Income Debt Securities (QUIDS). Under certain circumstances the interest payments on QUIDS may be deferred for a period of up to 20 consecutive quarters. Debt redemption costs of refinancings are amortized over the life of the associated new securities. Due to the significant number of refinancings which have occurred over the past four years, this balance is now $16 million. Reduced future interest expense will more than offset these expenses. Preferred stock redemption costs of $1.4 million were charged directly to retained earnings.
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 $7 million to $30 million in 1995. At December 31, 1995, the Company had SEC authorization to issue up to $100 million of short-term debt. The Company and its affiliates use 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. In addition, a multi-year credit program established in 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 1995. During 1996, the Company anticipates meeting its capital require- ments through a combination of internally generated funds, cash on hand, and short-term borrowing as necessary. 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.
CHANGES IN THE ELECTRIC UTILITY INDUSTRY
Competitive forces within the electric utility industry continued to increase in 1995. As in the past, utilities must compete for siting of new industrial and commercial customers and for retaining existing customers in the franchised territory. Electric utilities must also compete with suppliers of other forms of energy. Growing competitive challenges due to legislative, economic, and technological changes, and the ability to meet these challenges, have been a major focal point in 1995.
Competition in Core Business
Competition in the wholesale market for electricity was enhanced by the National Energy Policy Act of 1992 (EPACT), which permits wholesale generators, utility-owned and otherwise, and wholesale customers to request from owners of bulk power transmission facilities a commitment to supply transmission services. EPACT was the first legislative action to permit wholesale customers within a utility's franchised service territory to seek alternative providers of energy.
The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995 which intends to stimulate wholesale competition among electric utilities and unregulated electricity generators. The Mega-NOPR encourages wholesale competition by requiring utilities to allow their transmission facilities to be used by sellers or buyers of wholesale power. The Mega-NOPR provides that electric utilities will be able to recover stranded costs (costs of facilities made uneconomic by wholesale transmission access). The FERC has not yet issued a final rulemaking on these issues.
The Public Utilities Commission of Ohio has initiated proceedings to evaluate the feasibility of retail competition. The Company has filed a response in this proceeding which emphasizes the need to move cautiously towards retail competition in order to protect the reliability of service to retail customers, and to insure that utilities without excess generating capacity, like the Company, are not placed at a competitive disadvantage by permitting utilities with excess capacity to dump energy at low marginal cost while keeping its own customers captive through high stranded investment fees. Attempts at variations of retail wheeling have been authorized in some states, and various municipalities around the country that are not wholesale customers are exploring ways to become wholesale customers to obtain the ability to choose their electric supplier. In 1995, the Department of Defense proposed that it be granted competitive procurement rights for defense facilities.
Efforts to Maintain and Improve Competitive Position
The emerging competitive environment in generation and wholesale markets and the increasing possibility of retail competition have created greater planning uncertainty and risks for the Company. In response, the Company is continuing to develop a number of strategies to retain its existing customers and to expand its retail and wholesale customer base, including:
1. Restructuring its operations to maintain its relatively low-cost status by controlling costs and operating more efficiently
2. Implementing new marketing strategies
3. Increasing customer and energy services
4. Avoiding future rate increases
The Company believes it is taking necessary actions to position itself to meet current and future competitive challenges.
Potomac Edison MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Net Income
Net income was $78.3 million in 1995 compared with $82.0 million in 1994, excluding in 1994 the cumulative effect of an accounting change to record unbilled revenues. The decrease resulted primarily from restructuring charges and inventory write-offs in 1995 of $4.3 million after tax and higher expenses offset in part by increased kilowatt-hour (kWh) sales and previously reported rate increases. Net income in 1993 was $73.5 million. The increase in 1994 resulted from an increase in kWh sales and revenue increases, offset in part by higher expenses.
Restructuring activities in 1995 were initiated by the System in response to the competitive environment emerging in the electric utility industry. The System, including the Company, is restructuring many of its functions to strengthen its competitive position and improve its cost structure. During 1995, reengineering of the Bulk Power Supply department in the affiliated Allegheny Power Service Corporation was substantially completed and process redesign is expected to be substantially completed in 1996 for the remainder of the System. Downsizing was not a specific goal of the restruc- turing efforts, but as a consequence of process redesign and elimination of duplicate positions, approximately 200 System employees have been placed in a staffing force pending reassignment or layoff. In addition, about 130 fewer System employees will be required in the power station work force by the end of 1997, and employee reductions are also likely to result from reengineering in other areas. The charges recorded in 1995 in connection with restructuring activities reflect estimated liabilities related to staffing force employees' separation costs, inventory write-offs in connection with changes in inventory management objectives, and certain other costs. It is expected that these costs will be recovered through future cost savings.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial customers are shown on pages 53 and 54. Such kWh sales increased 3.3% and 2.3% in 1995 and 1994, respectively. The increases in revenues from sales to residential, commercial, and industrial customers resulted from the following: Changes from Prior Year 1995 1994 (Millions of Dollars) Increased kWh sales.............................. $17.3 $10.3 Rate changes: Maryland....................................... 17.7 11.9 Virginia....................................... (1.8) 8.5 West Virginia.................................. 2.2 1.9 18.1 22.3 Fuel and energy cost adjustment clauses*............................ 3.2 18.6 Other............................................ (3.0) 1.0 $35.6 $52.2
*Changes in revenues from fuel and energy cost adjustment clauses have little effect on net income.
The increase in kWh sales in 1995 was in part attributable to industrial and commercial sales. Industrial sales increased 2.7% and 2.8% in 1995 and 1994, respectively. The 3.6% increase in commercial sales in 1995 and the 2.1% increase in 1994 reflect growth in the number of customers and in 1995 also increased customer usage. These increases continue to reflect a trend of economic growth in the service territory. In 1995 the Company implemented a new Major Accounts Program which focuses on enhancing the working relationships with its largest customers. The goal of the program is to assure, through superior service, that the Company remains the energy supplier for these major customers.
Residential kWh sales increased 3.9% in 1995 and 1.7% in 1994. The rate of growth in the number of residential customers has remained constant at about 2.1% annually in 1995, 1994, and 1993. However, the impact of weather on customer usage continues to produce fluctuations in residential sales. In 1995, decreased sales due to mild weather in the first and second quarters were more than offset by extremely hot summer weather and cooler than normal winter weather in November and December as compared to 1994. The 1994 residential use was down slightly from 1993 levels reflecting a decrease in both heating and cooling degree days.
Rate case decisions in all jurisdictions, representing revenue increases in excess of $35 million on an annual basis, have been obtained, most of them in late 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. Additional base rate increases are not expected to be necessary for the next several years. However, future purchased power expenses related to a qualified facility under the Public Utility Regulatory Policies Act of 1978 (PURPA), to be completed in late 1999, may make it necessary to increase rates at that time.
KWh sales to and revenues from nonaffiliated utilities are comprised of the following items:
1995 1994 1993 KWh sales (Billions): From Company generation............... .2 .3 .4 From purchased power.................. 4.2 2.9 3.5 4.4 3.2 3.9 Revenues (Millions): From Company generation............... $ 4.6 $ 8.9 $ 8.6 From sales of purchased power............................... 121.3 98.1 99.5 $125.9 $107.0 $108.1
Sales to nonaffiliated companies from the Company's generation in 1995 decreased because of growth in kWh sales to retail customers which reduced the amount available for sale and because of continuing price competition. The generation tax imposed in West Virginia, which in prior years was a signifi- cant factor affecting the Company's ability to compete in the market for sales to nonaffiliated companies, was favorably amended effective in June 1995 to change the basis of the tax from generation to generating capacity. Sales of purchased power vary depending on the availability of other companies' generating equipment, demand for energy, and price competition. In the future, some of these transactions may be made under new transmission tariffs described below. About 95% of the aggregate benefits from sales to nonaffili- ated companies are passed on to retail customers and have little effect on net income.
The increase in other revenues in 1995 resulted primarily from provisions recorded for rate refunds in 1994 and increased revenues from wholesale customers (cooperatives and municipalities who own their own distribution systems and who buy all or part of their bulk power needs from the Company under regulation by the Federal Energy Regulatory Commission). Under the National Energy Policy Act of 1992, these customers obtained the ability to choose the bulk power supplier of their choice by the requirement that transmission-owning utilities must provide transmission service. In June 1995, rate cases for wholesale customers were completed with the result that such customers, with revenues representing about 94% of the $23.4 million in annual wholesale revenues, agreed to negotiated rate increases of about $2.1 million, and signed three-year contracts to remain as Company customers. One customer representing the remaining 6% of annual revenues selected an 18-month contract at higher rates. In the event that this customer was to select another supplier, the Company would retain transmission revenues with the result that any reduction in net income would not be significant. 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. The refunds were completed in 1995.
Other revenues in 1995 also reflect an increase in standard transmis- sion service revenues. See page 85 under Competition in Core Business for information about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the Federal Energy Regulatory Commission (FERC) in 1995. Effective in 1996, pursuant to the intentions of the Mega-NOPR, the Company eliminated its Standard Transmission Service tariff for new service transactions, and began using two new transmission service tariffs which qualify as required open access tariffs - a Network tariff and Point-to- Point tariff. The FERC accepted the filing of the new tariffs subject to hearings in the summer of 1996 and modification pending final Mega-NOPR rules. The Company is using the new tariffs in the interim, subject to refund. In addition, the Company has a Standard Generation Service tariff accepted by the FERC under which the Company makes available bundled, nonfirm generation services with associated transmission services. About 95% of the benefits of these sales of transmis- sion and generation services to customers outside the service territory are passed through to retail customers and as a result have little effect on net income. While this procedure will continue to apply to similar sales under the new tariffs, the Company may petition to revise the procedure in the future.
Operating Expenses
The 7% decrease in fuel expenses in 1995 was primarily the result of renegotiations of long-term fuel contracts which reduced fuel prices effective in January 1995, and the ability to use lower-cost, high-sulfur coal at the Harrison Power Station because of the new scrubbers. 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), an affiliate partially owned by the Company, and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and is comprised of the following items:
1995 1994 1993 (Millions of Dollars) Nonaffiliated transactions: Purchased power: For resale to other companies........ $108.5 $ 86.5 $ 87.9 Other................................ 15.4 12.7 10.5 Power exchanges, net................... (.2) (.2) (.8) Affiliated transactions: AGC capacity charges................... 28.1 29.4 28.0 Other affiliated capacity charges...... 45.6 37.6 28.4 Energy and spinning reserve charges...................... 48.2 51.1 51.1 $245.6 $217.1 $205.1
The amount of power purchased from nonaffiliated companies for use by the Company and for resale to nonaffiliated companies 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
companies from which such purchases are made. The primary reason for the fluctuations in purchases for resale to nonaffiliated companies is described under Sales and Revenues above. Other purchased power continued to increase in 1995 because of increased sales to retail customers and the availability of more economic energy. The increase in affiliated capacity in 1995 and 1994 was due to growth of kWh sales to retail customers. 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 subject to deferred power cost procedures with the result that changes in such costs have little effect on net income.
While the Company does not currently purchase generation from qualified facilities under PURPA, it will be required to do so in 1999 because of a PURPA facility which is then scheduled to commence operations. This project may significantly increase the cost of power purchases passed on to customers.
The increase in other operation expense in 1995 resulted primarily from restructuring charges which are described in Note B to the financial statements on page 140. Additional restructuring charges will be incurred in 1996 as the Company and its affiliates complete their reengineering process. Other operation expense in 1996 and thereafter is expected to reflect the benefits of savings related to the restructuring activities. The 1994 increase in other operation expense 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. The increase in pension expense occurred because the Company in 1994 discontinued the practice of deferring pension expense in West Virginia to reflect a rate case decision in that state, and wrote off $.9 million of prior deferrals in Virginia and West Virginia because recovery of those deferrals was denied.
