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 (collectively, the 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, 1996, Allegheny Power had approximately 5,100 employees. In 1996 APS, APSC and the Operating Subsidiaries began doing business under the common business name "Allegheny Power." In June 1996, the corporate headquarters of Allegheny Power moved from New York City to Washington County, Maryland. The move situated Allegheny Power's headquarters in the service territory of the Operating Subsidiaries.
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 350,100 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, 1996, Monongahela had 1,534 employees. Most employees have been or will be transferred to APSC in 1997 as part of the final phase of a restructuring of operations which began in 1996. Monongahela's 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.
- 2 - 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 375,400 customers in a service area of about 7,300 square miles with a population of about 782,000. The six largest communities served have populations ranging from 11,900 to 40,100. On December 31, 1996, Potomac Edison had 790 employees. Most employees have been or will be transferred to APSC in 1997 as part of the final phase of a restructuring of operations which began in 1996. Potomac Edison's service area's principal industries produce aluminum, cement, fabricated products, rubber products, sand, stone, and gravel. There are four municipal electric distribution systems in its service area, all of which 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 662,900 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, 1996, West Penn had 1,625 employees. Most employees have been or will be transferred to APSC in 1997 as part of the final phase of a restructuring of operations which began in 1996. West Penn's service area has navigable waterways and substantial deposits of bituminous coal, limestone, and other natural resources. Its service area's principal industries produce steel, coal, fabricated products, and glass. There are three municipal electric distribution systems in its service area, all of which purchase their power requirements from West Penn, and five rural electric cooperative associations, located partly within the area, all of which purchase virtually 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 to AYP Capital and its subsidiaries at cost. On December 31, 1996, APSC had 1,171 employees. This number will increase in 1997, as employees formerly employed by the Operating Subsidiaries are transferred to APSC as part of a restructuring of operations. (See ITEM I. RESTRUCTURING for a further discussion of the restructuring.) - 3 - AYP Capital, incorporated in Delaware in 1994, is a wholly owned nonutility subsidiary of APS which was formed in an effort to meet the challenges of the new competitive environment in the industry. AYP Capital has two wholly owned subsidiaries, AYP Energy, Inc. (AYP Energy) and Allegheny Communications Connect, Inc., (ACC) both Delaware corporations. AYP Energy is an exempt wholesale generator and a power marketer. AYP Energy owns a 50% interest (276 MW) in Unit No. 1 of the Fort Martin Power Station which it purchased in 1996 for approximately $170 million. ACC is an exempt telecommunications company. AYP Capital is also part owner of APS Cogenex, a limited liability company formed with EUA Cogenex. APS Cogenex ceased its marketing activities in 1996 and is concluding existing projects. (See ITEM 1. COMPETITION for a further description of AYP Capital and its subsidiaries' activities.) AYP Capital and its subsidiaries have no employees. However, as of December 31, 1996, 16 APSC employees were dedicated to AYP Capital and its subsidiaries' 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 as of December 31, 1996, was $27.8 million. APS is currently committed to invest up to an additional $6.9 million in AYP Capital to fund AYP Capital's investment in two limited partnerships.
Allegheny Power has in the past and may in the future experience some of the more significant problems and challenges common to electric utilities in general. These include the effect on Allegheny Power of: legislation and proposals to restructure and to deregulate portions of the industry and to increase competition; the potential adverse effect of increased competition on revenues and earnings; increases in operating and other expenses; difficulties in obtaining adequate and timely rate relief (particularly as ratemaking methodologies change as the industry moves toward increased competition and exposure to market forces); and restrictions on construction and operation of facilities due to regulatory requirements and environmental and health considerations. These include the requirements of the Clean Air Act Amendments of 1990 (CAAA), which among other things, require a substantial annual reduction in emissions of sulfur dioxides (SO2) and nitrogen oxides (NOx), and other state and federal Clean Air initiatives.
Further concerns of the industry include possible restrictions on carbon dioxide and NOx emissions, uncertainties in demand due to economic conditions, energy conservation, market competition, weather, and interruptions in fuel supply. The move to a more competitive environment will present a new set of opportunities and problems, including determining the appropriate industry structure, determining recovery of stranded costs (those costs imposed or incurred under a regulatory structure that would not be recoverable in a competitive environment), retaining existing customers and acquiring new customers, and in general changing the way electric utilities do business.
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COMPETITION
Competitive forces within the electric utility industry continued to increase in 1996. In Pennsylvania, Allegheny Power's largest service territory, legislation enacted in 1996 moved that state toward retail competition for electric utility customers. The legislation will phase-in competition over three years by offering retail choice to one-third of each electric utility's customers each year starting in 1999. Difficult questions including stranded cost 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 investigated in Maryland, Ohio, Virginia and West Virginia, as well as at the federal level. Federal legislation to restructure the industry was introduced by several members of Congress in 1996 and has been reintroduced in 1997. In response to the competitive environment that has been evolving, 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.
On December 3, 1996, Pennsylvania enacted a new chapter to the Public Utility Code to restructure its electric utility industry in order to create retail access to a competitive market for the generation of electricity. The legislation reflects many of the recommendations made in a July 1996 Pennsylvania Public Utility Commission (PUC) order which resulted from the PUC's investigation into electric power competition. The legislation became effective on January 1, 1997 and includes the following major provisions:
All electric utilities in Pennsylvania are required to file, beginning on April 1, 1997, and in no event later than September 30, 1997, a restructuring plan to implement direct access to a competitive market for electric generation. The plan must include unbundled rates for generation, juris- dictional transmission, distribution and other services; a proposed mechanism for recovery of stranded costs; a proposed universal service and energy conservation cost recovery mechanism; procedures for ensuring direct access to all licensed energy suppliers; a discussion of the proposed plan's effects on utility employees; and revised tariffs and rates implementing the foregoing.
Retail customer choice will be phased in as follows: up to 33% of all customer load on January 1, 1999; up to 66% of all customer load in all customer classes on January 1, 2000; and 100% of all customer load by January 1, 2001. The PUC can delay this schedule by two six-month periods, if necessary.
Electric distribution companies will continue to be the suppliers of last resort. The PUC will ensure that adequate generation reserves exist to maintain reliable electric
- 5 - service. A utility's transmission and distribution system must continue to meet established national industry standards for installation, maintenance, and safety.
Retail rates will be capped for at least 4-1/2 years for transmission and distribution charges and for as long as 9 years for generation charges. A utility may be exempted from the caps only under very specific circumstances, e.g., nonutility generation contracts, changes in laws or regula- tions, required upgrades or repairs to the transmission system, increases in fuel prices or purchased power prices, nuclear power plant decommissioning costs, or taxes.
Pennsylvania utilities are permitted to recover PUC-approved transition or stranded costs over several years; however, the utilities are required to mitigate these costs to the extent practicable. The recovery of these costs is not to result in cost shifting among customers. Financing of such costs through securitization is also permitted.
All generation suppliers must demonstrate financial and technical fitness and must be licensed by the PUC. Cooperatives and municipalities may participate in retail competition but are not subject to the provisions of the legislation unless they elect to serve customers outside their franchised territories.
State tax revenues paid by utilities and generation suppliers are to remain at their current level to protect against any state revenue loss from restructuring.
The PUC will monitor electricity markets for anti- competitive or discriminatory conduct, and will consider the effect of mergers and acquisitions on these markets.
Allegheny Power is currently evaluating the new legislation to formulate its plan to implement direct retail customer access to a competitive generation services market. Allegheny Power cannot predict what the ultimate effect will be of this legislation. As required by the legislation, West Penn will file its restructuring plan on June 1, 1997. In addition, in 1997 West Penn will implement a Retail Customer Choice Pilot Program for up to 5% of the peak load of its customers. This will result in customers with as much as 165 MW of Allegheny Power's Pennsylvania retail load being eligible to choose an alternate supplier of generation. Allegheny Power, on the other hand, anticipates the opportunity to offer capacity and/or energy to a similar portion of the load of the other Pennsylvania utilities.
As a result of the Pennsylvania competition legislation, West Penn's rates, including its energy cost rates, have been capped effective January 1, 1997. The legislation did not eliminate the energy
- 6 - cost tracking procedure and left to Pennsylvania PUC discretion the method of future rate adjustments for energy costs.
On December 12, 1996, the Public Service Commission of West Virginia issued an order initiating a general investigation for the purpose of seeking comments and information regarding the restructuring of the regulated electric utility industry, establishment of competition in power supply markets, and establishment of retail wheeling and intra- state open access of jurisdictional power distribution systems. Public hearings are scheduled to begin on April 1, 1997.
In September 1995, the Virginia State Corporation Commission (SCC) began an investigation to review its policy regarding restructuring of and competition in the electric industry. On November 12, 1996, the SCC ordered further investigation into restructuring of the industry, requiring the three largest electric utilities in Virginia, including Potomac Edison, to file competition information by March 31, 1997.
On October 9, 1996, the Maryland Public Service Commission issued an order directing its Staff to evaluate the current state of the electric industry and to submit a report to the Commission by May 31, 1997. The four major Maryland electric utilities, including Potomac Edison, are to present unbundled cost studies and model retail service tariffs, among other things, by August 1, 1997.
The Public Utilities Commission of Ohio (Ohio PUC) has initiated informal roundtable discussions on issues concerning competition in the electric utility industry and promoting increased competitive options for Ohio businesses. The meetings have resulted in sets of guidelines on interruptible rates and conjunctive service pilot programs which have been adopted by the Ohio PUC.
On average, the Operating Subsidiaries' rates compare 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 lower than the sum of their actual fixed and variable costs or from marketers acting as resellers of the same low-priced generation. At the same time, the Operating Subsidiaries have experienced increased costs due to compliance with the CAAA and purchases from PURPA projects. (See page 14 for a discussion of PURPA projects, and ITEM 3. LEGAL PROCEEDINGS for a description of litigation and regulatory proceedings concerning PURPA capacity.)
Fully meeting challenges in the emerging competitive environment will be difficult for Allegheny Power 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.
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Allegheny Power, along with the other 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. In the past, 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 on its operations is an alternative.
Allegheny Power continues to advocate repeal of PURPA and in 1996 worked with other utilities seeking PURPA repeal or reform of Section 210 on the grounds that it is obsolete, anticompetitive, and it results in utility customers paying above-market prices for power. (See ITEM 3. LEGAL PROCEEDINGS for information concerning PURPA-related litigation.)
Allegheny Power joined with seven other electric utilities in 1996 to form the Partnership for Customer Choice whose purpose is to seek enactment of federal legislation to bring choice to electric customers no later than the year 2000. The legislation sought would deregulate the generation of electric power, creating a free market for electricity.
To help meet the challenges of the new competitive environment, AYP Capital was formed in 1994. Its purpose is to pursue and develop new opportunities in unregulated markets and to strengthen the long-term competitiveness and profitability of Allegheny Power. During 1996 AYP Capital made several investments in funds which were established in 1995. They include an investment in 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 over ten years, beginning in 1995. They also include an investment 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 over eight years, beginning in 1995. Through FONDELEC, AYP Capital has invested in electric distribution companies in Peru and Argentina. 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. APS
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Cogenex, a limited liability company formed jointly with EUA Cogenex to offer certain energy-related services, ceased marketing activities in 1996 but will conclude existing projects.
AYP Energy, a wholly owned subsidiary of AYP Capital, moved into the wholesale unregulated power generation market with its purchase of Duquesne Light Company's (Duquesne) 50% interest in Unit No. 1 of the Fort Martin Power Station. AYP Energy is an exempt wholesale generator and a certified power marketer. AYP Energy is marketing the output of its 50% interest in Unit No. 1 of Fort Martin, as well as engaging in other power marketing activities. The operation of a merchant plant and power marketing in the wholesale market is essentially participation in a commodity market, which creates certain risk exposures. AYP Energy expects to use exchange-traded and over-the-counter futures, options, and swap contracts both to hedge its exposure to changes in electric power prices, and for trading purposes. The risks to which AYP Energy is exposed include underlying price volatility, credit risk and variation in cash flows, among others. To manage these risks, Allegheny Power has implemented risk management policies and procedures, consistent with industry practice and its goals.