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, and the amount of work found necessary when the equipment is dismantled. Maintenance expense in 1995 includes a charge of about $2 million for inventory write-offs described in Note B to the financial statements on page 140. Maintenance expense for the Harrison scrubbers which went into service in late 1994 is expected to increase since the warranty period has expired.
Depreciation expense increases resulted primarily from additions to electric plant. The Company began depreciating the Harrison scrubbers in mid- November 1994 amounting to approximately $10 million annually. Future depreciation expense increases for utility operations are expected to be less than historical increases because of reduced levels of proposed capital expenditures.
The net increase of $4 million in federal and state income taxes in 1995 resulted primarily from an increase in reversals of prior year deprecia- tion benefits for which deferred taxes were not then provided. The net increase of $3 million in federal and state income taxes in 1994 resulted primarily from an increase in income before taxes. Note C to the financial statements provides a further analysis of income tax expenses.
The combined decreases in allowances for borrowed and other than borrowed funds used during construction (AFUDC) in 1995 and 1994 of $4 million and $1 million, respectively, reflect decreases in construction expenditures upon substantial completion of the compliance program for Phase I of the CAAA. The increase in other income, net, of $2 million in 1995 was due primarily to income from demand-side management programs. During 1995, the Company continued its participation in the collaborative process for demand-side management in Maryland. Program costs, including lost revenues and rebates, are deferred as a regulatory asset and are being recovered through an energy conservation surcharge over a seven-year period. The balance in the regulato- ry asset for this program is $16 million as of December 31, 1995. The increase in other income, net, in 1994 resulted primarily from the Company's share of earnings of AGC (see Note E to the financial statements) and income from demand-side management programs.
In 1995 interest on long-term debt increased $4 million due primarily to the new security issues in 1994 and the timing of the refinancing of $145 million of first mortgage bonds and $21 million of pollution control revenue notes in 1995. The increase also reflects interest on $45.5 million of Quarterly Income Debt Securities issued in 1995 to refund preferred stock issues. 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.
Environmental and Other Issues
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 in Liquidity and Capital Requirements. The CAAA, among other things, require an annual reduction in total utility emissions within the United States of 10 million tons of sulfur dioxide (SO[2]) and two million tons of nitrogen oxides (NOx) from 1980 emission levels, to be completed in two phases, Phase I and Phase II. Three coal-fired Company plants are affected in Phase I and the remaining plants will be affected in Phase II. Installation of scrubbers at the Harrison Power Station was the strategy undertaken to meet the required SO[2] emission reductions for Phase I (1995-1999). Continuing studies will
determine the compliance strategy for Phase II (2000 and beyond). Studies to evaluate cost effective options to comply with Phase II SO[2] limits, including those which may be available from the use of the Company's banked emission allowances and from the emission allowance trading market, are continuing. It is expected that burner modifications at possibly all 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 (where the Company has ownership in a station) for ozone nonattainment (Title I) reasons. Continuous emission monitoring equipment has been installed on all Phase I and Phase II units.
The Company previously reported that the Environmental Protection Agency had identified the Company and its affiliates and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. The Company has also been named as a defendant along with multiple other affiliated and nonaffiliated defendants in pending asbestos cases involving one or more plaintiffs. The Company believes that provisions for liabilities and insurance recoveries are such that final resolution of these claims will not have a material effect on its financial position.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. SFAS No. 121 establishes standards for the impairment of long-lived assets and certain identifiable intangibles and requires companies to recognize an impairment loss if the expected future undiscounted cash flows are less than the carrying amount of an asset. The Company does not believe at this time that adoption of this standard will have a materially adverse effect on its financial position.
FINANCIAL CONDITION AND REQUIREMENTS
Liquidity and Capital Requirements
To meet the Company's need for cash for operating expenses, the payment of interest and dividends, retirement of debt and certain preferred stocks, and for its construction program, 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.
Construction expenditures in 1995 were $92 million and for 1996 and 1997 are estimated at $87 million and $103 million, respectively. In 1995, these expenditures included $9 million for compliance with the CAAA. The 1996 and 1997 estimated expenditures include $1 million and $2 million, respective- ly, for additional CAAA compliance costs. The Harrison scrubbers, which were
constructed for compliance with Phase I of the CAAA, were completed on schedule in late 1994 and the final cost was approximately 24% below the original budget. Expenditures in the future to cover the costs of compliance with Phase II of the CAAA may be significant. Based on current forecasts and considering peak diversity exchange arrangements, demand-side management and conservation programs, a power supply agreement with affiliates, and contract- ed PURPA capacity, it is not anticipated that the Company will require new generating capacity until the year 2000 or beyond. The Company also has additional capital requirements for 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 $85 million in 1995 compared with $67 million in 1994. Because of the new rate case authorizations effective in late 1994 and 1995 and reduced levels of capital expenditures, the Company was able to finance approximately 92% of its capital expenditure program through internal cash generation in 1995, as compared to 47% in 1994. This ratio is expected to continue to increase over the next several years.
As a capital-intensive electric utility, the Company is affected by the rate of inflation. The inflation rate over the past several years has been relatively low and has not materially affected the Company's financial position. However, since utility revenues are based on rate regulation that generally only recognizes historical costs, cash flows based on recovery of historical plant may not be adequate to replace plant in future years.
Fuel inventory provided a source of cash in 1995 ($3 million), primarily related to lower fuel prices attained through renegotiations of fuel contracts effective in January 1995 and the ability to use lower-cost, high- sulfur coal at the Harrison Power Station because of the new scrubbers. In 1994, fuel inventory represented a use of cash ($4 million) as it returned to a higher level after selective mine shutdowns during contract renegotiations in 1993. The decrease in operating and construction inventory in 1995 resulted from the write-off of obsolete and slow-moving inventory. In connection with ongoing restructuring activities and consolidation of facilities, the Company is reevaluating inventory management objectives to take advantage of centralized storerooms serving several facilities and to improve turnover ratios.
Financings
During 1995, the Company refinanced $166 million of debt securities with new debt securities having lower interest rates and refinanced preferred stock issues totaling $45.5 million with Quarterly Income Debt Securities (QUIDS). Under certain circumstances the interest payments on QUIDS may be deferred for a period of up to 20 consecutive quarters. Debt redemption costs of refinancings are amortized over the life of the associated new securities. Due to the significant number of refinancings which have occurred over the past four years, this balance is now $19 million. Reduced future interest expense will more than offset these expenses. Preferred stock redemption costs of $2.0 million were charged directly to retained earnings.
Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. Short-term debt increased to $22 million in 1995. At December 31, 1995, the Company had SEC authorization to issue up to $115 million of short-term debt. The Company and its affiliates use 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. In addition, a multi-year credit program established in 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 1995. During 1996, the Company anticipates meeting its capital require- ments through a combination of internally generated funds, cash on hand, and short-term borrowing as necessary. 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.
CHANGES IN THE ELECTRIC UTILITY INDUSTRY
Competitive forces within the electric utility industry continued to increase in 1995. As in the past, utilities must compete for siting of new industrial and commercial customers and for retaining existing customers in the franchised territory. Electric utilities must also compete with suppliers of other forms of energy. Growing competitive challenges due to legislative, economic, and technological changes, and the ability to meet these challenges, have been a major focal point in 1995.
Competition in Core Business
Competition in the wholesale market for electricity was enhanced by the National Energy Policy Act of 1992 (EPACT), which permits wholesale generators, utility-owned and otherwise, and wholesale customers to request from owners of bulk power transmission facilities a commitment to supply transmission services. EPACT was the first legislative action to permit wholesale customers within a utility's franchised service territory to seek alternative providers of energy.
The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995 which intends to stimulate wholesale competition among electric utilities and unregulated electricity generators. The Mega-NOPR encourages wholesale competition by requiring utilities to allow their transmission facilities to be used by sellers or buyers of wholesale power. The Mega-NOPR provides that electric utilities will be able to recover stranded costs (costs of facilities made uneconomic by wholesale transmission access). The FERC has not yet issued a final rulemaking on these issues.
The Virginia commission is conducting proceedings to evaluate the feasibility of retail competition. The Maryland commission has completed its investigation and issued an order which found that while competition in the electric wholesale market should be encouraged, retail competition is not in the public interest at this time. The Company has filed responses in these proceedings which emphasize the need to move cautiously toward retail competition in order to protect the reliability of service to retail custom- ers, and to insure that utilities without excess generating capacity, like the
Company, are not placed at a competitive disadvantage by permitting utilities with excess capacity to dump energy at low marginal cost while keeping its own customers captive through high stranded investment fees. Attempts at variations of retail wheeling have been authorized in some states, and various municipalities around the country that are not wholesale customers are exploring ways to become wholesale customers to obtain the ability to choose their electric supplier. In 1995, the Department of Defense proposed that it be granted competitive procurement rights for defense facilities.
Efforts to Maintain and Improve Competitive Position
The emerging competitive environment in generation and wholesale markets and the increasing possibility of retail competition have created greater planning uncertainty and risks for the Company. In response, the Company is continuing to develop a number of strategies to retain its existing customers and to expand its retail and wholesale customer base, including:
1. Restructuring its operations to maintain its relatively low-cost status by controlling costs and operating more efficiently
2. Implementing new marketing strategies
3. Increasing customer and energy services
4. Avoiding future rate increases
The Company believes it is taking necessary actions to position itself to meet current and future competitive challenges.
West Penn MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Consolidated Net Income
Consolidated net income in 1995 increased to $117.9 million compared with $101.0 in 1994, excluding in 1994 the cumulative effect of an accounting change to record unbilled revenues. The increase resulted primarily from additional retail revenues due to increased kilowatt-hour (kWh) sales and previously reported rate increases. These revenue increases were offset in part by restructuring charges and inventory write-offs in 1995 of $6.5 million after tax and higher expenses. Earnings in 1994 included a charge of $5.2 million after tax related to asset write-offs. Consolidated net income in 1993 was $102.1 million. Consolidated net income in 1994 reflects higher retail revenues from increased kWh sales and rate increases, offset in part by higher expenses.
Restructuring activities in 1995 were initiated by the System in response to the competitive environment emerging in the electric utility industry. The System, including the Company, is restructuring many of its functions to strengthen its competitive position and improve its cost structure. During 1995, reengineering of the Bulk Power Supply department in the affiliated Allegheny Power Service Corporation was substantially completed and process redesign is expected to be substantially completed in 1996 for the remainder of the System. Downsizing was not a specific goal of the restruc- turing efforts, but as a consequence of process redesign and elimination of duplicate positions, approximately 200 System employees have been placed in a staffing force pending reassignment or layoff. In addition, about 130 fewer System employees will be required in the power station work force by the end of 1997, and employee reductions are also likely to result from reengineering in other areas. The charges recorded in 1995 in connection with restructuring activities reflect estimated liabilities related to staffing force employees' separation costs, inventory write-offs in connection with changes in inventory management objectives, and certain other costs. It is expected that these costs will be recovered through future cost savings.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial customers are shown on pages 55 and 56. Such kWh sales increased 4.0% and 2.9% in 1995 and 1994, respectively. The increases in revenues from sales to residential, commercial, and industrial customers resulted from the following: Changes from Prior Year 1995 1994 (Millions of Dollars)
Increased kWh sales.............................. $17.3 $ 9.4 Rate increases................................... 50.2 22.7 Fuel and energy cost adjustment clauses*......... (2.9) 16.8 Other............................................ 3.0 2.3 $67.6 $51.2
*Changes in revenues from fuel and energy cost adjustment clauses have little effect on consolidated net income.