Allegheny Communications Connect (ACC) was formed in 1996 as an exempt telecommunications company under PUHCA. ACC's purpose is to develop unregulated opportunities in the deregulated communications market.
In addition to utilizing AYP Capital and its subsidiaries, management continues to explore methods of marketing and pricing electric energy in new and competitive ways, such as bulk sales of each type of service to nonaffiliates, innovative pricing to traditional utility customers, and repackaging of services in nontraditional ways. Management is also attempting to reduce costs to make Allegheny Power more competitive.
RESTRUCTURING
In 1995, Allegheny Power announced its intention to undertake a restructuring designed to consolidate and reengineer its operations to better meet the competitive challenges of the changing electric utility industry and remain the energy supplier of choice in the future for its customers. In 1996, Allegheny Power essentially completed restructuring of its operations. The benefits Allegheny Power has realized from restructuring include increased efficiencies and synergies due to the elimination of layers of management and the combination of previously duplicated functions.
In general, the restructuring of Allegheny Power consolidated in APSC certain functions which previously were either performed separately by employees of each of the three Operating Subsidiaries, or by employees of the three Operating Subsidiaries along with employees of APSC. Allegheny Power and AYP Capital have been restructured into the
- 9 - following revenue-generating business units: Operating Business Unit; Retail Marketing Business Unit; Generation Business Unit; Transmission Business Unit; and AYP Capital and its subsidiaries. Support business units which provide services to these revenue-generating business units have also been formed. The restructuring of Allegheny Power did not involve the formation of any new legal entities, nor did it require the writedown of any rate base assets. Moreover, no capital assets were transferred within Allegheny Power in connection with the restructuring.
Most of the functions which were performed exclusively by the Operating Subsidiaries have been restructured into the Operating Business Unit and Retail Marketing Business Unit. Most of the functions performed by the Bulk Power Supply section of APSC were restructured into the distinct generating, transmission, and planning and compliance business units. The support functions were restructured in order to supply services to the above with greater efficiency.
Most employees who have left service as a result of restructuring were offered a voluntary separation plan which included continuation of salary and certain benefits for up to eighteen months, job counseling and outplacement assistance, and in some cases an early retirement enhancement was offered. Allegheny Power anticipates that future reductions in force will occur due to normal attrition.
SALES
In 1996, consolidated kilowatt-hour (kWh) sales to regular customers (retail and wholesale power) increased 1.9% from those of 1995 as a result of increases of 2.5%, 2.1%, and .6% in residential, commercial, and industrial sales, respectively. The increased kWh sales in 1996 reflect both growth in number of customers for all classes and an increase in residential and commercial use. Consolidated revenues from residential sales increased .5%. Consolidated revenues from commercial and industrial sales decreased .2% and 2.25%, respectively, primarily due to decreases in fuel and energy recovery revenues which have little effect on net income. (See ITEM 1. RATE MATTERS and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.)
Bulk power transaction revenues, primarily with nonaffiliated utilities and power marketers, increased 30%. These revenues have little effect on net income as most profit therefrom is passed through to retail customers.
Allegheny Power's all-time peak load of 7500 MW occurred on February 5, 1996. The peak load in 1995 was 7280 MW.
Consolidated regulated electric operating revenues for 1996 were derived as follows: Pennsylvania, 44.9%; West Virginia, 27.9%; Maryland, 19.2%; Virginia, 6.0%; Ohio, 2.0% (residential, 40.1%; commercial, 21.2%; industrial, 32.3%; bulk power transactions, 3.2%; and other,
- 10 - 3.2%). The following percentages of such revenues were derived from these industries: iron and steel, 6.8%; fabricated products, 1.8%; chemicals, 3.5%; aluminum and other nonferrous metals, 3.4%; coal mines, 3.4%; cement, 2.5%; and all other industries, 11.0%.
During 1996, Monongahela's kWh sales to retail customers decreased .4%. Residential and commercial sales increased .3% and 2.0%, respectively, but industrial sales decreased 1.8%. Revenues from residential, commercial and industrial customers decreased 1.4%, 2.3%, and 5.4%, respectively, primarily due to a reduction in the fuel and energy cost component. Revenues from bulk power transactions and sales to affiliates increased 6.5%. Monongahela's revenues represented 24.0% of Allegheny Power's total sales to regular customers. Monongahela's all-time peak load of 1825 MW occurred on August 17, 1995.
Monongahela's electric operating revenues were derived as follows: West Virginia, 92.9% and Ohio, 7.1% (residential, 32.6%; commercial, 19.2%; industrial, 31.8%; bulk power transactions, 2.7%; and other, 13.7%).
During 1996, Potomac Edison's kWh sales to retail customers increased 3.1% as a result of increases of 5.1%, 3.4%, and 1.5% in residential, commercial, and industrial sales, respectively. Revenues from residential and commercial customers increased 2.3% and .9%, respectively. Revenues from industrial customers decreased 2.0% due to a reduction in the fuel and energy cost component. Revenues from bulk power transactions and sales to affiliates increased 22.8%. Potomac Edison's revenues represented 31.1% of Allegheny Power's total sales to regular customers. Potomac Edison's all-time peak load of 2614 MW occurred on January 17, 1997.
Potomac Edison's electric operating revenues were derived as follows: Maryland, 62.0%; West Virginia 18.9% and Virginia, 19.1%; (residential, 44.6%; commercial, 20.1%; industrial, 27.1%; bulk power transactions, 3.4%; and other, 4.8%). Revenues from one industrial customer, the Eastalco aluminum reduction plant near Frederick, Maryland, amounted to $64 million (8.8% 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 1996. This agreement may be canceled before the year 2000 upon 90 days notice of a governmental decision resulting in a material modification of the agreement.
During 1996, West Penn's kWh sales to retail customers increased 1.5% as a result of increases of 1.6%, 1.4% and 1.5% in residential, commercial, and industrial sales, respectively. Revenues from residential and commercial customers increased .2% and .2%, respectively. Revenues from industrial customers decreased .5% due to a reduction in the fuel and energy cost component. Revenues from bulk power transactions and sales to affiliates increased 10.7%. West Penn's revenues represented 44.9% of Allegheny Power's total sales to regular
- 11 - customers. West Penn's all-time peak load of 3242 MW occurred on February 5, 1996.
West Penn's electric operating revenues were derived as follows: Pennsylvania, 100% (residential, 36.9%; commercial, 20.6%; industrial, 32.6%; bulk power transactions, 3.0%; and other, 6.9%).
In 1996, AYP Energy provided 109,229 MWH of energy to nonaffiliated customers, including generation from the Fort Martin Unit No. 1 acquisition amounting to 44,014 MWH. Unregulated operating revenues in 1996 amounted to $.7 million.
In 1996, the Operating Subsidiaries provided approximately 1 billion kWh of energy to nonaffiliated companies and marketers from generation facilities operated by the Subsidiaries. Revenues from those sales of generation from the Operating Subsidiaries were approximately $22.4 million.
The Operating Subsidiaries transmitted approximately 17.4 billion kWh to others located outside their service territories under various forms of transmission service agreements. Revenues from those sales of service approximated $52.4 million.
Sales of generation and transmission services to others 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 sales of transmission services to others in 1996, sales of power generated by the Operating Subsidiaries did not change appreciably relative to 1995 primarily because of stagnant demand, increases in Allegheny Power's native load, and increased number of and willingness of other suppliers to make sales at lower prices. Decreases in sales by Allegheny Power of power generated from rate base assets to nonaffiliates and others are expected in 1997 and beyond. For 1996, substantially all of the benefits of power and transmission service sales to nonaffiliates by the Operating Subsidiaries 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 2000. 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 2000. 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.
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Pursuant to an exchange arrangement with Duquesne which will continue through February 2000 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.
Until March 16, 1996, West Penn supplied retail electric service to the Borough of Tarentum (Tarentum) using in part distribution facilities leased from Tarentum under a 30-year lease agreement which terminated in 1996. In June 1993, Tarentum 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 resulted in Tarentum becoming a municipal customer which at present purchases electricity on a wholesale basis from West Penn under a new 3-year contract. In 1996 Tarentum provided a load of 6.5 MW and revenues of $1.1 million.
The Energy Policy Act of 1992 (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. Of particular significance to public utilities, on April 24, 1996, the FERC issued its Orders 888 and 889. These Orders 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 is to stimulate wholesale (sale for resale) generation service competition among electric utilities and nonregulated electricity generators while preventing anti-competitive or discriminatory transmission practices. The Orders encourage wholesale competition by requiring utilities that own transmission systems and are under the FERC's jurisdiction to file nondiscriminatory, open access transmission tariffs available to all wholesale buyers and sellers of electricity and apply those open access tariffs to their own wholesale purchases and sales of electricity. Utilities must 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. When existing facility capacity is insufficient, transmission system owners are required to attempt to build additional facilities when customers are willing to support the cost of those facilities.
To meet the objective of providing nondiscriminatory or comparable wholesale transmission services, the Orders require that utilities functionally unbundle transmission operations from wholesale merchant functions. In addition, separate rates must be presented for wholesale generation, transmission and ancillary services. Accordingly, as of January 3, 1997, the FERC required separation of the transmission
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operations and marketing functions from the wholesale generation marketing function of public utilities. In response to both the process leading up to the FERC's adoption of Orders 888 and 889, and the continuing evolution of the wholesale power and transmission service markets, Allegheny Power in 1996 established separate business units to operate and manage its generation and transmission assets.
Effective July 9, 1996, the FERC required that wholesale transmission services be purchased by a transmission owner under that owner's filed open access tariffs whenever a generation affiliate of the owner intends to make wholesale generation service sales to any party. In addition, the Orders set standard terms which must be contained in each transmission provider's open access tariffs. Effectively, the tariffs contractually open the interconnected transmission network to provide comparable transmission service for use by the transmission owner, its affiliates and non-affiliates alike. Order 888 also states that electric utilities should be able to collect stranded costs that may result from restructuring of the wholesale electric industry. In addition, the Order provides that it is up to each state to decide if retail wheeling should be adopted and, if so, to address retail stranded costs. In a separate notice, the 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 and in Order 889 directed implementation of such a network. Although Allegheny Power has taken appropriate steps to comply, it has also requested rehearing of certain aspects of both Orders. Allegheny Power cannot predict what action the FERC may take on this request.
Effective in 1995 and consistent with the intentions of the FERC prior to its issuance of Orders 888 and 889, Allegheny Power submitted a filing to the FERC of a set of two new transmission service tariffs which qualified as open access filings. The FERC then accepted for filing a Network Transmission Service Tariff and a Point-to-Point Transmission Service Tariff under which the Operating Subsidiaries began to sell comparable open access transmission services to eligible wholesale customers as of December 1995. The tariffs were accepted by the FERC, subject to modification pending the outcome of the proceeding. The FERC set the tariffs for hearing during the summer of 1996. In the interim, the Operating Subsidiaries sold transmission services under the tariffs, subject to refund. Refunds, if any, are not expected to be material. With that filing, the need for and applicability of the Standard Transmission Service Tariff was eliminated for new service transactions.
With the issuance of Orders 888 and 889, the FERC mandated that most transmission owning entities (the major exclusion was tight power pools) had to issue or reissue open access transmission service tariffs which complied with the rules by July 9, 1996. Allegheny Power did so and the immediate effect was that its 1995 open access tariff filings became subsumed by the July filing of one all-encompassing tariff. However, the rates terms and conditions previously set for hearing were
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carried over to the new tariff. In January 1997, the tariffs were again modified to strictly comply with current FERC orders on non-rate terms and conditions. Allegheny Power still awaits an order on rates for the open access tariff.
In addition, the Operating Subsidiaries have a Standard Generation Service Schedule (SGS) tariff on file with and accepted by the FERC under which the Operating Subsidiaries previously made available bundled, nonfirm generation services with associated transmission services to any customer who executed an agreement under such tariff. Recently and in keeping with the unbundled service prescription of the FERC Orders, the SGS tariff has been amended to separate the provision of generation and transmission services. Customers in search of delivered wholesale power service from Allegheny Power now have to separately contract for generation and transmission services under the SGS and the Open Access Tariffs.
Similarly, as of December 1996, Allegheny Power filed to unbundle generation and transmission services sold under existing coordination agreements with contiguous public utilities.
Specifically in Order 889, the FERC established that an Open Access Same Time Information System (OASIS) and Standards of Conduct must be adopted by each transmission provider to ensure the separation of service directed by the functional unbundling of wholesale services required by Order 888 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 adopted and filed Standards of Conduct and joined with other transmission service providers in a collaborative effort to develop OASIS capability. OASIS became operational for processing requests for transmission services as of January 3, 1997; the Standards of Conduct were implemented on the same day.
Allegheny Power founded and continues to participate in, along with other utilities, an organization, General Agreement on Parallel Paths (GAPP) whose primary purpose is to develop a mutually acceptable method of resolving the inequities imposed on transmission network owners by parallel power flows. Allegheny Power also participated in the funding of and continued support of an organization known as the "Alliance" whose four transmission-owning members intend, among other things, to pursue a test of the GAPP methodology. To that end, a request for such experimentation authorization was submitted by the Alliance and two other GAPP members to the FERC in December 1996. Allegheny Power cannot predict what action the FERC may take on this request.
Under PURPA, certain municipalities, businesses and private developers have installed, are installing or are proposing to install 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
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consistent with PURPA and ordered by appropriate state commissions. As a result of PURPA, Allegheny Power is committed to 299 MW of on-line PURPA capacity. Payments for PURPA capacity and energy in 1996 totaled approximately $133 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 of PURPA capacity (Warrior Run) to come on-line in 1999. It is expected that the Warrior Run project will result in substantial costs for Potomac Edison's Maryland customers. Allegheny Power has attempted to negotiate a buyout or restructuring of the existing contract with the Warrior Run project developer to reduce the cost impact on customers. The negotiations have been unsuccessful. (See ITEM 3. LEGAL PROCEEDINGS for a description of litigation and regulatory proceedings in Pennsylvania and West Virginia concerning other proposed PURPA projects.)
ELECTRIC FACILITIES
The following table shows Allegheny Power's December 31, 1996, generating capacity, based on the maximum monthly normal seasonal operating capacity of each unit. Allegheny Power's owned capacity totaled 8070 MW, of which 7090 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 owned steam stations shown on the following page, based on generating capacity at December 31, 1996, was about 26.6 years. In 1996, their average heat rate was 9,910 Btu's/kWh, and their availability factor was 86.0%.
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(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/repowering of these units in about five years. On December 31, 1994, 82 MW of the total MW at Mitchell Power Station were reactivated. Also excludes 276 MW of Unit No. 1 of Fort Martin merchant plant capacity owned by AYP Energy which is not subject to price regulation by any regulatory commission.
(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) West Penn has a 30-year license for Lake Lynn, effective December 1994. Potomac Edison's license for hydroelectric facilities Dam No. 4 and Dam No. 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 180-MW Warrior Run project has completed its financial closing, is under construction, and is planned to begin providing capacity and energy to Potomac Edison in 1999.
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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.
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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, 1996:
Above Ground Transmission and Distribution Lines (a) and Substations
(a) Allegheny Power has a total of 6,083 miles of underground distribution lines.
(b) The substations have an aggregate transformer capacity of 39,357,495 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 early 1996, use of the transmission system in aggregate declined and the west-to-east power flows decreased to more comfortable levels. However, beginning in the summer months of 1996, west-to-east transfers increased and occasionally reached 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, may again operate more frequently nearer to reliability limits at which time restrictions on transfers may become necessary. (SEE discussion concerning General Agreement on Parallel Paths and the Alliance under ITEM I. SALES.)
Wholesale generators and other wholesale customers may now seek from owners of bulk power transmission facilities a commitment to supply transmission services. (See discussion under ITEM 1. SALES.) Such demand on Allegheny Power's transmission facilities may add to heavy power flows on Allegheny Power's facilities.
The Operating Subsidiaries have, since the early 1980's, provided managed contractual access to Allegheny Power's transmission facilities under various tariffs. As described earlier, for new agreements starting in 1996, managed access will also be governed by the
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provisions of the Allegheny Power open access tariffs recently filed with the FERC.
RESEARCH AND DEVELOPMENT
The Operating Subsidiaries spent $7.7 million, $9.0 million, and $7.7 million, in 1996, 1995, and 1994, respectively, for research programs. Of these amounts, $5.5 million, $6.2 million, and $5.9 million were for Electric Power Research Institute (EPRI) dues in 1996, 1995, and 1994, respectively. EPRI is an industry-sponsored research and development institution. The Operating Subsidiaries plan to spend approximately $7.5 million for research in 1997, with EPRI dues representing $5.7 million of that total.
In addition to EPRI support, in-house research conducted by Allegheny Power concentrated on environmental protection, generating unit performance, transmission system performance, future generating technologies, delivery systems, customer-related research, clean power technology focused on power quality and load management devices, and techniques for customer and delivery equipment. All in-house research is related to adapting both competitive and leading edge technology to Allegheny Power's operations.
Research is also being directed to help address major issues facing our industry, including electric and magnetic field (EMF) assessment of employee exposure within the work environment, waste disposal and discharges, greenhouse gases, renewable resources, fuel cells, new combustion turbines and cogeneration technologies. A constructed wetlands project at Allegheny Power's Springdale Power Station significantly improved the water quality of the effluent from a closed ash management facility. The project received the 1996 Industrial Excellence Award from the Pennsylvania Water Environment Association. During 1996, Allegheny Power supported the federal government's National EMF Research and Public Information Dissemination Program, a project on biomechanisms with the Massachusetts Institute of Technology, and an Edison Electric Institute (EEI) program to study employee and public health effects, if any, of EMF. The financial effect of these issues on Allegheny Power, if any, cannot be determined at this time. In addition, there is continuing evaluation of technical proposals from outside sources and monitoring of developments in industry-related literature, law and litigation, general business and environmental standards (ISO 9000 AND ISO 14000), and intellectual property rights.
Because of the NOx control requirements of the CAAA, Allegheny Power is participating in 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. Other research is directed at NOx control technologies for power station compliance. Allegheny Power
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continues to monitor and demonstrate technical solutions to greenhouse gas reduction, sequestration, capture, and control.
As part of its response to Energy Policy Act of 1992 and the subsequent Clinton Climate Action Plan, Allegheny Power, as part of an EEI program, has agreed to participate in research initiatives which are designed to reduce, sequester or control greenhouse gases. This program is consistent with filings made with the Department of Energy (DOE) in voluntary compliance with Section 1605(b) of EPACT.
Electric vehicle (EV) research in 1996 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.
In 1996 research was also directed into communication systems to develop and demonstrate a high speed advanced power line communication system utilizing existing utility wires to service information and automation needs of Allegheny Power's customers and to support system requirements in retail wheeling.
Allegheny Power continues to pursue beneficial uses of coal combustion by-products. In cooperation with the West Virginia Division of Environmental Protection, a project is under way to investigate the feasibility and cost-effectiveness of injecting fly ash from Allegheny Power's power stations into abandoned underground mine sites in West Virginia to reduce acid mine drainage and mine surface subsidence. The project cost is being shared with EPRI as part of a Tailored Collaboration Agreement. Also being investigated is the use of fly ash as a construction material.
As part of customer research, a model home program is being developed and adjustable speed drives for customer motor loads are being used at a steel company and at an extrusion process plant. An effort in which Allegheny Power participated through West Penn in 1996 is 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.
In 1996 the Operating Subsidiaries 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 1996 amounted to $289 million and for 1997 and 1998 are expected to aggregate $322 million and $324 million, respectively. In 1996, these expenditures included $3 million for compliance with the CAAA. The 1997 and 1998 estimated expenditures include $15 million and $42 million,
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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.
Construction Expenditures
* Includes allowance for funds used during construction (AFUDC) for 1996, 1997 and 1998 of: Monongahela $0.7, $1.8 and $2.5; Potomac Edison $2.5, $2.2 and $2.7; and West Penn $2.7, $3.4 and $4.5.
** Includes amounts for capital projects connected with the restructuring of $22.4, $40.5 and $1.8 for 1996, 1997 and 1998, respectively.
These construction expenditures include major capital projects at existing generating stations, upgrading distribution lines and substations, and the strengthening of the transmission and
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subtransmission systems. They also include $22.4 million, $40.5 million and $1.8 million in 1996, 1997 and 1998, respectively, for new systems resulting from the restructuring effort.
On a collective basis for the Subsidiaries, expenditures for 1996, 1997, and 1998 include $43 million, $37 million, and $59 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 and meet existing customer demand and future increases in customer demand, including 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, acquisition of energy and capacity from third-party suppliers.
Potomac Edison is engaged in implementing state commission ordered 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 1.35% and 1.49%, respectively, in the period 1997-2007. It is anticipated that the reactivation of Mitchell No. 2 Unit, the repowering of Springdale No. 8 Unit, peak diversity exchange arrangements (described under ITEM 1. SALES), demand-side management and conservation programs, and mandated PURPA capacity will be sufficient for Allegheny Power's needs until the year 2000 and beyond. The advent of retail competition may have a significant effect on load growth.
In connection with its construction and demand-side management programs, Allegheny Power must make estimates of the availability and cost of capital as well as the future demands of its customers that are necessarily subject to regional, national, and international developments, changing business conditions, and other factors. The construction of facilities and their cost are affected by laws and regulations, lead times in manufacturing, availability of labor, materials and supplies, inflation, interest rates, and licensing, rate, environmental, and other proceedings before regulatory authorities. Decisions regarding construction of facilities must now also take into account retail competition. As a result, future plans of Allegheny Power are subject to continuing review and substantial change.
The Subsidiaries have financed their construction programs through internally generated funds, first mortgage bonds, debentures, medium-term notes, subordinated debt and preferred stock issues, pollution control and solid waste disposal notes, installment loans, long-term lease arrangements, equity investments by APS (or, in the case
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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. 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 Energy financed its $170 million acquisition of 276 MW of Fort Martin Unit No. 1 from Duquesne with a combination of $25 million of equity from APS and $160 million of 5-year debt financing provided by a syndicate of banks. Funds in excess of the purchase price will be used to fund operations. AYP Energy's obligation under the Credit Agreement is supported by APS. The debt is priced at a floating rate. Prior to closing the transaction, AYP Energy entered into a $160 million forward swap to hedge against fluctuations in interest rates during the 5-year period.
In 1996, APS sold 1,139,518 shares of its common stock for $33.8 million through its Dividend Reinvestment and Stock Purchase Plan and its Employee Stock Ownership and Savings Plan.
During 1996, 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 4.185%, 4.04%, 4.245%, and 4.018%. The rate set at auction on January 14, 1997 was 4.008%.
At December 31, 1996, short-term debt was outstanding in the following amounts: APS $84.4 million, Monongahela $31.1 million, Potomac Edison $7.5 million, and West Penn $33.4 million. At December 31, 1996, AGC had $20.0 million of commercial paper outstanding.
The Subsidiaries' ratios of earnings to fixed charges for the year ended December 31, 1996, were as follows: Monongahela, 3.44; Potomac Edison, 3.25; West Penn, 2.88; and AGC, 3.48.
Allegheny Power's consolidated capitalization ratios as of December 31, 1996, were: common equity, 45.8%; preferred stock, 3.6%; and long-term debt, 50.6%, including Quarterly Income Debt Securities (QUIDS) (3.3%). Allegheny Power's long-term objective is to maintain the common equity portion above 46%.