The increase in kWh sales in 1995 was largely attributable to industrial and commercial sales. Industrial sales increased 5.8% and 4.4% in 1995 and 1994, respectively. The 4.4% increase in commercial sales in 1995 and the 2.9% increase in 1994 reflect growth in the number of customers and increased customer usage. These increases continue to reflect a trend of economic growth in the service territory. In 1995 the Company implemented a new Major Accounts Program which focuses on enhancing the working relation- ships with its largest customers. The goal of the program is to assure, through superior service, that the Company remains the energy supplier for these major customers.
Residential kWh sales increased 1.4% in 1995 and 1.1% in 1994 due to growth in number of customers and higher usage. The rate of growth in the number of residential customers has remained constant at just under 1% annually in 1995, 1994, and 1993. However, the impact of weather on customer usage continues to produce fluctuations in residential sales. In 1995, decreased sales due to mild weather in the first and second quarters were more than offset by extremely hot summer weather and cooler than normal winter weather in November and December as compared to 1994. Residential usage increased in 1994 despite a decrease in both heating and cooling degree days.
Rate case decisions, representing revenue increases in excess of $57 million on an annual basis, have been obtained effective in late 1994. These included recovery of the remaining carrying charges on investment, deprecia- tion, 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. Additional base rate increases are not expected to be necessary for the next several years.
KWh sales to and revenues from nonaffiliated utilities are comprised of the following items:
1995 1994 1993 KWh sales (Billions): From Company generation................. .2 .5 .4 From purchased power.................... 5.7 3.8 5.0 5.9 4.3 5.4 Revenues (Millions): From Company generation................. $ 5.7 $ 12.3 $ 11.5 From sales of purchased power........... 162.5 132.5 141.0 $168.2 $144.8 $152.5
Sales to nonaffiliated companies from the Company's generation in 1995 decreased because of growth in kWh sales to retail customers which reduced the amount available for sale and because of continuing price competition. The generation tax imposed in West Virginia, which in prior years was a signifi- cant factor affecting the Company's ability to compete in the market for sales to nonaffiliated companies, was favorably amended effective in June 1995 to change the basis of the tax from generation to generating capacity. Sales of purchased power vary depending on the availability of other companies' generating equipment, demand for energy, and price competition. In the
future, some of these transactions may be made under new transmission tariffs described below. Most of the aggregate benefits from sales to nonaffiliated companies and sales of energy and spinning reserve to affiliates included in other revenues described below, are passed on to retail customers and have little effect on consolidated net income.
The increase in other revenues in 1995 resulted primarily from an increase in sales of capacity, energy, and spinning reserve to other affiliat- ed companies. About $18 million of other revenues in 1995 were derived from wholesale customers (cooperatives and municipalities who own their own distribution systems and who buy all or part of their bulk power needs from the Company under regulation by the Federal Energy Regulatory Commission). Under the National Energy Policy Act of 1992, these customers obtained the ability to choose the bulk power supplier of their choice by the requirement that transmission-owning utilities must provide transmission service. In 1994, a rate case for wholesale customers was completed with the result that such customers agreed to negotiated rate increases and signed seven-year contracts to remain as Company customers.
Other revenues in 1995 also reflect an increase in standard transmis- sion service revenues. See page 94 under Competition in Core Business for information about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the Federal Energy Regulatory Commission (FERC) in 1995. Effective in 1996, pursuant to the intentions of the Mega-NOPR, the Company eliminated its Standard Transmission Service tariff for new service transactions, and began using two new transmission service tariffs which qualify as required open access tariffs - a Network tariff and a Point-to-Point tariff. The FERC accepted the filing of the new tariffs subject to hearings in the summer of 1996 and modification pending final Mega-NOPR rules. The Company is using the new tariffs in the interim, subject to refund. In addition, the Company has a Standard Generation Service tariff accepted by the FERC under which the Company makes available bundled, nonfirm generation services with associated transmission services. Most of the benefits of these sales of transmission and generation services to customers outside the service territory are passed through to retail customers and as a result have little effect on consolidated net income. While this procedure will continue to apply to similar sales under the new tariffs, the Company may petition to revise the procedure in the future.
Operating Expenses
The 6% decrease in fuel expenses in 1995 was primarily the result of renegotiations of long-term fuel contracts which reduced fuel prices effective in January 1995, and the ability to use lower-cost, high-sulfur coal at the Harrison Power Station because of the new scrubbers. Fuel expenses decreased 2% in 1994 due primarily to a decrease 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 companies and purchases from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA), capacity charges paid to Allegheny Generating Company (AGC), an affiliate partially owned by the Company, and other transactions with affiliates made
pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and is comprised of the following items:
1995 1994 1993 (Millions of Dollars) Nonaffiliated transactions: Purchased power: For resale to other companies........ $145.4 $116.9 $124.5 From PURPA generation................ 64.7 65.7 49.6 Other................................ 21.6 18.3 15.2 Power exchanges, net................... (.1) (.2) (1.2) Affiliated transactions: AGC capacity charges................... 37.8 37.2 42.3 Energy and spinning reserve charges...................... 4.6 8.6 4.7 Other affiliated capacity charges...... .7 .7 .7 $274.7 $247.2 $235.8
The amount of power purchased from nonaffiliated companies for use by the Company and for resale to nonaffiliated companies 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 companies from which such purchases are made. The primary reason for the fluctuations in purchases for resale to nonaffiliated companies is described under Sales and Revenues above. The reduced level of 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. Other purchased power continued to increase in 1995 because of increased sales to retail customers and the availability of more economic energy. The cost of power 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 Pennsylvania Public Utility Commission (PUC), and is primarily subject to deferred power cost procedures with the result that changes in such costs have little effect on consolidated net income.
In January 1996, the Company and the developers of a proposed Shannopin PURPA project reached agreement to terminate the project and all pending litigation, at a buy out price of $31 million. The agreement is subject to PUC approval of recovery of the buy out price by the Company by no later than March 31, 1999. The agreement was filed with the PUC in February 1996 along with a request for expedited approval.
The increase in other operation expense in 1995 resulted primarily from restructuring charges which are described in Note B to the consolidated financial statements on page 157. Additional restructuring charges will be incurred in 1996 as the Company and its affiliates complete their reengineeri- ng process. Other operation expense in 1996 and thereafter is expected to reflect the benefits of savings related to the restructuring activities. The 1994 increase in other operation expense 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 in 1994 due to an increase in aged outstanding receivables caused primarily by Pennsylvania rate regulations which make it difficult if not impossible to curtail service to non-paying customers. It is expected that the allowance for these uncollectible accounts will be increased in the future because of increasing accounts receivable in arrears. The increase in pension expense occurred because the Company in 1994 discontinued the practice of deferring pension expense to reflect a rate case decision.
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, and the amount of work found necessary when the equipment is dismantled. Maintenance expense in 1995 includes a charge of about $4 million for inventory write- offs described in Note B to the consolidated financial statements on page 157. Maintenance expense for the Harrison scrubbers which went into service in late 1994 is expected to increase since the warranty period has expired.
Depreciation expense increases resulted primarily from additions to electric plant and from a change in depreciation rates. The Company began depreciating the Harrison scrubbers in mid-November 1994 amounting to approximately $14 million annually. Future depreciation expense increases are expected to be less than historical increases because of reduced levels of proposed capital expenditures.
The increase in taxes other than income in 1995 was due primarily to an increase in gross receipts taxes resulting from higher revenues from retail customers. 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 ($2 million).
The net increase of $11 million in federal and state income taxes in 1995 resulted primarily from an increase in income before taxes. The net decrease in 1994 of $1 million resulted primarily from plant removal cost tax deductions for which deferred taxes were not provided. Note C to the consolidated financial statements provides a further analysis of income tax expenses.
The combined decrease in allowances for borrowed and other than borrowed funds used during construction (AFUDC) in 1995 of $6 million reflects decreases in construction expenditures upon substantial completion of the compliance program for Phase I of the CAAA. The increase of $2 million in AFUDC in 1994 reflects increased construction expenditures, including those associated with the CAAA, net of CAAA amounts included in rate base and earning a cash return. Other income, net, in 1994 reflects 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.
In 1995, interest on long-term debt increased $6 million due primarily to the new security issues in 1994 and the timing of the refinancing of $30 million of first mortgage bonds and $47 million of pollution control revenue notes in 1995. The increase also reflects interest on $70 million of Quarterly Income Debt Securities issued in 1995 to refund preferred stock issues. 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.
Environmental and Other Issues
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 in Liquidity and Capital Requirements. The CAAA, among other things, require an annual reduction in total utility emissions within the United States of 10 million tons of sulfur dioxide (SO[2]) and two million tons of nitrogen oxides (NO[x]) from 1980 emission levels, to be completed in two phases, Phase I and Phase II. Four coal-fired Company plants are affected in Phase I and the remaining plants and units reactivated in the future will be affected in Phase II. Installation of scrubbers at the Harrison Power Station was the strategy undertaken to meet the required SO[2] emission reductions for Phase I (1995- 1999). Continuing studies will determine the compliance strategy for Phase II (2000 and beyond). Studies to evaluate cost effective options to comply with Phase II SO[2] limits, including those which may be available from the use of the Company's banked emission allowances and from the emission allowance trading market, are continuing. It is expected that burner modifications at possibly all stations will satisfy the NO[x] emission reduction requirements for the acid rain (Title IV) provisions of the CAAA. Additional post- combustion controls may be mandated in Pennsylvania for ozone nonattainment (Title I) reasons. Continuous emission monitoring equipment has been installed on all Phase I and Phase II units.
The Company previously reported that the Environmental Protection Agency had identified the Company and its affiliates and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. The Company has also been named as a defendant along with multiple other affiliated and nonaffiliated defendants in pending asbestos cases involving one or more plaintiffs. The Company believes that provisions for liabilities and insurance recoveries are such that final resolution of these claims will not have a material effect on its financial position.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. SFAS No. 121 establishes standards for the impairment of long-lived assets and certain identifiable intangibles and requires companies to recognize an impairment loss if the expected future undiscounted
cash flows are less than the carrying amount of an asset. The Company does not believe at this time that adoption of this standard will have a materially adverse effect on its financial position.
FINANCIAL CONDITION AND REQUIREMENTS
Liquidity and Capital Requirements
To meet the Company's need for cash for operating expenses, the payment of interest and dividends, retirement of debt and certain preferred stocks, and for its construction program, 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.
Construction expenditures in 1995 were $149 million and for 1996 and 1997 are estimated at $125 million and $126 million, respectively. In 1995, these expenditures included $19 million for compliance with the CAAA. The 1996 and 1997 estimated expenditures include $4 million and $10 million, respectively, for additional CAAA compliance costs. The Harrison scrubbers, which were constructed for compliance with Phase I of the CAAA, were completed on schedule in late 1994 and the final cost was approximately 24% below the original budget. Expenditures in the future to cover the costs of compliance with Phase II of the CAAA may be significant. Based on current forecasts and considering the reactivation of capacity in cold reserve, peak diversity exchange arrangements, demand-side management and conservation programs, a power supply agreement with affiliates, and contracted PURPA capacity, it is not anticipated that the Company will require new generating capacity until the year 2000 or beyond. The Company also has additional capital requirements for 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 $110 million in 1995 compared with $109 million in 1994. Because of the new rate case authorizations effective in late 1994 and reduced levels of capital expenditures, the Company was able to finance approximately 74% of its capital expenditure program through internal cash generation in 1995, as compared to 42% in 1994. This ratio is expected to continue to increase over the next several years.
As a capital-intensive electric utility, the Company is affected by the rate of inflation. The inflation rate over the past several years has been relatively low and has not materially affected the Company's financial position. However, since utility revenues are based on rate regulation that generally only recognizes historical costs, cash flows based on recovery of historical plant may not be adequate to replace plant in future years.
Fuel inventory provided a source of cash in 1995 ($6 million), primarily related to lower fuel prices attained through renegotiations of fuel
contracts effective in January 1995 and the ability to use lower-cost, high- sulfur coal at the Harrison Power Station because of the new scrubbers. In 1994, fuel inventory represented a use of cash ($5 million) as it returned to a higher level after selective mine shutdowns during contract renegotiations in 1993. The decrease in operating and construction inventory in 1995 resulted from the write-off of obsolete and slow-moving inventory. In connection with ongoing restructuring activities and consolidation of facilities, the Company is reevaluating inventory management objectives to take advantage of centralized storerooms serving several facilities and to improve turnover ratios.
Financings
During 1995, the Company refinanced $77 million of debt securities with new debt securities having lower interest rates and refinanced preferred stock issues totaling $70 million with Quarterly Income Debt Securities (QUIDS). Under certain circumstances the interest payments on QUIDS may be deferred for a period of up to 20 consecutive quarters. Debt redemption costs of refinancings are amortized over the life of the associated new securities. Due to the significant number of refinancings which have occurred over the past four years, this balance is now $12 million. Reduced future interest expense will more than offset these expenses. Preferred stock redemption costs of $2.2 million were charged directly to retained earnings.
Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. Short-term debt increased to $70 million in 1995. At December 31, 1995, the Company had SEC authorization to issue up to $170 million of short-term debt. The Company and its affiliates use 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. In addition, a multi-year credit program established in 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 1995. During 1996, the Company anticipates meeting its capital require- ments through a combination of internally generated funds, cash on hand, and short-term borrowings as necessary. 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.
CHANGES IN THE ELECTRIC UTILITY INDUSTRY
Competitive forces within the electric utility industry continued to increase in 1995. As in the past, utilities must compete for siting of new industrial and commercial customers and for retaining existing customers in the franchised territory. Electric utilities must also compete with suppliers of other forms of energy. Growing competitive challenges due to legislative, economic, and technological changes, and the ability to meet these challenges, have been a major focal point in 1995.
Competition in Core Business
Competition in the wholesale market for electricity was enhanced by the National Energy Policy Act of 1992 (EPACT), which permits wholesale generators, utility-owned and otherwise, and wholesale customers to request from owners of bulk power transmission facilities a commitment to supply transmission services. EPACT was the first legislative action to permit wholesale customers within a utility's franchised service territory to seek alternative providers of energy.
The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995 which intends to stimulate wholesale competition among electric utilities and unregulated electricity generators. The Mega-NOPR encourages wholesale competition by requiring utilities to allow their transmission facilities to be used by sellers or buyers of wholesale power. The Mega-NOPR provides that electric utilities will be able to recover stranded costs (costs of facilities made uneconomic by wholesale transmission access). The FERC has not yet issued a final rulemaking on these issues.
The Pennsylvania PUC has begun an investigation into electric power competition. The PUC staff issued a report advising against instituting retail wheeling at this time. The Company has filed a response to this investigation which emphasizes the need to move cautiously toward retail competition in order to protect the reliability of service to retail custom- ers, and to insure that utilities without excess generating capacity, like the Company, are not placed at a competitive disadvantage by permitting utilities with excess capacity to dump energy at low marginal cost while keeping their own customers captive through high stranded investment fees. Attempts at variations of retail wheeling have been authorized in some states, and various municipalities around the country that are not wholesale customers are exploring ways to become wholesale customers to obtain the ability to choose their electric supplier. In 1995, the Department of Defense proposed that it be granted competitive procurement rights for defense facilities.
Efforts to Maintain and Improve Competitive Position
The emerging competitive environment in generation and wholesale markets and the increasing possibility of retail competition have created greater planning uncertainty and risks for the Company. In response, the Company is continuing to develop a number of strategies to retain its existing customers and to expand its retail and wholesale customer base, including:
1. Restructuring its operations to maintain its relatively low-cost status by controlling costs and operating more efficiently
2. Implementing new marketing strategies
3. Increasing customer and energy services
4. Avoiding future rate increases
The Company believes it is taking necessary actions to position itself to meet current and future competitive challenges.
AGC MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
As described under Liquidity and Capital Requirements, 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 1995 decreased due to a reduction in net investment and reduced operating expenses which are described below. Revenues for 1994 increased primarily because of the return on equity settlement which resulted in an adjustment of prior period provisions for rate refunds.
The decrease in operating expenses in 1995 resulted from a decrease in federal income taxes due to a decrease in income before taxes ($1.2 million) combined with a decrease in operation and maintenance expense ($1.0 million). 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 interest on long-term debt in 1994 was the combined result of a decrease in the average amount of, and interest rates on, long- term debt outstanding. The increase in other interest in 1995 was due to cash needs for refunds mandated in rate case proceedings (see Liquidity and Capital Requirements), and the increase in 1994 was due to amortization of the premium paid to refund debentures in 1993.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. SFAS No. 121 establishes standards for the impairment of long-lived assets and certain identifiable intangibles and requires companies to recognize an impairment loss if the expected future undiscounted cash flows are less than the carrying amount of an asset. The Company does not believe at this time that adoption of this standard will have a materially adverse effect on its financial position.
Liquidity and Capital Requirements
The Company's only operating assets are an undivided 40% interest in the Bath County (Virginia) pumped-storage hydroelectric station and its connecting transmission facilities. The Company has no plans for construction of any other major facilities.
Pursuant to an agreement, 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, deprecia- tion, taxes, and a return on its investment.
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 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 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 was filed with the FERC on January 12, 1995, which would reduce the Company's ROE from 11.53% to 11.13% for the period from March 1, 1992 through December 31, 1994, and increase the Company's ROE to 11.2% for the period from January 1, 1995 through December 31, 1995. This settlement was approved by the FERC on March 23, 1995. Refunds were made by the Company of any revenues collected between March 1, 1992 and March 23, 1995 in excess of these levels. A second settlement has been negotiated to address the Company's ROE after 1995. On December 21, 1995, the Company submitted the new settlement to the FERC and action is pending. Interested parties representing less than 2% of the Company's eventual revenues have filed exceptions to the settlement. Under the terms of the settlement, the Company's ROE for 1996 would be 11%. For 1997 and 1998 the ROE would be set by a formula based upon the yields of 10- year constant maturity U.S. Treasury securities. However, the change in ROE from the previous year's value cannot exceed 50 basis points.
Through a filing completed on October 31, 1994, the Company sought FERC approval to add a prior tax payment of approximately $12 million to rate base which will produce about $1.4 million in additional annual revenues. The FERC accepted the Company's filing and ordered the increase to become effective June 1, 1995.
An internal money pool accommodates intercompany short-term borrowing needs to the extent that certain of the Company's affiliates have funds available.
All other schedules are omitted because they are not applicable or the required information is shown in the Financial Statements or Notes thereto.
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, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, 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 audit provides a reasonable basis for the opinion expressed above.
As discussed in Note A to the consolidated financial statements, the Company changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP
New York, New York February 1, 1996
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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, 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 Note A to the financial statements, the Company changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP
New York, New York February 1, 1996
REPORT OF INDEPENDENT ACCOUNTANTS
The 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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, 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 Note A to the financial statements, the Company changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP
New York, New York February 1, 1996
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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, 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 Note A to the consolidated financial statements, the Company changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP
New York, New York February 1, 1996
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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, 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.
PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP
New York, New York February 1, 1996
APS Notes to Consolidated Financial Statements (These notes are an integral part of the consolidated financial statements.)
Note A: Summary of Significant Accounting Policies
Allegheny Power System, Inc. (the Company) is an electric utility holding company that derives substantially all of its income from the electric utility operations of its regulated subsidiaries, Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company. The principal markets for the System's electric sales are in the states of Pennsylvania, West Virginia, Maryland, Virginia, and Ohio. In 1995, revenues from 50 of its largest electric utility customers provided approximately 20% of the System's retail revenues. The Company also has a wholly-owned nonutility subsidiary, AYP Capital, Inc., formed in 1994, which is involved primarily in energy-related services, development of wholesale unregulated power generation, and other energy-related businesses.
The Company and its subsidiaries are subject to regulation by the Securities and Exchange Commission (SEC), including the Public Utility Holding Company Act of 1935. 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.
Use of Estimates:
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and disclosures of contingencies during the reporting period, which in the normal course of business are subsequently adjusted to actual results.
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, 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 to other utilities, including transmission services, 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 by the regulated subsidiaries 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 1995, 1994, and 1993 averaged 8.73%, 9.00%, and 9.37%, 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% of average depreciable property in 1995, 3.3% in 1994, and 3.4% in 1993. 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 acquisi- tion 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.
Benefit plans' investments represent the estimated cash surrender values of purchased life insurance on the Board of Directors and qualifying management employees under a Directors' pension plan, and an executive life insurance plan and a supplemental executive retirement 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 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. These balances are being amortized over the 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 an amount equal to the annual cost, but not more than can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association (VEBA) trust funds in amounts up to that which can be deducted for federal
income tax purposes. Medical benefits are self-insured; the life insurance plan is paid through insurance premiums.
Accounting Changes:
Effective January 1, 1994, the regulated 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 rate making 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 1994 consolidated income before the cumulative effect of accounting change, as well as 1993 consolidated net income, is not material.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. The Company does not believe at this time that the adoption of this standard will have a materially adverse effect on its financial position.
Note B: Restructuring Charges and Asset Write-Offs
The System is undergoing a reorganization and reengineering process (restruc- turing) to simplify its management structure and to increase efficiency. As a consequence of this process, approximately 200 employees, primarily in the Bulk Power Supply department, have been placed in a staffing force. In January 1996, these employees were offered an option to resign immediately under a Voluntary Separation Program (VSP) or to remain employed subject to involuntary separation (layoff) after one year, if during that year they have not found other employment within the System.
In 1995, the regulated subsidiaries recorded restructuring charges of $16.0 million ($9.6 million after tax) in other operation expense, for the estimated liabilities related primarily to staffing force employees' involuntary separation costs. Further separation costs for these employees will be recorded in 1996 depending upon those employees who elect early separation under the VSP, which provides enhanced separation benefits. Additional restructuring costs may be required as the restructuring process is completed for other departments.
In connection with changes in inventory management objectives, the regulated subsidiaries in 1995 also recorded $7.4 million ($4.5 million after tax) primarily in maintenance expense for the write-off of obsolete and slow-moving materials.
In 1994, the regulated subsidiaries wrote off $9.2 million ($5.3 million after tax) in other income (expense), net, 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 was no longer reasonable to assume future recovery of these costs in rates.
Note C: Income Taxes Details of federal and state income tax provisions are:
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:
Federal income tax returns through 1991 have been examined and substantially settled.
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 regulated subsidiaries have recorded regulatory assets of $559 million and $605 million as of December 31, 1995 and 1994, respectively. Regulatory liabilities of $98 million and $105 million as of December 31, 1995 and 1994, respectively, have been recorded 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 D: Dividend Restriction
Supplemental indentures relating to most outstanding bonds of the regulated subsidiaries contain dividend restrictions under the most restrictive of which $209,729,000 of consolidated retained earnings at December 31, 1995, 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 E: Pension Benefits
Net pension costs, 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 at December 31 using a measurement date of September 30 were as follows:
In determining the actuarial present value of the projected benefit obligation at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1995, 1994, and 1993.
Note F: Postretirement Benefits Other Than Pensions The cost of postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents in 1995 and 1994, 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 at December 31 using a measurement date of September 30 were as follows:
In determining the APBO at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The 1995 expected long-term rate of return on assets was 8.25% net of tax. For measurement purposes, a health care trend rate of 8% for 1996, declining 1% each year thereafter to 6.5% 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, 1995, by $12.8 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1995 by $1.3 million.