During 1997, Monongahela plans to issue $45 million of new debt for general corporate purposes, including its construction program. Potomac Edison and West Penn currently anticipate meeting their capital requirements through a combination of internally generated funds, cash on hand, and short-term borrowing as necessary. However, West Penn may issue debt securities pursuant to the securitization provisions of the
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Pennsylvania legislation of December 3, 1996. 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 16.4 million tons of coal in 1996. Of that amount, 86% was either cleaned (5.0 million tons) or used in stations equipped with scrubbers (9.1 million tons). The use of desulfurization equipment and the cleaning and blending of coal make burning local higher-sulfur coal practical. In 1996, about 99% of the coal received at Allegheny Power-operated stations came from mines in West Virginia, Pennsylvania, Maryland, and Ohio. Allegheny Power does 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 to provide for approximately 14.8 million tons of coal in 1997. 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 1992 through 1995, the average cost per ton of coal burned was $36.31, $36.19, $35.88, and $32.68, respectively. For the year 1996, the cost per ton decreased to $32.25.
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 coal combustion by-products for beneficial uses and thereby reduce landfill requirements. (See ITEM 1. RESEARCH AND DEVELOPMENT.) In 1996, the Operating Subsidiaries received approximately $919,000 from the sale of 131,000 tons of fly ash and 168,000 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 higher sulfur coal recoverable by deep mining. There are no present plans to mine these reserves and, in view of economic conditions now prevailing in the coal market, the Operating Subsidiaries plan to hold the reserves as a long-term resource.
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RATE MATTERS
On October 29, 1996 the Virginia State Corporation Commission (SCC) approved an agreement filed by Potomac Edison and staff of the SCC that reduced rates effective November 1, 1996, by $1.2 million (1%) on an annual basis. The agreement was the result of an Annual Informational Filing required by the SCC.
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). Pursuant to a settlement agreement filed April 4, 1996, with the FERC, AGC's ROE was set at 11% for 1996 and will continue until the time any affected party seeks renegotiation of the ROE. Notice of such intent to seek a revision in ROE must be filed during a notice period each year between November 1 and November 15. No requests for change were filed during the 1996 notice period. Therefore, AGC's ROE will remain at 11% for 1997.
Currently all state regulatory jurisdictions and the FERC utilize special procedures to recognize changes in fuel and other energy costs in rates on a more current basis than other costs. These procedures, generally referred to as energy recovery or fuel clauses, use an expedited proceeding schedule, and require the companies to use a tracking procedure to compare revenues received for energy costs with actual energy costs incurred. Differences are deferred until the next proceeding when energy rates are adjusted to return or recover previous overrecoveries or underrecoveries, respectively. Because of this procedure, changes in fuel and other energy costs have had little effect on net income.
The Pennsylvania competition legislation capped West Penn's rates, including its energy cost rates, effective January 1, 1997. Since the new legislation left the method of future rate adjustments for energy costs to Pennsylvania PUC discretion, West Penn on February 28, 1997 filed a Petition with the Pennsylvania PUC to roll the energy cost rates into its base rates. Upon receipt of an order of approval, West Penn would then assume the risks of increases in the costs of fuel and purchased power and any declines in bulk power transaction sales. However, West Penn would also retain the benefits of decreases in such costs and increases in such sales. West Penn would accomplish this result by discontinuance of deferred fuel accounting.
On May 23, 1996, the Pennsylvania PUC approved a settlement authorizing West Penn to recover all of the costs ($31 million) associated with termination of a power supply contract with the Shannopin PURPA project. This contract was negotiated under the requirements of PURPA. The majority of cost recovery ($24 million) was accomplished by reducing West Penn's overrecovered fuel balance. Effective July 9, 1996, West Penn's energy cost rates were decreased by $5.1 million annually. The remaining Shannopin costs ($7 million) were to be recovered in 1997 and 1998, but, pursuant to the rate caps enacted
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by the new Pennsylvania competition legislation, will be recovered through other means.
On June 25, 1996, the Public Service Commission of West Virginia approved stipulated agreements in the annual Expanded Net Energy Cost proceedings under which Monongahela and Potomac Edison customers will receive annual decreases in their energy rates of $19.5 million and $5.3 million, respectively. Included for both companies was a small increase in base rates to cover additional costs for CAAA-related investments and operating expenses. The new rates became effective July 1, 1996.
Annual audit reports on fuel-related items for Monongahela were filed with the Ohio Public Utilities Commission on October 11, 1996. A fuel rate change was effective February 1, 1997, and reflected a slight decrease.
By order dated June 20, 1996, the Maryland Public Service Commission accepted a stipulation and agreement that approved a decrease in fuel rates to Potomac Edison's Maryland customers of $6.8 million annually. This decrease resulted from fuel costs declining by more than 5% when measured by a commission formula.
A Virginia SCC order dated March 6, 1996, approved an annual increase in fuel rates to Potomac Edison's Virginia customers of $315,000 effective March 7, 1996. This increase resulted from the SCC's annual fuel cost review. On February 14, 1997, Potomac Edison requested the Virginia SCC to permit it to continue to charge its currently authorized fuel rates until further order of the commission.
ENVIRONMENTAL MATTERS
The operations of the Allegheny Power-operated stations are subject to regulation as to air and water quality, hazardous and solid waste disposal, and other environmental matters by various federal, state, and local authorities.
Meeting known environmental standards is estimated to cost the Subsidiaries about $189 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.
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Allegheny Power meets current emission standards as to SO2 by the use of scrubbers, the burning of low-sulfur coal, the purchase of cleaned coal to lower the sulfur content, and the blending of low-sulfur with higher sulfur coal.
The CAAA, among other things, require an annual reduction in total utility emissions within the United States of 10 million tons of SO2 and two million tons of NOx from 1980 emission levels, to be completed in two phases, Phase I and Phase II. Five coal-fired 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 SO2 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 SO2 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 most of the Allegheny Power-operated 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, Pennsylvania, and West Virginia for ozone nonattainment (Title I) reasons. Continuous emission monitoring equipment has been installed on all Phase I and Phase II units.
In an effort to introduce market forces into pollution control, the CAAA created SO2 emission allowances. An allowance is defined as an authorization to emit one ton of SO2 into the atmosphere. Subject to regulatory limitations, allowances (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.
Pursuant to an option in the CAAA and in order to avoid the potential for more stringent NOx limits in Phase II, Allegheny Power chose to treat five Phase II, Group 1 boilers (tangential- and wall- fired) as Phase-I-affected units (Substitution Units) for calendar year 1996. Additionally, three of the four Phase II, Group 2 boilers (top- and cyclone-fired) were also made Substitution Units for 1996. The status of all Substitution Units is evaluated on an annual basis to ascertain the financial benefits of retaining these units as Phase-1- affected units. As a result of being Phase-I-affected, these Substitution Units will also be required to comply with the Phase I SO2
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limits for each year that they are accorded substitution status by Allegheny Power. Phase I NOx and SO2 compliance for these units should not require additional capital or operating expenditures.
Title I of the CAAA established an ozone transport region (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 Environmental Protection Agency (EPA) to remove western Pennsylvania from the OTR. The EPA has denied the request. Sources within the OTR will be required to reduce NOx emissions, a precursor of ozone, to a level conducive to attainment of the ozone National Ambient Air Quality Standards (NAAQS). The installation of reasonably available control technology (RACT) (overfire air equipment and/or low NOx burners) at all Pennsylvania and Maryland stations has been completed. The installation of RACT satisfies both Title I and Title IV NOx reduction requirements.
Title I of the CAAA also established an Ozone Transport Commission (OTC), which has determined that Allegheny Power will be required to make additional NOx reductions beyond RACT in order for the OTR to meet the ozone NAAQS. Under terms of a Memorandum of Understanding (MOU) among the OTR states, Allegheny Power-operated stations located in Maryland and Pennsylvania will be required to reduce NOx emissions by approximately 55% from the 1990 baseline emissions, with a compliance date of May 1999. Further reductions of 75% from the 1990 baseline may be required by May 2003, unless the results of modeling studies, due to be completed by 1998, indicate otherwise. If Allegheny Power has to make reductions of 75%, it could be very expensive and would depend upon the installation of post-combustion control technologies. 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 NOx and Volatile Organic Compounds (VOCs) in 37 states east of and bordering the west bank of the Mississippi River plus Texas. OTAG is similar to the OTC in purpose and organization and could lead to additional NOx controls on certain Allegheny Power-operated stations in West Virginia. There is no assurance that NOx control for non-OTR states will be limited to RACT. What occurs in the non-OTR states could also affect whether Allegheny Power-operated stations in Maryland and Pennsylvania would need post- RACT controls. OTAG plans to issue recommendations by late spring 1997.
The EPA is required by law to regularly review the NAAQS for criteria pollutants. Recent court orders due to litigation by the American Lung Association have expedited these reviews. The EPA in 1996 concluded not to revise the SO2 and NOx standards. Revisions to particulate matter and ozone standards were proposed by the EPA in 1996 and will likely be finalized in 1997. The impact on Allegheny Power of any revision to these standards is unknown at this time but could be substantial if the 1996 recommendations become requirements.
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In 1989, the West Virginia Air Pollution Control Commission approved the construction of a third-party cogeneration facility in the vicinity of Rivesville, West Virginia. Emissions impact modeling for that facility raised concerns about the compliance of Monongahela's Rivesville Station with ambient standards for SO2. Pursuant to a consent order, Monongahela agreed to collect on-site meteorological data and conduct additional dispersion modeling in order to demonstrate compliance. The modeling study and a compliance strategy recommending construction of a new "good engineering practices" (GEP) stack were submitted to the West Virginia Department of Environmental Protection (WVDEP) in June 1993. Costs associated with the GEP stack are approximately $20 million. Monongahela is awaiting action by the WVDEP.
Under an EPA-approved consent order with Pennsylvania, West Penn completed construction of a GEP stack at the Armstrong Power Station in 1982 at a cost of over $13 million with the expectation that EPA's reclassification of Armstrong County to "attainment status" under NAAQS for SO2 would follow. As a result of the 1985 revision of its stack height rules, EPA refused to reclassify the area to attainment status. Subsequently, West Penn filed an appeal with the U.S. Court of Appeals for the Third Circuit for review of that decision as well as a petition for reconsideration with EPA. In 1988, the Court dismissed West Penn's appeal stating it could not decide 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 and Pennsylvania disposal sites contain what Allegheny Power believes are overly stringent discharge limitations. Allegheny Power is working cooperatively with the states to develop alternate water quality criteria which will result in less stringent permit limits. If this effort is unsuccessful, 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 established a two-tiered application process for discharges
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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 established 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 (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 Land Recycling Act, adopted in 1996, allows for the development and application of site-specific, risk-based groundwater cleanup standards to both abandoned and active industrial sites. The intent is to encourage the reuse of abandoned but contaminated industrial sites and to allow for continual operation of industrial sites whose operation began before groundwater protection statutes were in place -- as long as it can be demonstrated by the owner/operator that there is little or no risk to human health or the environment. A similar statute has passed in West Virginia and implementing regulations are being drafted in both states. It is anticipated that the final rules should provide for reasonable and cost-effective groundwater cleanup of Allegheny Power facilities should it become necessary and will encourage economic development in Allegheny Power's service territories in Pennsylvania and West Virginia.
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
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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 and 1996 for expansion of existing coal combustion by-product (CCB) disposal sites due to requirements for installation of liners on new sites and assessment of groundwater effects 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 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. A work group comprised of a number of state agencies and utility company representatives has been proposed and will be formed by PADEP to encourage beneficial use of CCBs. A similar work group is operating in West Virginia with Allegheny Power support and participation.
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 and the Butler Tunnel Superfund Site in Pennsylvania. (See ITEM 3. LEGAL PROCEEDINGS for a description of these Superfund cases.)