Note G: Fair Value of Financial Instruments
The carrying amounts and estimated fair value of financial instruments at December 31 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 long-term debt and QUIDS 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 H: Capitalization 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 1995, the regulated subsidiaries refunded $130 million of preferred stock with dividend rates between 7% and 8.8%, with the proceeds from the issuance of Quarterly Income Debt Securities (QUIDS) described below. 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.
Long-Term Debt and QUIDS:
Maturities for long-term debt for the next five years are: 1996, $43,575,000; 1997, $26,900,000; 1998, $185,400,000; 1999, $34,861,000; and 2000, $145,300,000. 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.
In 1995, the regulated subsidiaries issued $155.5 million of 8% 30-year QUIDS to refund preferred stock. Under certain circumstances the interest payments may be deferred for a period of up to 20 consecutive quarters.
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 1999. Each bank has the option to discontinue its loans after 1999 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 Company and its regulated subsidiaries, 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 Company and its regulated subsidiaries have fee arrangements on all of their lines of credit and no compensating balance requirements. At December 31, 1995, unused lines of credit with banks were $173,350,000. 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 regulated subsidiaries may borrow up to $300 million on a standby revolving credit basis. Short-term debt outstanding for 1995 and 1994 consisted of:
Note J: Commitments and Contingencies Construction Program:
The regulated subsidiaries have entered into commitments for their construction programs, for which expenditures are estimated to be $279 million for 1996 and $305 million for 1997. Through 1999, annual construction expenditures are not expected to significantly exceed 1996 estimated levels. Construction expenditure levels in 2000 and beyond will depend upon future generation requirements, as well as the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990.
Nonutility Investments:
AYP Capital, Inc. has entered into an agreement with Duquesne Light Company, subject to regulatory approvals, to purchase its 50% interest in Unit No. 1 of the Fort Martin Power Station for approximately $170 million. AYP Capital intends to operate the unit as an exempt wholesale generator and sell the output at market rates. Necessary regulatory approvals will likely take several months, and AYP Capital expects a closing by late 1996.
AYP Capital has committed to invest up to $10 million in two limited partner- ships formed to invest in emerging electrotechnologies that promote the efficient use of electricity and improve the environment, and to invest in and develop electric energy opportunities in Latin America. As of December 31, 1995, AYP Capital's investments totaled $1.1 million.
Environmental Matters and Litigation:
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. 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.
The regulated subsidiaries previously reported that the Environmental Protec- tion Agency (EPA) had identified them and approximately 875 others as potential- ly responsible parties in a Superfund site subject to cleanup. The regulated subsidiaries have also been named as defendants along with multiple other defendants in pending asbestos cases involving one or more plaintiffs. The subsidiaries believe that provisions for liabilities and insurance recoveries are such that final resolution of these claims will not have a material effect on their financial position.
Monongahela NOTES TO FINANCIAL STATEMENTS (These notes re 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.
USE OF ESTIMATES: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and disclosures of contingencies during the reporting period, which in the normal course of business are subsequently adjusted to actual results.
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 to other companies, including transmission services, 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 1995, 1994, and 1993 were 7.29%, 8.16%, and 8.69%, 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 3.4%, 3.6%, and 3.8% of average depreciable property in 1995, 1994, and 1993, respectively. 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 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. These balances are being amortized over the 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 an amount equal to the annual cost,
but not more than can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association (VEBA) trust funds in amounts up to that which can be deducted for federal income tax purposes. Medical benefits are self- insured; the life insurance plan is paid through insurance premiums.
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 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 1994 income before the cumulative effect of accounting change, as well as 1993 net income, is not material.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. The Company does not believe at this time that the adoption of this standard will have a materially adverse effect on its financial position.
Note B - Restructuring Charges and Asset Write-Offs:
The System is undergoing a reorganization and reengineering process (restructuring) to simplify its management structure and to increase efficiency. As a consequence of this process, approximately 200 employees, primarily in the System's Bulk Power Supply department, have been placed in a staffing force. In January 1996, these employees were offered an option to resign immediately under a Voluntary Separation Program (VSP) or to remain employed subject to involuntary separation (layoff) after one year, if during that year they have not found other employment within the System.
In 1995, the Company recorded restructuring charges of $4.1 million ($2.5 million after tax) in other operation expense, for its share of the estimated liabilities related primarily to staffing force employees' involuntary separation costs. Further separation costs for these employees will be recorded in 1996 depending upon those employees who elect early separation under the VSP, which provides enhanced separation benefits. Additional restructuring costs may be required as the restructuring process is completed for other departments.
In connection with changes in inventory management objectives, the Company in 1995 also recorded $1.4 million ($.8 million after tax) primarily in maintenance expense for the write-off of obsolete and slow-moving materials.
Note C - Income Taxes:
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:
Federal income tax returns through 1991 have been examined and substantially settled.
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 $152 million and $174 million as of December 31, 1995 and 1994, respectively. Regulatory liabilities of $20 million as of December 31, 1995 and 1994, respectively, have been recorded 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 D - Dividend Restriction:
Supplemental indentures relating to most outstanding bonds of the Company contain dividend restrictions under the most restrictive of which $76,384,000 of retained earnings at December 31, 1995, 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 E - 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. AGC's rates are set by a formula filed with and previously accepted by the FERC.
The only component which changes is the return on equity (ROE). In December 1991, AGC filed for a continuation of the existing ROE of 11.53% and other interested parties filed to reduce the ROE to 10%. A recommendation was issued by an Administrative Law Judge on December 22, 1994, to dismiss the joint complaint. A settlement agreement for both cases was filed with the FERC on January 12, 1995, which would reduce AGC's ROE from 11.53% to 11.13% for the period from March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.2% for the period from January 1, 1995, through December 31, 1995. This settlement was approved by the FERC on March 23, 1995. Refunds were made by AGC of any revenues collected between March 1, 1992 and March 23, 1995 in excess of these levels. A second settlement has been negotiated to address AGC's ROE after 1995. On December 21, 1995, AGC submitted the new settlement to the FERC. Interested parties representing less than 2% of AGC's eventual revenues have filed exceptions to the settlement. Under the terms of the settlement, AGC's ROE for 1996 would be 11%, and set by formula in 1997 and 1998 based primarily on changes in interest rates.
Following is a summary of financial information for AGC:
December 31 1995 1994 (Thousands of Dollars) Balance sheet information: Property, plant, and equipment............... $677,857 $680,749 Current assets............................... 7,586 5,991 Deferred charges............................. 24,844 27,496 Total assets............................... $710,287 $714,236
Total capitalization......................... $463,862 $489,894 Current liabilities.......................... 11,892 6,484 Deferred credits............................. 234,533 217,858 Total capitalization and liabilities....... $710,287 $714,236
The Company's share of the equity in earnings above was $7.4 million, $8.0 million, and $7.3 million for 1995, 1994, and 1993, respectively, and is included in other income, net, on the Statement of Income.
Note F - 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:
1995 1994 1993 (Thousands of Dollars)
Service cost - benefits earned........ $ 3,340 $ 3,677 $ 3,198 Interest cost on projected benefit obligation.................. 9,375 9,045 8,577 Actual (return) loss on plan assets......................... (27,269) 87 (22,606) Net amortization and deferral......... 15,183 (11,563) 12,048 Pension cost.......................... 629 1,246 1,217 Regulatory reversal (deferral)........ 3,718 (1,179) Net pension cost...................... $ 629 $ 4,964 $ 38
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:
1995 1994 (Thousands of Dollars) Actuarial present value of accumulated benefit obligation earned to date (including vested benefit of $100,006,000 and $92,823,000)................ $107,672 $ 99,605 Funded status: Actuarial present value of projected benefit obligation......................... $133,485 $123,935 Plan assets at market value, primarily common stocks and fixed income securities.. 156,554 134,166 Plan assets in excess of projected benefit obligation......................... (23,069) (10,231) Add: Unrecognized cumulative net gain from past experience different from that assumed............................. 24,151 13,969 Unamortized transition asset, being amortized over 14 years beginning January 1, 1987.......................... 3,242 3,988 Less unrecognized prior service cost due to plan amendments................ 2,195 2,471 Pension cost liability at September 30....... 2,129 5,255 Fourth quarter contributions................. 1,829 Pension liability at December 31............. $ 2,129 $ 3,426
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, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future
compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1995, 1994, and 1993.
Note G - Postretirement Benefits Other Than Pensions:
The cost of postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents in 1995 and 1994, a portion of which (about 25% to 30%) was charged to plant construction, included the following components:
1995 1994 (Thousands of Dollars)
Service cost - benefits earned.................. $ 741 $ 764 Interest cost on accumulated postretirement benefit obligation............. 3,939 3,655 Actual (return) loss on plan assets............. (1,702) 38 Amortization of unrecognized transition obligation......................... 1,783 1,783 Other net amortization and deferral............. 1,376 50 Postretirement cost............................. 6,137 6,290 Regulatory reversal (deferral).................. 345 (3,450) Net postretirement cost......................... $ 6,482 $ 2,840
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: 1995 1994 (Thousands of Dollars)
Accumulated postretirement benefit obligation (APBO): Retirees.................................... $32,249 $33,528 Fully eligible employees.................... 5,221 4,947 Other employees............................. 14,177 14,458 Total obligation.......................... 51,647 52,933 Plan assets at market value, in common stocks, fixed income securities, and short-term investments................................... 10,515 5,338 Accumulated postretirement benefit obligation in excess of plan assets........... 41,132 47,595 Less: Unrecognized cumulative net loss from past experience different from that assumed...... 7,559 12,752 Unrecognized transition obligation, being amortized over 20 years beginning January 1, 1993................... 30,378 32,368 Postretirement benefit liability at September 30............................... 3,195 2,475 Fourth quarter contributions and benefit payments.......................... 2,046 1,437 Postretirement benefit liability at December 31................................ $ 1,149 $ 1,038
In determining the APBO at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%, and 7.25% and the rates of increase in future compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The 1995 expected long-term rate of return on assets was 8.25% net of tax. For measurement purposes, a health care trend rate of 8% for 1996, declining 1% each year thereafter to 6.5% 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, 1995, by $3.4 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1995 by $.3 million.
Note H - Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:
1995 1994 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars)
Liabilities: Short-term debt..... $ 29,868 $ 29,868 $ 36,570 $ 36,570 Long-term debt and QUIDS............. 513,710 540,387 473,710 458,714
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 and QUIDS 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 I - Capitalization:
COMMON STOCK AND OTHER PAID-IN CAPITAL: Other paid-in capital decreased $76,000 in 1995 as a result of preferred stock transactions and $477,000 in 1994 as a result of underwriting fees and commissions associated with the Company's sale of $50 million of preferred stock.
PREFERRED STOCK: In 1995, the Company refunded $40 million of preferred stock with dividend rates between 7.36% and 8.80%, with the proceeds from the issuance of Quarterly Income Debt Securities (QUIDS) described below. 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.
LONG-TERM DEBT AND QUIDS: Maturities for long-term debt for the next five years are: 1996, $18,500,000; 1997, $15,500,000; 1998, $20,100,000; 1999, $1,000,000; and 2000, $66,000,000. 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.
In 1995, the Company sold $70 million of 7-5/8% 30-year first mortgage bonds to refund a $70 million 8-7/8% issue due in 2019. The Company also issued $25 million of 6.15% 20-year tax-exempt notes to refund a $25 million 7-3/4% issue.
In 1995, the Company issued $40 million of 8% 30-year QUIDS to refund preferred stock. QUIDS may not be redeemed until the year 2000. Under certain circumstances the interest payments may be deferred for a period of up to 20 consecutive quarters.
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 1995 and 1994 consisted of:
1995 1994 (Thousands of Dollars) Balance at end of year: Commercial Paper.................. $22,368-6.09% $24,970-6.21% Notes Payable to Banks............ 7,500-6.00% 11,600-6.43% Money Pool........................ 2,900-5.49% Average amount outstanding during the year: Commercial Paper.................. 8,699-5.96% 8,751-3.58% Notes Payable to Banks............ 7,153-5.99% 15,283-3.89% Money Pool........................ 3,116-5.85% 11,363-4.51%
Note K - Commitments and Contingencies:
CONSTRUCTION PROGRAM: The Company has entered into commitments for its construction program, for which expenditures are estimated to be $66 million for 1996 and $75 million for 1997. Through 1999, annual construction expenditures are not expected to significantly exceed 1996 estimated levels. Construction expenditure levels in 2000 and beyond will depend upon future generation requirements, as well as the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990.
ENVIRONMENTAL MATTERS AND LITIGATION:
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. 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 previously reported that the Environmental Protection Agency had identified it and its affiliates and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. The Company has also been named as a defendant along with multiple other defendants in pending asbestos cases involving one or more plaintiffs. The Company believes that provisions for liabilities and insurance recoveries are such that final resolution of these claims will not have a material effect on their financial position.
The Company is guarantor as to 27% of a $50 million revolving credit agreement of AGC, which in 1995 was used by AGC solely as support for its indebtedness for commercial paper outstanding.
Potomac Edison
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 Commis- sion (SEC), by various state bodies having jurisdiction, and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below.
USE OF ESTIMATES: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and disclosures of contingencies during the reporting period, which in the normal course of business are subsequently adjusted to actual results.
REVENUES: Beginning in 1994, revenues, including amounts resulting from the applica- tion 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, revenues were recorded for billings rendered to customers. Revenues of $67.4 million from one industrial customer, Eastalco Aluminum Company, were 8% of total electric operating revenues in 1995.
DEFERRED POWER COSTS, NET: The costs of fuel, purchased power, and certain other costs, and revenues from sales to other companies, including transmission services, 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 administra- tion, 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 1995, 1994, and 1993 were 9.71%, 9.73%, and 9.97%, 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 3.6%, 3.4%, and 3.6% of average depreciable property in 1995, 1994, and 1993, respectively. 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 substan- tially in accordance with the accounting procedures followed for ratemaking purposes. Deferred tax assets and liabilities 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 invest- ment credits, and amounts equivalent to such credits were charged to income with concurrent credits to a deferred account. These balances are being amortized over the 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 an amount equal to the annual cost, but not more than can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association (VEBA) trust funds in amounts up to that which can be deducted for federal income tax purposes. Medical benefits are self-insured; the life insurance plan is paid through insurance premiums.
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 1994 income before the cumulative effect of accounting change, as well as 1993 net income, is not material.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. The Company does not believe at this time that the adoption of this standard will have a materially adverse effect on its financial position.
Note B - Restructuring Charges and Asset Write-Offs:
The System is undergoing a reorganization and reengineering process (re- structuring) to simplify its management structure and to increase efficiency. As a consequence of this process, approximately 200 employees, primarily in the System's Bulk Power Supply department, have been placed in a staffing force. In January 1996, these employees were offered an option to resign immediately under a Voluntary Separation Program (VSP) or to remain employed subject to involuntary separation (layoff) after one year, if during that year they have not found other employment within the System.
In 1995, the Company recorded restructuring charges of $4.6 million ($2.9 million after tax) in other operation expense, for its share of the estimated liabilities related primarily to staffing force employees' involuntary separation costs. Further separation costs for these employees will be recorded in 1996 depending upon those employees who elect early separation under the VSP, which provides enhanced separation benefits. Additional restructuring costs may be required as the restructuring process is completed for other departments.
In connection with changes in inventory management objectives, the Company in 1995 also recorded $2.2 million ($1.4 million after tax) primarily in maintenance expense for the write-off of obsolete and slow-moving materials.
Note C - Income Taxes:
Details of federal and state income tax provisions are:
1995 1994 1993 (Thousands of Dollars) Income taxes--current: Federal............................. $25,949 $34,193 $29,758 State............................... (640) (2,849) 3,991 Total............................. 25,309 31,344 33,749 Income taxes--deferred, net of amortization........................ 16,504 14,955 (770) Amortization of deferred investment credit................... (2,225) (2,267) (2,349) Total income taxes................ 39,588 44,032 30,630 Income taxes--charged to other income and deductions............... (2,652) (1,176) (544) Income taxes--charged to accounting change (including state income taxes)................. (9,693) Income taxes--charged to operating income.................... $36,936 $33,163 $30,086
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:
1995 1994 1993 (Thousands of Dollars) Financial accounting income before cumulative effect of accounting change and income taxes............ $115,201 $115,146 $103,553 Amount so produced................... $ 40,300 $ 40,300 $ 36,200 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower tax depreciation......... 4,200 100 2,300 Plant removal costs............ (1,200) (1,700) (2,100) State income tax, net of federal income tax benefit............... 2,200 1,300 1,600 Amortization of deferred investment credit................ (2,225) (2,267) (2,349) Equity in earnings of subsidiaries..................... (2,600) (2,900) (2,600) Other, net......................... (3,739) (1,670) (2,965) Total.......................... $ 36,936 $ 33,163 $ 30,086
Federal income tax returns through 1991 have been examined and substantially settled.
At December 31, the deferred tax assets and liabilities were comprised of the following:
1995 1994 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credit............ $ 15,084 $ 16,497 Unbilled revenue............................. 3,492 3,504 Tax interest capitalized..................... 11,221 12,701 Contributions in aid of construction......... 12,614 11,653 State tax loss carryback/carryforward........ 24 2,721 Advances for construction.................... 1,573 1,338 Other........................................ 5,619 5,800 49,627 54,214 Deferred tax liabilities: Book vs. tax plant basis differences, net.... 189,618 192,862 Other........................................ 15,803 13,367 205,421 206,229 Total net deferred tax liabilities............. 155,794 152,015 Less portion above included in current liabilities.......................... 362 2,716 Total long-term net deferred tax liabilities.............................. $155,432 $149,299
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 $61 million and $76 million as of December 31, 1995 and 1994, respectively. Regulatory liabilities of $15 million and $17 million as of December 31, 1995 and 1994, respectively, have been recorded 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 D - Dividend Restriction:
Supplemental indentures relating to most outstanding bonds of the Company contain dividend restrictions under the most restrictive of which $94,355,000 of retained earnings at December 31, 1995, 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 E - 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. AGC's rates are set by
a formula filed with and previously accepted by the FERC. The only component which changes is the return on equity (ROE). In December 1991, AGC filed for a continuation of the existing ROE of 11.53% and other interested parties filed to reduce the ROE to 10%. A recommendation was issued by an Administra- tive Law Judge on December 22, 1994, to dismiss the joint complaint. A settlement agreement for both cases was filed with the FERC on January 12, 1995, which would reduce AGC's ROE from 11.53% to 11.13% for the period from March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.2% for the period from January 1, 1995, through December 31, 1995. This settlement was approved by the FERC on March 23, 1995. Refunds were made by AGC of any revenues collected between March 1, 1992 and March 23, 1995 in excess of these levels. A second settlement has been negotiated to address AGC's ROE after 1995. On December 21, 1995, AGC submitted the new settlement to the FERC. Interested parties representing less than 2% of AGC's eventual revenues have filed exceptions to the settlement. Under the terms of the settlement, AGC's ROE for 1996 would be 11%, and set by formula in 1997 and 1998 based primarily on changes in interest rates.
Following is a summary of financial information for AGC:
December 31 1995 1994 (Thousands of Dollars) Balance sheet information: Property, plant, and equipment............... $677,857 $680,749 Current assets............................... 7,586 5,991 Deferred charges............................. 24,844 27,496 Total assets............................... $710,287 $714,236
Total capitalization......................... $463,862 $489,894 Current liabilities.......................... 11,892 6,484 Deferred credits............................. 234,533 217,858 Total capitalization and liabilities....... $710,287 $714,236
Year Ended December 31 1995 1994 1993 (Thousands of Dollars) Income statement information: Electric operating revenues......... $86,970 $91,022 $90,606 Operation and maintenance expense........................... 5,740 6,695 6,609 Depreciation........................ 17,018 16,852 16,899 Taxes other than income taxes...................... 5,091 5,223 5,347 Federal income taxes................ 13,552 14,737 13,262 Interest charges.................... 18,361 17,809 21,635 Other income, net................... (16) (11) (328) Net income.......................... $27,224 $29,717 $27,182
The Company's share of the equity in earnings above was $7.6 million, $8.3 million, and $7.6 million for 1995, 1994, and 1993, respectively, and is included in other income, net, on the Statement of Income.
Note F - 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:
1995 1994 1993 (Thousands of Dollars)
Service cost--benefits earned......... $ 3,286 $ 3,555 $ 3,225 Interest cost on projected benefit obligation.................. 10,161 9,867 9,612 Actual (return) loss on plan assets......................... (25,718) 304 (22,481) Net amortization and deferral......... 12,631 (12,808) 10,669 Pension cost.......................... 360 918 1,025 Regulatory reversal................... 1,194 537 Net pension cost...................... $ 360 $ 2,112 $ 1,562
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:
1995 1994 (Thousands of Dollars) Actuarial present value of accumulated benefit obligation earned to date (including vested benefit of $111,538,000 and $103,546,000)............... $119,383 $110,577 Funded status: Actuarial present value of projected benefit obligation......................... $144,800 $135,060 Plan assets at market value, primarily common stocks and fixed income securities.. 169,830 146,211 Plan assets in excess of projected benefit obligation......................... (25,030) (11,151) Add: Unrecognized cumulative net gain from past experience different from that assumed............................. 23,839 13,165 Unamortized transition asset, being amortized over 14 years beginning January 1, 1987.......................... 3,435 4,183 Less unrecognized prior service cost due to plan amendments................ 2,450 2,732 Pension cost liability at September 30....... (206) 3,465 Fourth quarter contributions................. 1,989 Pension (prepayment) liability at December 31............................. $ (206) $ 1,476
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 obliga- tion at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1995, 1994, and 1993.
Note G - Postretirement Benefits Other Than Pensions:
The cost of postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents in 1995 and 1994, a portion of which (about 25% to 30%) was charged to plant construction, included the following components:
1995 1994 (Thousands of Dollars)
Service cost - benefits earned.................. $ 683 $ 696 Interest cost on accumulated postretirement benefit obligation............. 4,476 4,047 Actual loss (return) on plan assets............. (1,938) 47 Amortization of unrecognized transition obligation......................... 2,011 1,976 Other net amortization and deferral............. 1,570 53 Postretirement cost............................. 6,802 6,819 Regulatory reversal (deferral).................. 11 (457) Net postretirement cost......................... $6,813 $6,362
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:
1995 1994 (Thousands of Dollars)
Accumulated postretirement benefit obligation (APBO): Retirees.................................... $35,852 $36,927 Fully eligible employees.................... 8,699 8,152 Other employees............................. 13,805 14,035 Total obligation.......................... 58,356 59,114 Plan assets at market value, in common stocks, fixed income securities, and short-term investments................................... 11,882 5,962 Accumulated postretirement benefit obligation in excess of plan assets........... 46,474 53,152 Less: Unrecognized cumulative net loss from past experience different from that assumed...... 8,578 14,223 Unrecognized transition obligation, being amortized over 20 years beginning January 1, 1993................... 34,125 35,928 Postretirement benefit liability at September 30............................... 3,771 3,001 Fourth quarter contributions and benefit payments.......................... 2,221 1,634 Postretirement benefit liability at December 31................................ $ 1,550 $ 1,367
In determining the APBO at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The 1995 expected long-term rate of return on assets was 8.25% net of tax. For measurement purposes, a health care trend rate of 8% for 1996, declining 1% each year thereafter to 6.5% 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, 1995, by $3.8 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1995 by $.4 million.