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 Energy are
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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. Bills were introduced in the last Congress to repeal PUHCA, but did not pass. Similar bills will likely be introduced in the 105th Congress. However, Allegheny Power cannot predict what changes, if any, will be made to PUHCA as a result of these activities.
The FERC issued Orders 888 and 889 on April 24, 1996. (See ITEM 1. SALES for a discussion of these Orders.)
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. Maryland, Pennsylvania, Ohio, Virginia, and West Virginia declined to adopt the federal standards, concluding that existing state regulations adequately address the issues.
Although regulatory agencies in Ohio and West Virginia have considered competitive bidding rules for long-term purchase of capacity and energy by electric utilities, neither has yet imposed such a requirement.
As part of its investigation into market competition and regulatory policies, the Maryland PSC, in an Order issued August 18, 1995, 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. (See ITEM 1. COMPETITION for more information on Maryland and other state utility commission investigations into competition.)
Virginia has not mandated competitive bidding for capacity additions.
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 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.
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In December 1994, West Penn filed responses to the questions. West Penn cannot predict the outcome of this proposed rulemaking.
During 1996, Potomac Edison continued its participation in the Collaborative Process for demand-side management in Maryland. Rebates paid in the various programs totaled $394,000 and the savings in future generation requirements was 746 kW. The surcharge for recovery of demand-side management was revised based on a September 1996 Maryland PSC order. The surcharge for commercial and small and intermediate industrial customers was set at approximately 6% of revenue while the surcharge for large industrial and residential customers was approximately 1% of revenue.
In 1996, the Operating Subsidiaries continued to take part in and fund various programs to assist low income customers, customers with special needs, and/or customers experiencing temporary financial hardship.
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, rights-of-way, permits or other arrangements, many of which have not been recorded and some of which are not evidenced by formal grants. In some cases no examination of titles has been made as to lands on which transmission and distribution lines and substations are located. Each of the 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
Pursuant to PURPA, 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
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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.
West Penn and the developers of the Shannopin project reached an agreement on January 25, 1996, which provided that West Penn would buy out the Shannopin EEPA and terminate the project and all pending litigation associated with the Shannopin project for a price of $31 million. The buyout agreement was approved by the Pennsylvania PUC on May 28, 1996, and provided for full pass through of the buyout price to West Penn's customers through the energy cost rate by no later than March 31, 1999. Because the buyout agreement includes full pass-through of the buyout price to customers, it will not have a material effect on West Penn's net income.
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 Burgettstown EEPA, as modified by Pennsylvania PUC orders, automatically terminated in accordance with its terms, as the financing closing had not occurred by May 8, 1995, and Burgettstown did not request a further extension.
On May 2, 1995, Washington Power, the developer of Burgettstown, 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. This complaint was later amended to add a count alleging wrongful use of civil proceedings. On April 1, 1996, Champion Processing, Inc., North Branch Energy, Inc., and Air Products and Chemicals, Inc., claiming involvement or potential involvement in the Burgettstown project, filed a similar complaint alleging anti-trust violations, unfair competition and intentional interference with a contract. The complaints have been consolidated. 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 sought to require West Penn to purchase 240 MW of power from a proposed coal-fired PURPA project to be built in Fayette County,
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Pennsylvania. West Penn opposed this complaint as the power was not needed and the price proposed by South River was 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 October 7, 1996, the PUC dismissed the complaint on the basis that the developers had failed to demonstrate that they had "a defined and viable" Qualifying Facility (QF) project. The developers appealed to the Commonwealth Court. That appeal is pending. West Penn cannot predict the outcome of this proceeding.
On September 7, 1995, MidAtlantic Energy (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 a proposed PURPA project and interference with MidAtlantic's contract with the Babcock and Wilcox Company (B and W), among other things. This suit followed an unsuccessful complaint proceeding by MidAtlantic requesting the West Virginia PSC order Monongahela and Potomac Edison to purchase capacity and energy from the project. The MidAtlantic suit also named B and W as a defendant. MidAtlantic seeks compensatory and punitive damages. Monongahela, Potomac Edison and APS filed an answer and B and W filed an answer and counterclaim. 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, filed a Petition to Reopen and for Emergency Interim Relief with the West Virginia PSC to modify its power purchase contract with Monongahela. The modifications would have increased the price of project energy. The West Virginia PSC dismissed the petition on March 29, 1996. On August 13, 1996, ABPP filed a request for arbitration alleging that the energy rate payable under the purchase power contract had been improperly calculated. The first phase of the arbitration proceeding is scheduled for March 1997. Monongahela cannot predict the outcome of this proceeding.
As of January 16, 1997, Monongahela has been named as a defendant along with multiple other defendants in a total of 6,700 pending asbestos cases involving one or more plaintiffs. Potomac Edison and West Penn have been named as defendants along with multiple other defendants in approximately one-half of those cases. Because these cases are filed in a "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
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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. 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 January 27, 1995, Allegheny Power filed a declaratory judgment action in the Court of Common Pleas of Westmoreland County, Pennsylvania 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. 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. This case was settled in 1996.
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. A final determination has not been made for the Operating Subsidiaries' share of the remediation costs based on the amount of materials sent to the site. However, at this time it is estimated that the impact to the Operating Subsidiaries will not be material.
Potomac Edison received a questionnaire on October 1, 1996 from the EPA concerning a release or threat of release of hazardous substances, pollutants, or contaminants into the environment at the Butler Tunnel Site located in Luzerne County, Pennsylvania. Potomac
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Edison notified the EPA that it has no records or recollection of any business relations with the site or any of the companies identified in the questionnaire. It is not possible to determine at this time what impact, if any, this matter may have on Potomac Edison.
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 remand order has been appealed and negotiations are ongoing to settle this matter. The Operating Subsidiaries cannot predict the outcome of this proceeding.
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.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
APS, Monongahela, Potomac Edison, West Penn and AGC did not submit any matters to a vote of shareholders during the fourth quarter of 1996.
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Executive Officers of the Registrants
The names of the executive officers of each company, their ages as of December 31, 1996, the positions they hold, or held during 1996, and their business experience during the past five years appears below:
(a) All officers and directors are elected annually. (b) Retired as CEO effective June 1, 1996, and as Chairman to be effective May 8, 1997. (c) Retired effective July 1, 1996.
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(a) All officers and directors are elected annually. (b) Prior to joining Allegheny Power, Mr. Morrell was a V.P. - Regulatory and Public Affairs, Jersey Central Power & Light Company (JCP&L) (8/94-4/96); V.P. - Materials, Services and Regulatory Affairs, JCP&L, (1/93-8/94); and V.P. and Treasurer, GPU, Inc. and Subsidiaries (2/86-1/93). (c) Retired effective July 1, 1996. (d) Prior to joining Allegheny Power, Ms. Schaff was a Federal Affairs Representative with the Union Electric Company (4/88-12/95).
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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, 1996, there were 58,677 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 March 6, 1997 were $30-3/4 and $30- 1/2. The last reported sale on that date was at $30-5/8.
Monongahela, Potomac Edison, and West Penn. The information required by this Item is not applicable as all the common stock of the Operating Subsidiaries is held by APS.
AGC. The information required by this Item is not applicable as all the common stock of AGC is held by Monongahela, Potomac Edison, and West Penn.
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ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Page No.
APS D-1 Monongahela D-3 Potomac Edison D-5 West Penn D-7 AGC D-9
D-1
(a) Prior period amounts have been reclassified for comparative purposes to reflect a change in 1996 for reporting certain bulk power transmission transactions. (b) To record unbilled revenues, net of income taxes. (c) Reflects a two-for-one common stock split effective November 4, 1993. (d) Excludes the cumulative effect of the accounting change in 1994 and includes the effect of restructuring in 1995 and 1996. (e) Capability available through contractual arrangements with nonutility generators. (f) Preliminary.
D-3
(a) Prior period amounts have been reclassified for comparative purposes to reflect a change in 1996 for reporting certain bulk power transmission transactions. (b) To record unbilled revenues, net of income taxes. (c) Excludes the cumulative effect of the accounting change in 1994 and includes the effect of restructuring in 1995 and 1996.
D-4
(a) Capability available through contractual arrangements with nonutility generators. (b) Prior period amounts have been reclassified for comparative purposes to reflect a change in 1996 for reporting certain bulk power transmission transactions.
D-5
The Potomac Edison Company
(a) Prior period amounts have been reclassified for comparative purposes to reflect a change in 1996 for reporting certain bulk power transmission transactions. (b) To record unbilled revenues, net of income taxes. (c) Excludes the cumulative effect of the accounting change in 1994 and includes the effect of restructuring in 1995 and 1996.
D-6
(a) Prior period amounts have been reclassified for comparative purposes to reflect a change in 1996 for reporting certain bulk power transmission transactions.
D-7
West Penn Power Company and Subsidiaries
(a) Prior period amounts have been reclassified for comparative purposes to reflect a change in 1996 for reporting certain bulk power transmission transactions. (b) To record unbilled revenues, net of income taxes. (c) Excludes the cumulative effect of the accounting change in 1994 and includes the effect of restructuring in 1995 and 1996.
D-8
West Penn Power Company and Subsidiaries
(a) Capability available through contractual arrangements with nonutility generators. (b) Prior period amounts have been reclassified for comparative purposes to reflect a change in 1996 for reporting certain bulk power transmission transactions.
D-9
*Reflects a balance sheet reclassification of $12 million from deferred charges to plant for a prior tax payment.
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ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Page No. APS M- 1 Monongahela M-12 Potomac Edison M-20 West Penn M-28 AGC M-38
M-1 Allegheny Power System
Management's Discussion and Analysis of Financial Condition and Results of Operations
Review of Operations Earnings Earnings for 1996, 1995, and 1994, and the after tax restructuring charges, asset write-offs, and cumulative effect of accounting change included in each period are:
*Changes in revenues from fuel and energy cost adjustment clauses have little effect on consolidated net income. See "Rate Caps" under Competition in Core Business on page M-10 for information regarding a potential change in the fuel and energy cost adjustment clause (Energy Cost Rate or ECR) in Pennsylvania.
The increase in Kwh sales in 1996 was attributable to increases in each of the residential, commercial, and industrial customer classes. Residential Kwh sales increased 3% in both 1996 and 1995. These increases, which are more weather sensitive than commercial and industrial sales, were due primarily to increased customer usage and continued growth in the number of customers. The Company measures the effect of weather conditions on its utility sales by using degree days, which reflect the differences between the average daily actual temperature and the baseline temperature of 65 degrees. In 1996, heating degree days in the relatively colder January-through-April period were about 10% greater than the corresponding 1995 period. This increase was somewhat offset by milder weather during the remainder of the year. In 1995, increased sales resulted from extremely hot summer weather and cooler-than-normal winter weather.
The 2% increase in commercial sales in 1996 and the 5% increase in 1995 reflect growth in the number of customers, and, in 1995, also reflects increased customer usage. Industrial sales increased 1% and 4% in 1996 and 1995, respectively. Excluding the decrease in the fuel and energy cost component of industrial sales, revenues from sales to industrial customers also increased over 1% in 1996. The increase in Kwh sales reflects a trend of economic growth in the service territory and the efforts of the newly formed Retail Marketing Business Unit. With the increased potential for retail competition and in light of the Pennsylvania legislation (see Competition in Core Business on M-8), this function has been expanded to increase efforts to retain and acquire customers and to expand into other markets.
M-3
Increases resulting from rate changes were minimal for 1996, as the base rate increases effective in 1994 have been fully reflected in both the 1996 and 1995 periods. As a result of the Pennsylvania competition legislation, West Penn Power's (West Penn) rates have been capped effective January 1, 1997. This is more fully described on page M-9.
The increase in wholesale and other revenues in 1996 resulted primarily from load additions to the wholesale customers' systems (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 FERC). Competition in the wholesale market for electricity was enhanced by the 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. An agreement in principle was reached with one customer in 1996, representing $3 million in annual wholesale revenues, for a new five-year contract effective in 1997. With this new contract, all of the wholesale customers have signed contracts to remain as customers for periods ranging from two to six years. Kwh deliveries to and revenues from bulk power transactions consist of the following items:
The final rules on open transmission access, issued by the FERC in early 1996, require utilities to offer to others transmission service that is comparable to service they provide to themselves. Increased transmission services in 1996 resulted primarily from increased activity from power marketers who have agreed to take service under the new open access tariffs filed by the subsidiaries in accordance with these rules. Deliveries from the sale of 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. About 95% of the aggregate benefits from bulk power transactions are passed on to retail customers through fuel cost adjustment clauses and have little effect on consolidated net income. See page M-10 for information regarding the potential change in the ECR for Pennsylvania.
Operating Expenses
The 1% increase in fuel expenses in 1996 was due to a 2% increase in Kwh generated, offset in part by lower average coal prices. The 7% decrease in fuel expenses in 1995 was primarily the result of renegotiations of long-term fuel contracts which reduced fuel prices
M-4
effective in January 1995. Fuel expenses for the regulated subsidiaries 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 their fuel expenses have little effect on consolidated net income. See page M-10 for information regarding the potential change in the ECR for Pennsylvania.
"Purchased Power and Exchanges, Net" represents power purchases from and exchanges with other utilities and purchases from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and consists of the following items:
The decrease in purchase costs 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. In 1996, West Penn and the developers of a proposed Shannopin PURPA project reached an agreement to terminate the project at a buyout price of $31 million. The Pennsylvania Public Utility Commission (PUC) has authorized full recovery of the buyout price, of which $24 million was recovered by reducing West Penn's over-recovered fuel balance. The remaining $7 million was to be recovered in 1997 and 1998, but, pursuant to the recent Pennsylvania rate caps enacted by the new Pennsylvania Electric Generation Customer Choice and Competition Act, will be recovered through other means. The buyout will save West Penn's customers approximately $665 million over the next 30 years by eliminating the need to buy the uneconomic power.
A PURPA power station project in The Potomac Edison Company's (Potomac Edison) Maryland jurisdiction is scheduled to commence generation in 1999. Because of the high cost of this energy, Potomac Edison has attempted to negotiate a buyout or restructure the existing contract to reduce the cost to customers. To date, the negotiations have been unsuccessful. This project will significantly increase the cost of power purchases.
None of the subsidiaries' purchased power contracts is capitalized since there are no minimum payment requirements absent associated Kwh generation. The cost of power purchased, including power from PURPA generation, is mostly recovered from customers currently through the regular fuel and energy cost recovery procedures with the result that changes in such costs have little effect on consolidated net income. See page M-10 for information regarding the potential change in the ECR for Pennsylvania.
M-5
The increase in other operation expense in 1996 resulted primarily from increased allowances for uncollectible accounts ($4 million) and the write-off of deferred Clean Air Act Amendments of 1990 (CAAA) compliance costs ($4 million). For 1997 and thereafter, operations expense is expected to reflect the benefits of savings related to the restructuring activities. Allowances for uncollectible accounts increased 40% in 1996 due to an increase in aged accounts receivable caused primarily by regulations in Pennsylvania which severely restrict curtailment of service to non-paying customers.
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. 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.
Restructuring charges and asset write-offs resulted primarily from the completion of restructuring initiatives undertaken in 1995 and the write-off of previously accumulated costs related to a proposed transmission line. See Note B to the Consolidated Financial Statements for additional information.
Depreciation expense increases resulted primarily from additions to electric plant. The subsidiaries began depreciating the Harrison scrubbers in mid-November 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 planned capital expenditures.
The increase in taxes other than income in 1996 was due to higher property taxes and, in 1995, reflects increases in gross receipts taxes resulting from higher revenues from retail customers. The net decrease in federal and state income taxes in 1996 resulted primarily from a decrease in income before taxes ($23 million), which was primarily related to restructuring charges recorded in 1996. The net increase of $28 million in federal and state income taxes in 1995 resulted primarily from an increase in income before taxes ($20 million) and an increase in reversals of prior year depreciation benefits for which deferred taxes were not then provided ($6 million). 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 1996 and 1995 were $2 million and $11 million, respectively, and reflect decreases in capital expenditures due to substantial completion of the program to comply with Phase I of the CAAA.
M-6
The decrease in other income, net, of $2 million in 1996 was due primarily to a write-off of a deferred return on West Virginia expenditures related to the CAAA and increased interest income in 1995 associated with the 1995 refinancings. The increase in other income, net, of $5 million in 1995 was due primarily to income from demand-side management programs. During 1996, 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.
Dividends on preferred stock decreased $6 million and $5 million in 1996 and 1995, respectively, due primarily to the redemption of preferred stock issues refinanced with the June 1995 issuance of $155.5 million of Quarterly Income Debt Securities (QUIDS). The increase in interest on long-term debt associated with the QUIDS was offset in 1996 by decreased interest on first mortgage bonds due primarily to refinancings to lower rate securities in 1995. Other interest expense reflects changes in the levels of short-term debt maintained by the companies throughout the year, as well as the associated interest rates.
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 restructuring of the electric utility industry and the recently passed Pennsylvania restructuring legislation are discussed in Competition in Core Business on page M-8.
The significant costs of complying with Phase I of the CAAA have essentially been incurred and are being recovered currently from customers in rates. Studies to evaluate cost-effective options to comply with Phase II SO2 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, which have been completed at most of the System's 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, Pennsylvania, and West Virginia for ozone nonattainment (Title I) reasons.
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. A final determination has not been made for the subsidiaries' share of the remediation costs based on the amount of materials sent to the site. 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
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insurance recoveries are such that final resolution of these claims will not have a material 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 internally generated funds and external financings, such as the sale of common and preferred stock, debt instruments, installment loans, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, the companies' cash needs, and capitalization ratio objectives. The availability and cost of external financing depend upon the financial health of the companies seeking those funds. Construction expenditures of the regulated subsidiaries in 1996 were $289 million and, for 1997 and 1998, are estimated at $322 million and $324 million, respectively. The 1997 and 1998 estimated expenditures include $37 million and $59 million, respectively, for construction of environmental control technology. Expenditures in the future to cover the costs of compliance with Phase II of the CAAA may be significant depending on the method chosen to meet the requirements. Based on current forecasts and considering the reactivation and repowering of capacity in cold reserve, peak diversity exchange arrangements, demand- side management and conservation programs, and mandated PURPA capacity, it is anticipated that generating capacity will be sufficient to meet the Company's needs until the year 2000 or beyond. It is the Company's goal to constrain future base capital spending, with the exception of mandated environmental expenditures, to the approximate level of depreciation currently in rates. The regulated subsidiaries also have additional capital requirements for debt maturities (see Note J 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 M-11.
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $386 million in 1996 compared with $281 million in 1995. Current rate levels and reduced levels of capital expenditures permitted the regulated subsidiaries to finance their entire capital expenditure program in 1996 and approximately 88% in 1995 through internal cash generation. It is expected that internal generation of cash over the next several years will continue to finance the majority of utility capital expenditures. See page M-11 for a description of future nonutility investments. Dividends paid on common stock in 1996 increased to $1.69 per share compared with $1.65 in 1995.
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The dividend payout ratio, excluding the restructuring charges and asset write-offs in 1996 and 1995, decreased in 1996. It is expected that the payout ratio will continue to decline in future years.
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 currently 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.
The increase in current liabilities for restructuring activities is related primarily to payout provisions under employee severance packages. Materials and supplies continued to provide a source of cash in 1996, primarily related to lower contracted fuel prices and to maintaining optimum levels of inventories.
Financing
During 1996, the Company issued 1,139,518 shares of common stock under its Dividend Reinvestment and Stock Purchase Plan (DRISP) and Employee Stock Ownership and Savings Plan (ESOSP) for $33.8 million. The Company plans to continue to issue DRISP/ESOSP shares in the future. Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. Short-term debt decreased $44 million to $156 million in 1996. At December 31, 1996, unused lines of credit with banks were $325 million.
During 1997, Monongahela Power Company anticipates issuing $45 million of new debt for general corporate purposes, including its construction program. The other subsidiaries anticipate they will be able to meet their 1997 cash needs through internal cash generation. See page M-11 for information on financing requirements for nonutility investments.
Competition in Core Business
All states in the System's service territory have initiated inquiries or investigations into retail competition and electric utility restructuring, with Pennsylvania enacting legislation in December 1996. Pennsylvania, which accounts for 45% of retail revenues for the Company, became only the fourth state in the country to legislate retail electric competition. The transition to competition in Pennsylvania will be phased in over the periods described below. The legislation includes the following major provisions:
All electric utilities in Pennsylvania must file a restructuring plan by September 30, 1997, to implement direct access to a competitive market for electric generation. The plan must include unbundled rates for
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generation, jurisdictional transmission, distribution and other services, a proposed mechanism for recovery of stranded costs, and a proposed universal service and energy conservation cost recovery mechanism. West Penn is scheduled to make its filing on or about June 1, 1997.
Retail customer choice will be phased in beginning with one-third of retail customers in the year 1999, another one-third in 2000, and the remaining customers in 2001.
Retail rates will be capped for at least 4-1/2 years for transmission and distribution charges and for as long as 9 years for generation charges. A utility may be exempted from the caps only under very specific circumstances as determined by the Pennsylvania PUC.
Pennsylvania utilities are permitted to recover PUC-approved transition or stranded costs over several years; however, the utilities are required to mitigate these costs to the extent practicable.
The Company is currently evaluating the new legislation to formulate its plan to implement direct access to a competitive market. As required in the legislation, in 1997 West Penn and other Pennsylvania electric utilities are required to implement Retail Customer Choice Pilot Programs for up to 5% of the peak load of their customers. This will result in customers with as much as 165 MW of West Penn's retail load being eligible to choose an alternate supplier of generation. The Company's subsidiaries on the other hand anticipate the opportunity to offer capacity and/or energy to customers of other Pennsylvania utilities' pilot programs. The Company cannot predict the ultimate effect of this legislation, but the issues being evaluated include:
Stranded Cost Recovery - Stranded costs can generally be described as mandated costs (such as regulatory assets and obligations under PURPA contracts) and costs of generation that could be recovered in a regulated environment but cannot be recovered in a competitive environment because they are in excess of market. The Pennsylvania legislation permits recovery of both types from customers through a competitive transition charge (CTC), with the provision that utilities have an obligation to mitigate stranded costs to the extent practicable. Over the CTC recovery period, which can be up to nine years, all Pennsylvania utilities are permitted a CTC charge to recover costs in excess of market. Because West Penn has no high-cost nuclear power stations, its CTC charge for costs in excess of market, if any, may be significantly less than the other utilities. West Penn is concerned that it may be placed at a significant competitive disadvantage in the first several phase-in years because other utilities with excess capacity may be willing to sell energy at marginal cost rates, lower than West Penn's full-cost rates, until the excess capacity is used. Under this possibility, West Penn would have stranded costs in the early years.
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West Penn's restructuring plan filing on or about June 1, 1997, will address this issue.
Applicability of SFAS No. 71 - In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," the regulated subsidiaries' financial statements reflect assets and liabilities based on current cost-based ratemaking regulation. Once the Pennsylvania transition to full retail competition is completed, West Penn may not meet the criteria for applying SFAS No. 71 to its generation operations and assets. In that event, any remaining related regulatory assets and liabilities, if any, would be written off, and any related long-lived fixed and intangible assets would need to be evaluated for impairment under the provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." Because of the provisions in the new legislation related to stranded cost recovery, West Penn does not believe any such write-offs or charges should be required.