Note H - Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:
1995 1994 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Liabilities: Mandatorily redeemable preferred stock.... $ - $ - $ 26,400 $ 25,542 Short-term debt...... 21,637 21,637 Long-term debt and QUIDS.............. 655,657 689,003 610,200 594,519
The fair value of mandatorily redeemable preferred stock was estimated based on quoted market prices. 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 and QUIDS 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 I - Capitalization:
COMMON STOCK AND OTHER PAID-IN CAPITAL: In October 1993, the Company issued and sold 2,500,000 shares of common stock to its parent at $20 per share. Other paid-in capital decreased $34,000 in 1995 and increased $10,000 in 1994 as a result of preferred stock transac- tions.
PREFERRED STOCK: In 1995, the Company refunded $45.5 million of preferred stock with dividend rates between 7% and 8.32%, with the proceeds from the issuance of Quarterly Income Debt Securities (QUIDS) described below. All of the preferred stock is entitled on voluntary liquidation to its then current call price and on involuntary liquidation to $100 a share.
LONG-TERM DEBT AND QUIDS: Maturities for long-term debt for the next five years are: 1996, $18,700, 000; 1997, $800,000; 1998, $1,800,000; 1999, $1,800,000; and 2000, $76,800,000. 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.
In 1995, the Company sold $65 million of 7-3/4% 30-year first mortgage bonds to refund a $65 million 9-1/4% issue due in 2019 and $80 million of 7-5/8% 30- year first mortgage bonds to refund an $80 million 9-5/8% issue due in 2020. The Company also issued $21 million of 6.15% 20-year tax-exempt notes to refund a $21 million 7.3% issue.
In 1995, the Company issued $45.5 million of 8% 30-year QUIDS to refund preferred stock. QUIDS may not be redeemed until the year 2000. Under certain circumstances the interest payments may be deferred for a period of up to 20 consecutive quarters.
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 $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. Short-term debt outstanding for 1995 and 1994 consisted of:
1995 1994 (Thousands of Dollars) Balance at end of year: Commercial Paper.................... $21,637-6.10% Average amount outstanding during the year: Commercial Paper.................. $ 499-5.94% $1,021-3.96% Notes Payable to Banks............ 995-6.04% 2,499-3.96% Money Pool........................ 179-5.96% 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 $87 million for 1996 and $103 million for 1997. Through 1999, annual construction expenditures are not expected to significantly exceed 1996 estimated levels. Construction expenditure levels in 2000 and beyond will depend upon future generation requirements, as well as the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990.
ENVIRONMENTAL MATTERS AND LITIGATION: 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. 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 previously reported that the Environmental Protection Agency had identified it and its affiliates and approximately 875 others as potentially responsible parties in a Superfund site subject to cleanup. The Company has also been named as a defendant along with multiple other defendants in pending asbestos cases involving one or more plaintiffs. The Company believes that provisions for liabilities and insurance recoveries are such that final resolution of these claims will not 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 1995 was used by AGC solely as support for its indebtedness for commercial paper outstanding.
West Penn 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).
USE OF ESTIMATES: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and disclosures of contingencies during the reporting period, which in the normal course of business are subsequently adjusted to actual results.
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, 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 to other companies, including transmission services, 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 administra- tion, 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 1995, 1994, and 1993 were 8.90%, 8.88%, and 9.40%, 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 3.9%, 3.5%, and 3.4% of average depreciable property in 1995, 1994, and 1993, 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 consoli- dated 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 substan- tially in accordance with the accounting procedures followed for ratemaking purposes. Deferred tax assets and liabilities 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. These balances are being amortized over the 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 an amount equal to the annual cost, but not more than can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association (VEBA) trust funds in amounts up to that which can be deducted for federal income tax purposes. Medical benefits are self-insured; the life insurance plan is paid through insurance premiums.
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 1994 consolidated income before the cumulative effect of accounting change, as well as 1993 consolidated net income, is not material.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. The Company does not believe at this time that the adoption of this standard will have a materially adverse effect on its financial position.
Note B - Restructuring Charges and Asset Write-Offs:
The System is undergoing a reorganization and reengineering process (restructuring) to simplify its management structure and to increase efficien- cy. As a consequence of this process, approximately 200 employees, primarily in the System's Bulk Power Supply department, have been placed in a staffing force. In January 1996, these employees were offered an option to resign immediately under a Voluntary Separation Program (VSP) or to remain employed subject to involuntary separation (layoff) after one year, if during that year they have not found other employment within the System.
In 1995 the Company recorded restructuring charges of $7.3 million ($4.3 million after tax) in other operation expense, for its share of the estimated liabilities related primarily to staffing force employees' involun- tary separation costs. Further separation costs for these employees will be recorded in 1996 depending upon those employees who elect early separation under the VSP, which provides enhanced separation benefits. Additional restructuring costs may be required as the restructuring process is completed for other departments.
In connection with changes in inventory management objectives, the Company in 1995 also recorded $3.8 million ($2.3 million after tax) primarily in maintenance expense for the write-off of obsolete and slow-moving materi- als.
In 1994, the Company wrote off $8.9 million ($5.2 million after tax) in other income (expense), net, 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 was no longer reasonable to assume future recovery of these costs in rates.
Note C - Income Taxes:
Details of federal and state income tax provisions are:
1995 1994 1993 (Thousands of Dollars) Income taxes--current: Federal............................. $49,928 $46,964 $47,089 State............................... 9,344 13,282 14,983 Total............................. 59,272 60,246 62,072 Income taxes--deferred, net of amortization................. 4,944 3,277 (7,522) Amortization of deferred investment credit................... (2,580) (2,578) (2,592) Total income taxes................ 61,636 60,945 51,958 Income taxes--credited (charged) to other income and deductions...... 109 3,300 (429) Income taxes--charged to accounting change (including state income taxes)................. (13,860) Income taxes--charged to operating income.................... $61,745 $50,385 $51,529
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:
1995 1994 1993 (Thousands of Dollars) Financial accounting income before cumulative effect of accounting change and income taxes............ $179,624 $151,400 $153,590 Amount so produced................... $ 62,900 $ 53,000 $ 53,800 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower tax depreciation......... 4,300 2,000 100 Plant removal costs............ (900) (1,700) (900) State income tax, net of federal income tax benefit............... 9,300 6,400 9,600 Amortization of deferred investment credit................ (2,580) (2,578) (2,592) Equity in earnings of subsidiaries..................... (4,300) (4,600) (4,300) Other, net......................... (6,975) (2,137) (4,179) Total.......................... $ 61,745 $ 50,385 $ 51,529
Federal income tax returns through 1991 have been examined and substan- tially settled.
At December 31, the deferred tax assets and liabilities were comprised of the following:
1995 1994 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credit............ $ 35,043 $ 38,560 Unbilled revenue............................. 8,594 9,539 Tax interest capitalized..................... 19,049 16,165 State tax loss carryback/carryforward........ 508 5,535 Postretirement benefits other than pensions.. 7,324 3,952 Contributions in aid of construction......... 6,009 4,866 Other........................................ 21,499 14,953 98,026 93,570 Deferred tax liabilities: Book vs. tax plant basis differences, net.... 526,257 536,343 Other........................................ 20,304 16,204 546,561 552,547 Total net deferred tax liabilities............. 448,535 458,977 Add portion above included in current assets............................ 21,024 12,538 Total long-term net deferred tax liabilities.............................. $469,559 $471,515
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 $332 million and $351 million as of December 31, 1995 and 1994, respectively. Regulatory liabilities of $36 million and $39 million as of December 31, 1995 and 1994, respectively, have been recorded 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 D - Dividend Restriction:
Supplemental indentures relating to most outstanding bonds of the Company contain dividend restrictions under the most restrictive of which $70,576,000 of consolidated retained earnings at December 31, 1995, 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 E - 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. AGC's rates are set by a formula filed with and previously accepted by the FERC. The only component which changes is the return on equity (ROE). In December 1991, AGC filed for a continuation of the existing ROE of 11.53% and other interested parties filed to reduce the ROE to 10%. A recommendation was issued by an Adminis- trative Law Judge on December 22, 1994, to dismiss the joint complaint. A settlement agreement for both cases was filed with the FERC on January 12, 1995, which would reduce AGC's ROE from 11.53% to 11.13% for the period from March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.2% for the period from January 1, 1995, through December 31, 1995. This settlement was approved by the FERC on March 23, 1995. Refunds were made by AGC of any revenues collected between March 1, 1992 and March 23, 1995 in excess of these levels. A second settlement has been negotiated to address AGC's ROE after 1995. On December 21, 1995, AGC submitted the new settlement to the FERC. Interested parties representing less than 2% of AGC's eventual revenues have filed exceptions to the settlement. Under the terms of the settlement, AGC's ROE for 1996 would be 11%, and set by formula in 1997 and 1998 based primarily on changes in interest rates.
Following is a summary of financial information for AGC:
December 31 1995 1994 (Thousands of Dollars) Balance sheet information: Property, plant, and equipment............... $677,857 $680,749 Current assets............................... 7,586 5,991 Deferred charges............................. 24,844 27,496 Total assets............................... $710,287 $714,236
Total capitalization......................... $463,862 $489,894 Current liabilities.......................... 11,892 6,484 Deferred credits............................. 234,533 217,858 Total capitalization and liabilities....... $710,287 $714,236
Year Ended December 31 1995 1994 1993 (Thousands of Dollars) Income statement information: Electric operating revenues......... $86,970 $91,022 $90,606 Operation and maintenance expense........................... 5,740 6,695 6,609 Depreciation........................ 17,018 16,852 16,899 Taxes other than income taxes...................... 5,091 5,223 5,347 Federal income taxes................ 13,552 14,737 13,262 Interest charges.................... 18,361 17,809 21,635 Other income, net................... (16) (11) (328) Net income.......................... $27,224 $29,717 $27,182
The Company's share of the equity in earnings above was $12.3 million, $13.4 million, and $12.2 million for 1995, 1994, and 1993, respectively, and is included in other income, net, on the Consolidated Statement of Income.
Note F - 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:
1995 1994 1993 (Thousands of Dollars)
Service cost - benefits earned........ $ 4,655 $ 5,124 $ 4,606 Interest cost on projected benefit obligation.................. 14,412 14,051 13,773 Actual (return) loss on plan assets......................... (32,610) 358 (31,224) Net amortization and deferral......... 14,000 (18,210) 14,262 Pension cost.......................... 457 1,323 1,417 Regulatory reversal (deferral)........ 760 - (1,309) Net pension cost...................... $ 1,217 $ 1,323 $ 108
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:
1995 1994 (Thousands of Dollars) Actuarial present value of accumulated benefit obligation earned to date (including vested benefit of $155,921,000 and $150,168,000)............... $165,162 $158,578 Funded status: Actuarial present value of projected benefit obligation......................... $199,683 $191,787 Plan assets at market value, primarily common stocks and fixed income securities.. 234,200 207,623 Plan assets in excess of projected benefit obligation......................... (34,517) (15,836) Add: Unrecognized cumulative net gain from past experience different from that assumed............................. 29,164 15,103 Unamortized transition asset, being amortized over 14 years beginning January 1, 1987.......................... 7,178 8,427 Less unrecognized prior service cost due to plan amendments................ 4,467 4,999 Pension cost liability at September 30....... (2,642) 2,695 Fourth quarter contributions................. 2,843 Pension prepayment at December 31............ $ (2,642) $ (148)
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, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1995, 1994, and 1993.