Rate Caps - As a result of the Pennsylvania legislation, West Penn's rates, including its energy cost rates, have been capped effective January 1, 1997. The legislation did not eliminate the ECR tracking procedure and left to PUC discretion the method of future rate adjustments for energy costs. In 1997, West Penn is reviewing its option to file a Petition with the PUC to roll the energy cost rates into its base rates. Upon receipt of a PUC order to that effect, which is expected if a Petition is filed, West Penn would then assume the risks of increases in the costs of fuel and purchased power and any declines in bulk power transaction sales. However, West Penn would also retain the benefits of decreases in such costs and increases in such sales. West Penn would accomplish this result by discontinuance of deferred fuel accounting.
Initiatives on comprehensive retail competition at the federal government level are also being undertaken. The Company believes that a federal framework of legislation to speed customer choice and provide a uniform framework for rules is necessary because of differences among the states. The Company supports deregulation of all generation, regulation of transmission by the FERC, and regulation of distribution by the states. The Company joined with seven other electric utilities in 1996 to form the Partnership for Customer Choice whose purpose is to seek enactment of federal legislation to bring choice to electric customers no later than the year 2000. The legislation sought would deregulate the generation of electric power, creating a free market for electricity.
The Company is also advocating federal legislation to repeal Section 210 of PURPA and the Public Utility Holding Company Act of 1935 (PUHCA). Both of these laws severely impede the Company's ability to compete on equal terms with both utility and nonutility electric providers who are not subject to their requirements.
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Nonutility Business
AYP Capital, the System's nonutility subsidiary, has continued to broaden its operations to strengthen the long-term competitiveness and profitability of the Company. In 1996, this included the formation of two wholly owned subsidiaries, AYP Energy, Inc. (AYP Energy) and Allegheny Communications Connect, Inc. (ACC).
AYP Energy is an exempt wholesale generator and power marketer. In October 1996, AYP Energy purchased Duquesne Light Company's 50% interest (276 MW) in Unit No. 1 of the Fort Martin Power Station for about $170 million. The remainder of the station is owned by the Company's regulated subsidiaries. AYP Energy incurs depreciation expense and other operating expenses related to Fort Martin. AYP Energy is marketing the output from its share of the station, as well as engaging in other power marketing activities. The operation of a merchant plant and power marketing in the wholesale market is essentially participation in a commodity market, which creates certain risk exposure. AYP Energy expects to use exchange-traded and over-the-counter futures, options, and swap contracts both to hedge its exposure to changes in electric power prices and for trading purposes. The risks to which AYP Energy is exposed include underlying price volatility, credit risk, and variations in cash flows, among others. The Company is in the process of implementing risk management policies and procedures consistent with industry practices and Company goals.
AYP Energy financed its October 1996 acquisition of the 50% interest of Fort Martin Power Station Unit No. 1 with a combination of $25 million of equity contribution from the Company and $160 million of five-year debt financing provided by a syndicate of banks. AYP Energy's obligation under the Credit Agreement is supported by the Company. The debt is priced at a floating rate. AYP Energy entered into a $160 million forward swap to hedge against fluctuations in interest rates during the five-year period. The swap converted the floating rate to an annual fixed rate of 6.78% for the five-year period. Throughout the five-year period, the floating rate may be above or below the fixed rate but is only relevant in the event of termination prior to maturity.
ACC was formed in 1996 as an exempt telecommunications company under PUHCA. ACC's purpose is to develop unregulated opportunities in the deregulated communications market.
AYP Capital has also committed to invest up to an additional $7 million in two limited partnerships, Envirotech Investment Fund I, L.P., formed to invest in emerging electrotechnologies that promote the efficient use of electricity and improve the environment, and the Latin American Energy and Electricity Fund I, L.P., formed to invest in and develop electric energy opportunities in Latin America. AYP Capital will continue to evaluate investment opportunities with potentially significant additional capital investments in the future.
AYP Capital is also developing other energy-related service businesses and offering engineering consulting services and project management for transmission and distribution facilities. The Company believes that the diversification provided by AYP Capital will ultimately enhance earnings growth.
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Monongahela Power Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Net Income
Net income for 1996, 1995, and 1994, and the after tax restructuring charges, asset write-offs, and cumulative effect of accounting changes included in each period are:
The increases in 1996 and 1995 adjusted net income were due primarily to increased revenues from previously reported retail rate increases, and in 1995 also from increased kilowatt-hour (kWh) sales.
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). In 1996, the System, including the Company, essentially completed its restructuring initiatives undertaken in 1995 to consolidate and reengineer operations to meet the competitive challenges of the changing electric utility industry. Although restructuring initiatives have been essentially completed, review of operations will be a continuing process. During 1996, restructuring activities included consolidation of operating divisions, customer services, and other functions. By reorganizing and eliminating certain processes and consolidating common decentralized functions, the System reduced employment by about 1,000 employees since October 1994. These reductions were accomplished through a voluntary separation plan, attrition, and layoffs. Due to efficiencies created by the restructuring process, a reduction in the rate of growth in operating and maintenance costs is expected. The costs associated with the restructuring program will be recovered through future cost savings.
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Restructuring activities are described further in Note B to the Financial Statements.
Competitive forces within the electric utility industry were heightened in 1996 with the issuance of the Federal Energy Regulatory Commission (FERC) Orders 888 and 889. The Company continues to advocate true competition in the electric utility industry and is proactive in its efforts to promote deregulation. See Competition in Core Business on page M-19 for a further discussion of competitive issues in the electric utility industry.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial customers are shown on pages D-3 and D-4. Such kWh sales decreased .4% in 1996 and increased 4.5% in 1995. The changes in revenues from sales to residential, commercial, and industrial customers resulted from the following:
*Changes in revenues from fuel and energy cost adjustment clauses have little effect on net income.
Residential kWh sales increased .3% and 5% in 1996 and 1995, respectively. These increases were due primarily to continued growth in the number of customers, and in 1995 also due to increased customer usage. In 1996, residential usage decreased because of mild weather in comparison to the 1995 extremely hot summer weather and cooler-than- normal winter weather.
The 2% increase in commercial kWh sales in 1996 and the 7% increase in 1995 reflect growth in the number of customers and increased customer usage. Industrial kWh sales decreased 2% in 1996 due primarily to decreased sales to chemical customers and increased 3% in 1995. With the increased potential for retail competition (see Competition in Core Business on page M-19), the efforts of the newly formed Retail Marketing Business Unit have been expanded to increase efforts to retain and acquire customers and to expand into other markets.
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The rate increase in Ohio became effective on November 9, 1995 and 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. There were no increases from rate changes in West Virginia, as the base rate increase effective in 1994 has been fully reflected in both the 1996 and 1995 periods.
The increase in wholesale and other revenues in 1996 resulted primarily from increases in sales of capacity to affiliated companies. 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 FERC). Competition in the wholesale market for electricity was enhanced by the 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. In 1994, a rate case for wholesale customers was completed with the result that such customers agreed to negotiated rate increases and signed five-year contracts to remain as the Company's customers.
KWh deliveries to and revenues from bulk power transactions consist of the following items:
The final rules on open transmission access, issued by the FERC in early 1996, require utilities to offer to others transmission service that is comparable to service they provide to themselves. Increased transmission services in 1996 resulted primarily from increased activity from power marketers who have agreed to take service under the new open access tariffs filed by the Company in accordance with these rules. Deliveries from the sale of Company 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. About 90% of the aggregate benefits from bulk power transactions are passed on to retail customers through fuel cost adjustment clauses and have little effect on net income.
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Operating Expenses
The 1% decrease in fuel expenses in 1996 was primarily due to lower average coal prices. 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. 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 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 consists of the following items:
The decrease in purchase costs 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. None of the Company's purchased power contracts is capitalized since there are no minimum payment requirements absent associated kWh generation. The cost of power purchased, including power from PURPA generation and affiliated transactions, is mostly recovered from customers currently through the regular fuel and energy cost recovery procedures with the result that changes in such costs have little effect on net income.
The decrease in other operation expense in 1996 resulted primarily from decreases in salaries and wages and employee benefits. For 1997 and thereafter, operations expense is expected to reflect the benefits of savings related to the restructuring activities.
M-16
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. 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.
Restructuring charges and asset write-offs resulted primarily from the completion of restructuring initiatives undertaken in 1995. See Note B to the Financial Statements for additional information.
The depreciation expense decrease in 1996 was the net result of a reduction in depreciation rates of $5.3 million, effective in January 1996, offset by additions to electric plant of $3 million. The Company began depreciating the Harrison scrubbers in mid-November 1994, amounting to approximately $8 million annually. Future depreciation expense increases are expected to be less than historical increases because of reduced levels of planned capital expenditures.
The increase in taxes other than income in 1996 was due to higher property taxes and a prior period adjustment in West Virginia Business and Occupation (B&O) Taxes. The decrease in 1995 was primarily due to a decrease in West Virginia 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 decrease in federal and state income taxes in 1996 resulted primarily from a decrease in income before taxes ($4 million), which was primarily related to restructuring charges recorded in 1996, and changes in the provisions for prior years ($2 million). 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). Note C to the Financial Statements provides a further analysis of income tax expenses.
The combined decreases in allowances for funds used during construction in 1996 and 1995 were about $1 million and $2 million, respectively, and reflect decreases in capital expenditures due to substantial completion of the program to comply with Phase I of the CAAA.
The decrease in other income, net, of $2 million in 1996 was due primarily to a write-off of a deferred return on West Virginia expenditures related to the CAAA and increased interest income in 1995 associated with the 1995 refinancings. 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.
M-17
The increase in interest on long-term debt associated with the June 1995 issuance of $40 million of Quarterly Income Debt Securities (QUIDS) was offset in 1996 by decreased interest on first mortgage bonds due primarily to refinancings to lower rate securities in 1995. 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 restructuring of the electric utility industry are discussed in Competition in Core Business on page M-19.
The significant costs of complying with Phase I of the CAAA have essentially been incurred and are being recovered currently from customers in rates. Studies to evaluate cost-effective options to comply with Phase II SO2 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, which have been completed at most of the System's 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, Pennsylvania, and West Virginia for ozone nonattainment (Title I) reasons.
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. A final determination has not been made for the Company's share of the remediation costs based on the amount of materials sent to the site.
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.
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
M-18
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 1996 were $73 million and, for 1997 and 1998, are estimated at $83 million and $91 million, respectively. The 1997 and 1998 estimated expenditures include $13 million and $18 million, respectively, for construction of environmental control technology. Expenditures in the future to cover the costs of compliance with Phase II of the CAAA may be significant depending on the method chosen to meet the requirements. Based on current forecasts and considering an affiliate's reactivation and repowering of capacity in cold reserve, peak diversity exchange arrangements, and a power supply agreement with affiliates, it is anticipated that generating capacity will be sufficient to meet the Company's needs until the year 2000 or beyond. It is the Company's goal to constrain future base capital spending, with the exception of mandated environmental expenditures, to the approximate level of depreciation currently in rates. The Company also has additional capital requirements for debt maturities (see Note J to the Financial Statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $92 million in 1996 compared with $93 million in 1995. Current rate levels and reduced levels of capital expenditures permitted the Company to finance its entire capital expenditure program in 1996 and 1995 through internal cash generation. It is expected that internal generation of cash over the next several years will continue to finance the majority of capital expenditures.
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 currently 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.
The increase in current liabilities for restructuring activities is related primarily to payout provisions under employee severance packages. Materials and supplies continued to provide a source of cash in 1996, primarily related to lower contracted fuel prices and to maintaining optimum levels of inventories.
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Financing
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, increased $1 million to $31 million in 1996. At December 31, 1996, the Company had Securities and Exchange Commission authorization to issue up to $100 million of short-term debt. The Company and its regulated 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. During 1997, the Company anticipates issuing $45 million of new debt for general corporate purposes, including its construction program.
COMPETITION IN CORE BUSINESS
All states in the System's service territory have initiated inquiries or investigations into retail competition and electric utility restructuring, with Pennsylvania enacting legislation in December 1996.
In December 1996, the Public Service Commission of West Virginia issued an order initiating a general investigation for the purpose of seeking comments and information regarding the restructuring of the regulated electric utility industry, establishment of competition in power supply markets, and establishment of retail wheeling and intra-state open access of jurisdictional power distribution systems. Public hearings are scheduled to begin on April 1, 1997.