Note G - Postretirement Benefits Other Than Pensions:
The cost of postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents in 1995 and 1994, a portion of which (about 25% to 30%) was charged to plant construc- tion, included the following components:
1995 1994 (Thousands of Dollars)
Service cost - benefits earned.................. $ 1,055 $ 1,154 Interest cost on accumulated postretirement benefit obligation............. 4,595 4,461 Actual (return) loss on plan assets............. (1,990) 31 Amortization of unrecognized transition obligation......................... 2,830 2,817 Other net amortization and deferral............. 1,610 83 Postretirement cost............................. 8,100 8,546 Regulatory reversal............................. 137 - Net postretirement cost......................... $ 8,237 $ 8,546
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:
1995 1994 (Thousands of Dollars)
Accumulated postretirement benefit obligation (APBO): Retirees.................................... $36,041 $35,895 Fully eligible employees.................... 7,802 8,290 Other employees............................. 17,608 17,013 Total obligation.......................... 61,451 61,198 Plan assets at market value in common stocks, fixed income securities, and short-term investments................................... 12,512 6,173 Accumulated postretirement benefit obligation in excess of plan assets........... 48,939 55,025 Less: Unrecognized cumulative net gain from past experience different from that assumed................................ (3,292) (543) Unrecognized transition obligation, being amortized over 20 years beginning January 1, 1993................... 48,099 50,929 Postretirement benefit liability at September 30............................... 4,132 4,639 Fourth quarter contributions and benefit payments.......................... 3,649 2,113 Postretirement benefit liability at December 31................................ $ 483 $ 2,526
In determining the APBO at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The 1995 expected long-term rate of return on assets was 8.25% net of tax. For measurement purposes, a health care trend rate of 8% for 1996, declining 1% each year thereafter to 6.5% 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, 1995, by $4.0 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1995 by $.4 million.
Note H - Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:
1995 1994 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Assets: Temporary cash investments........ $ 425 $ 425 $ 73 $ 73 Liabilities: Short-term debt...... 70,218 70,218 - - Long-term debt and QUIDS............ 913,985 955,336 870,985 826,003
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 long-term debt and QUIDS 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 I - Capitalization:
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 1993. Other paid-in capital decreased $212,000 in 1995 as a result of preferred stock transactions and decreased $145,000 in 1993 due to underwriting fees and commissions and miscellaneous expenses associated with the Company's sale of $40 million of preferred stock in 1992.
PREFERRED STOCK: In 1995, the Company refunded $70 million of preferred stock with dividend rates between 7% and 8.2%, with the proceeds from the issuance of Quarterly Income Debt Securities (QUIDS) described below. 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.
LONG-TERM DEBT AND QUIDS: Maturities for long-term debt for the next five years are: 1996 and 1997, none; 1998, $103,500,000; 1999, $1,500,000; and 2000, $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.
In 1995, the Company sold $30 million of 7-3/4% 30-year first mortgage bonds to refund a $30 million 9% issue due in 2019. The Company also issued $31.5 million of 6.15% 20-year tax-exempt notes to refund a $20 million 7% issue and an $11.5 million 6.95% issue and issued $15.4 million of 6.05% 19- year tax-exempt notes to refund a $15.4 million 9-3/8% issue.
In 1995, the Company issued $70 million of 8% 30-year QUIDS to refund preferred stock. QUIDS may not be redeemed until the year 2000. Under certain circumstances the interest payments may be deferred for a period of up to 20 consecutive quarters.
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 $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. Short-term debt outstanding for 1995 and 1994 consisted of:
1995 1994 (Thousands of Dollars) Balance at end of year: Commercial Paper.................. $36,318-6.09% Notes Payable to Banks............ 33,900-5.90% Average amount outstanding during the year: Commercial Paper.................. $ 5,692-6.00% $2,216-4.38% Notes Payable to Banks............ 5,342-5.96% 2,379-4.37% Money Pool........................ 592-5.79% 521-4.24%
Note K - Commitments and Contingencies:
CONSTRUCTION PROGRAM: The Company has entered into commitments for its construction program, for which expenditures are estimated to be $125 million for 1996 and $126 million for 1997. Through 1999, annual construction expenditures are not expected to significantly exceed 1996 estimated levels. Construction expenditure levels in 2000 and beyond will depend upon future generation requirements, as well as the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990.
ENVIRONMENTAL MATTERS AND LITIGATION: System companies are subject to various laws, regulations, and uncer- tainties 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 opera- tions. 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 previously reported that the Environmental Protection Agency had identified it and its affiliates and approximately 875 others as poten- tially responsible parties in a Superfund site subject to cleanup. The Company has also been named as a defendant along with multiple other defen- dants in pending asbestos cases involving one or more plaintiffs. The Company believes that provisions for liabilities and insurance recoveries are such that final resolution of these claims will not 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 1995 was used by AGC solely as support for its indebtedness for commercial paper outstanding.
AGC
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 regula- tion by the Securities and Exchange Commission (SEC) and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below.
USE OF ESTIMATES: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and disclosures of contingencies during the reporting period, which in the normal course of business are subsequently adjusted to actual results.
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 1995, 1994, and 1993. 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 consoli- dated 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 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. These balances are being amortized over the estimated service lives of the related properties.
ACCOUNTING CHANGE:
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in 1996. The Company does not believe at this time that the adoption of this standard will have a materially adverse effect on its financial position.
Note B - Income Taxes:
Details of federal income tax provisions are:
1995 1994 1993 (Thousands of Dollars)
Current income taxes payable.......... $ 7,053 $ 5,176 $ 8,112 Deferred income taxes- accelerated depreciation............ 7,818 10,883 6,637 Amortization of deferred investment credit................... (1,310) (1,316) (1,316) Total income taxes................ 13,561 14,743 13,433 Income taxes--charged to other income........................ (9) (6) (171) Income taxes--charged to operating income.................... $13,552 $14,737 $13,262
In 1995, the total provision for income taxes ($13,552,000) was less than the amount produced by applying the federal income tax statutory rate to financial accounting income before income taxes ($14,272,000), due primarily to amortization of deferred investment credit ($1,310,000).
Federal income tax returns through 1991 have been examined and substan- tially settled.
At December 31, the deferred tax assets and liabilities were comprised of the following:
1995 1994 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credit............ $ 27,455 $ 28,160 Other........................................ 104 27,455 28,264 Deferred tax liabilities: Book vs. tax plant basis differences, net.... 183,546 165,561 Total net deferred tax liabilities............. $156,091 $137,297
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 $14.6 million and $4.4 million as of December 31, 1995 and 1994, respectively. Regulatory liabilities of $27.5 million and $28.3 million as of December 31, 1995 and 1994, respective- ly, have been recorded 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 were as follows:
1995 1994 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Liabilities: Long-term debt: Debentures......... $150,000 $146,279 $150,000 $120,195 Medium term notes.. 76,975 78,075 77,975 73,704 Commercial paper... 30,561 30,561 41,736 41,736
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 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 - % 1995 1994 (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.................. 5.82 (1) 30,561 41,736 Medium term notes due 1995-1998... 6.36 (1) 76,975 77,975 Unamortized debt discount......... (1,452) (1,546) Total......................... 256,084 268,165 Less current maturities........... 6,375 1,000 Total......................... $249,709 $267,165
(1) Weighted average interest rate at December 31, 1995.
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 1999. Each bank has the option to discontinue its loans after 1999 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.
Maturities for long-term debt for the next five years are: 1996, $6,375,000; 1997, $10,600,000; 1998, $60,000,000; 1999, $30,561,000; and 2000, none.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
For APS and the Subsidiaries, none. PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
APS, Monongahela, Potomac Edison, West Penn, and AGC. Reference is made to the Executive Officers of the Registrants in Part I of this report. The names, ages, and the business experience during the past five years of the directors of the System companies are set forth below:
(1) See Executive Officers of the Registrants in Part I of this report for further details.
(a) Eleanor Baum. Dean of The Albert Nerken School of Engineering of The Cooper Union for the Advancement of Science and Art. Director of Avnet, Inc. and United States Trust Company. Commissioner of the Engineering Manpower Commission, a fellow of the Institute of Electrical and Electronic Engineers, member of Board of Governors, New York Academy of Sciences and President, American Society of Engineering Education.
(b) William L. Bennett. Chairman, HealthPlan Services Corporation, a leading managed health care services company. Formerly, Chairman and Chief Executive Officer of Noel Group, Inc. Director of Belding Heminway Company, Inc., Global Natural Resources Inc., Noel Group, Inc. and Sylvan, Inc.
(c) Wendell F. Holland. Of Counsel, Law Firm of Reed, Smith, Shaw & McClay. Formerly, Partner, Law Firm of LeBoeuf, Lamb, Greene & MacRae, and Commissioner of the Pennsylvania Public Utility Commission.
(d) Phillip E. Lint. Retired. Formerly, partner, Price Waterhouse.
(e) Edward H. Malone. Retired. Formerly, Vice President of General Electric Company and Chairman, eneral Electric Investment Corporation. Director of Fidelity Group of Mutual Funds, General Re Corporation, and Mattel, Inc.
(f) Frank A. Metz, Jr. Retired. Formerly, Senior Vice President, Finance and Planning, and Director, International Business Machines Corporation. Director of Monsanto Company and Norrell Corporation.
(g) Steven H. Rice. Bank consultant and attorney-at-law. Director and Vice Chairman of the Board of Stamford Federal Savings Bank. Formerly, President and Director of The Seamen's Bank for Savings and Director of Royal Group, Inc.
(h) Gunnar E. Sarsten. Chairman and Chief Executive Officer of MK International. Formerly, President and Chief Operating Officer of Morrison Knudsen Corporation, President and Chief Executive Officer of United Engineers & Constructors International, Inc. (now Raytheon Engineers & Constructors, Inc.), and Deputy Chairman of the Third District Federal Reserve Bank in Philadelphia.
(i) Peter L. Shea. Managing director of Hydrocarbon Energy, Inc., a privately owned oil and gas development drilling and production company and an Individual General Partner of Panther Partners, L.P., a closed-end, non-diversified management company. Member and Manager of Temblor Petroleum Company L.L.C., a privately owned oil and gas exploration and production company operating exclusively in California.
* Stanley I. Garnett, II resigned effective December 1, 1995.
Employment Contracts
In February 1995, APS entered into employment contracts with certain Allegheny Power 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 if there is a Change in Control, 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 payable to the employee will consist of a cash payment equal to 2.99 times the employee's annualized compensation and APS will maintain 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 1995, 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 attend- ed, except Executive Committee meetings, for which fees 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 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
In connection with the relocation of the New York office, Allegheny Power made available to each employee involved in the relocation an interest- free loan of up to 95% of the appraised equity in the employee's current residence for the purchase of a new residence. The loans must be repaid to Allegheny Power upon actual relocation. In addition, interest paid by an employee on a new mortgage will be reimbursed by Allegheny Power until the actual date of relocation. On October 10, 1995, Allegheny Power made an interest-free loan in the amount of $215,000 to Richard J. Gagliardi, a Vice President of APS. On December 7, 1995, Allegheny Power made an interest-free loan in the amount of $75,000 to Thomas K. Henderson, a Vice President of Monongahela, Potomac Edison and West Penn. On January 5, 1996, Allegheny Power made an interest-free loan in the amount of $61,000 to Peter J. Skrgic, a Senior Vice President of APS and a Vice President of Potomac Edison and AGC. Appropriate monthly interest payments as described above also have been and will be paid.
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.