The Public Utilities Commission of Ohio (Ohio PUC) has initiated informal roundtable discussions on issues concerning competition in the electric utility industry and promoting increased competitive options for Ohio businesses. The meetings have resulted in sets of guidelines on interruptible rates which have been adopted by the Ohio PUC and guidelines on conjunctive service which are now pending before the Ohio PUC.
Initiatives on comprehensive retail competition at the federal government level are also being undertaken. The Company believes that a federal framework of legislation to speed customer choice and provide a uniform framework for rules is necessary because of differences among the states. The System, including the Company, supports deregulation of all generation, regulation of transmission by the FERC, and regulation of distribution by the states. The System, including the Company, joined with seven other electric utilities in 1996 to form the Partnership for Customer Choice whose purpose is to seek enactment of federal legislation to bring choice to electric customers no later than the year 2000. The legislation sought would deregulate the generation of electric power, creating a free market for electricity.
The System is also advocating federal legislation to repeal Section 210 of PURPA and the Public Utility Holding Company Act of 1935. Both of these laws severely impede the Company's ability to compete on equal terms with both utility and nonutility electric providers who are not subject to their requirements.
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The Potomac Edison Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Net Income
Net income for 1996, 1995, and 1994, and the after tax restructuring charges, asset write-offs, and cumulative effect of accounting change included in each period are:
The increase in 1996 adjusted net income was due primarily to increases in kilowatt-hour (kWh) sales.
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). In 1996, the System, including the Company, essentially completed its restructuring initiatives undertaken in 1995 to consolidate and reengineer operations to meet the competitive challenges of the changing electric utility industry. Although restructuring initiatives have been essentially completed, review of operations will be a continuing process. During 1996, restructuring activities included consolidation of operating divisions, customer services, and other functions. By reorganizing and eliminating certain processes and consolidating common decentralized functions, the System reduced employment by about 1,000 employees since October 1994. These reductions were accomplished through a voluntary separation plan, attrition, and layoffs. Due to efficiencies created by the restructuring process, a reduction in the rate of growth in operating and maintenance costs is expected. The costs associated with the restructuring program will be recovered through future cost savings. Restructuring activities are described further in Note B to the Financial Statements.
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Competitive forces within the electric utility industry were heightened in 1996 with the issuance of the Federal Energy Regulatory Commission (FERC) Orders 888 and 889. The Company continues to advocate true competition in the electric utility industry and is proactive in its efforts to promote deregulation. See Competition in Core Business on page M-27 for a further discussion of competitive issues in the electric utility industry.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial customers are shown on pages D-5 and D-6. Such kWh sales increased 3.1% and 3.3% in 1996 and 1995, respectively. The changes in revenues from sales to residential, commercial, and industrial customers resulted from the following:
*Changes in revenues from fuel and energy cost adjustment clauses have little effect on net income.
The increase in kWh sales in 1996 was attributable to increases in each of the residential, commercial, and industrial customer classes. Residential kWh sales increased 5% in 1996 and 4% in 1995. These increases, which are more weather sensitive than commercial and industrial sales, were due primarily to increased customer usage and continued growth in the number of customers. The Company measures the effect of weather conditions on its utility sales by using degree days, which reflect the differences between the average daily actual temperature and the baseline temperature of 65 degrees. In 1996, heating degree days in the relatively colder January-through-April period were about 12% greater than the corresponding 1995 period. This increase was somewhat offset by milder weather during the remainder of the year. In 1995, increased sales resulted from extremely hot summer weather and cooler-than-normal winter weather.
The 3% increase in commercial kWh sales in 1996 and the 4% increase in 1995 reflect growth in the number of customers and increased customer usage. Industrial kWh sales increased 1% and 3% in 1996 and 1995, respectively. Excluding the decrease in the fuel and energy cost component of industrial sales, revenues from sales to industrial
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customers also increased over 1% in 1996. The increase in kWh sales reflects a trend of economic growth in the service territory and the efforts of the newly formed Retail Marketing Business Unit. With the increased potential for retail competition (see Competition in Core Business on page M-27), this function has been expanded to increase efforts to retain and acquire customers and to expand into other markets.
Base rate increases effective in 1994 have been fully reflected in both the 1996 and 1995 periods.
The increase in wholesale and other revenues in 1996 resulted primarily from load additions to the wholesale customers' systems (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 FERC). Competition in the wholesale market for electricity was enhanced by the 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. An agreement in principle was reached with one customer in 1996, representing $3 million in annual wholesale revenues, for a new five-year contract effective in 1997. With this new contract, all of the wholesale customers have signed contracts to remain as the Company's customers for two to five years. The increase in wholesale and other revenues in 1995 resulted primarily from provisions recorded for rate refunds in 1994 and increased revenues from wholesale customers.
KWh deliveries to and revenues from bulk power transactions consist of the following items:
The final rules on open transmission access, issued by the FERC in early 1996, require utilities to offer to others transmission service that is comparable to service they provide to themselves. Increased transmission services in 1996 resulted primarily from increased activity from power marketers who have agreed to take service under the new open access tariffs filed by the Company in accordance with these rules. Deliveries from the sale of Company 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. About 95% of the aggregate benefits from bulk power transactions are passed on
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to retail customers through fuel cost adjustment clauses and have little effect on net income.
Operating Expenses
The 2% increase in fuel expenses in 1996 was due to a 3% increase in kWh generated, offset in part by lower average coal prices. 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. 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 consists of the following items:
A Public Utility Regulatory Policies Act of 1978 (PURPA) power station project in the Company's Maryland jurisdiction is scheduled to commence generation in 1999. Because of the high cost of this energy, the Company has attempted to negotiate a buyout or restructure the existing contract to reduce the cost to customers. To date, the negotiations have been unsuccessful. This project will significantly increase the costs of power purchases.
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 with the result that changes in such costs have little effect on net income.
Maintenance expenses represent costs incurred to maintain the power stations, the transmission and distribution (T&D) system, and general
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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. 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.
Restructuring charges and asset write-offs resulted primarily from the completion of restructuring initiatives undertaken in 1995. See Note B to the Financial Statements for additional information.
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 are expected to be less than historical increases because of reduced levels of planned capital expenditures.
The decrease in taxes other than income in 1996 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 net decrease of $3 million in federal and state income taxes in 1996 resulted primarily from changes in the provisions for prior years ($1 million), a decrease in income before taxes ($1 million) which was primarily related to restructuring charges recorded in 1996, and plant removal tax deductions for which deferred taxes were not provided ($1 million). The net increase of $4 million in federal and state income taxes in 1995 resulted primarily from an increase in reversals of prior year depreciation benefits for which deferred taxes were not then provided. Note C to the Financial Statements provides a further analysis of income tax expenses.
The combined increase in allowances for funds used during construction (AFUDC) in 1996 of $.7 million is the result of a correction to reduce previously accrued AFUDC by $1.4 million in 1995. The combined decrease in AFUDC in 1995 reflects a decrease in capital expenditures due to substantial completion of the program to comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA).
The increase in other income, net, of $2 million in 1995 was due primarily to income from demand-side management programs. During 1996, 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 increase in interest on long-term debt associated with the June 1995 issuance of $45.5 million of Quarterly Income Debt Securities (QUIDS) was offset in 1996 by decreased interest on first mortgage bonds due
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primarily to refinancings to lower rate securities in 1995. 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 restructuring of the electric utility industry are discussed in Competition in Core Business on page M-27.
The significant costs of complying with Phase I of the CAAA have essentially been incurred and are being recovered currently from customers in rates. Studies to evaluate cost-effective options to comply with Phase II SO2 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, which have been completed at most of the System's 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, Pennsylvania, and West Virginia for ozone nonattainment (Title I) reasons.
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. A final determination has not been made for the Company's share of the remediation costs based on the amount of materials sent to the site. 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.
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
M-26
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 1996 were $86 million and, for 1997 and 1998, are estimated at $98 million and $109 million, respectively. The 1997 and 1998 estimated expenditures include $7 million and $11 million, respectively, for construction of environmental control technology. Expenditures in the future to cover the costs of compliance with Phase II of the CAAA may be significant depending on the method chosen to meet the requirements. Based on current forecasts and considering an affiliate's reactivation and repowering of capacity in cold reserve, peak diversity exchange arrangements, a power supply agreement with affiliates, and mandated PURPA capacity, it is anticipated that generating capacity will be sufficient to meet the Company's needs until the year 2000 or beyond. It is the Company's goal to constrain future base capital spending, with the exception of mandated environmental expenditures, to the approximate level of depreciation currently in rates. 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 $116 million in 1996 compared with $85 million in 1995. Current rate levels and reduced levels of capital expenditures permitted the Company to finance its entire capital expenditure program in 1996 and approximately 92% in 1995 through internal cash generation. It is expected that internal generation of cash over the next several years will continue to finance the majority of capital expenditures.
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 currently 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.
The increase in current liabilities for restructuring activities is related primarily to payout provisions under employee severance packages. Materials and supplies continued to provide a source of cash in 1996, primarily related to lower contracted fuel prices and to maintaining optimum levels of inventories.
Financings
Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. Short-term debt decreased $14 million to $7 million in 1996. At December 31, 1996, the Company had Securities and Exchange Commission authorization to issue up to $115 million of short-term debt. The Company and its regulated
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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. The Company anticipates that it will be able to meet its 1997 cash needs through internal cash generation.
COMPETITION IN CORE BUSINESS
All states in the Company's service territory have initiated inquiries or investigations into retail competition and electric utility restructuring, with Pennsylvania enacting legislation in December 1996.
In December 1996, the Public Service Commission of West Virginia issued an order initiating a general investigation for the purpose of seeking comments and information regarding the restructuring of the regulated electric utility industry, establishment of competition in power supply markets, and establishment of retail wheeling and intra-state open access of jurisdictional power systems. Public hearings are scheduled to begin on April 1, 1997.
In September 1995, the Virginia State Corporation Commission (SCC) began an investigation to review its policy regarding restructuring of and competition in the electric industry. In November 1996, the SCC ordered further investigation into restructuring of the industry, requiring the three largest electric utilities in Virginia, including the Company, to file competition information by March 31, 1997.
On October 9, 1996, the Maryland Public Service Commission issued an order directing its Staff to evaluate the current state of the electric industry and to submit a report to the Commission by May 31, 1997. The four major Maryland electric utilities, including the Company, are to present unbundled cost studies and model service tariffs, among other things, by August 1, 1997.
Initiatives on comprehensive retail competition at the federal government level are also being undertaken. The Company believes that a federal framework of legislation to speed customer choice and provide a uniform framework for rules is necessary because of differences among the states. The System, including the Company, supports deregulation of all generation, regulation of transmission by the FERC, and regulation of distribution by the states. The System, including the Company, joined with seven other electric utilities in 1996 to form the Partnership for Customer Choice whose purpose is to seek enactment of federal legislation to bring choice to electric customers no later than the year 2000. The legislation sought would deregulate the generation of electric power, creating a free market for electricity.
The System is also advocating federal legislation to repeal Section 210 of PURPA and the Public Utility Holding Company Act of 1935. Both of these laws severely impede the Company's ability to compete on equal terms with both utility and nonutility electric providers who are not subject to their requirements.
M-28
West Penn Power Company and Subsidiaries
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Consolidated Net Income
Consolidated net income for 1996, 1995, and 1994, and the after tax restructuring charges, asset write-offs, and cumulative effect of accounting change included in each period are:
The decrease in 1996 adjusted consolidated net income was due primarily to higher depreciation expense, increased charge-offs for uncollectible accounts, and the write-off of deferred Clean Air Amendments of 1990 (CAAA) compliance costs. The increase in 1995 adjusted consolidated net income resulted primarily from additional retail revenues due to increased kilowatt-hour (kWh) sales and retail rate increases.
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). In 1996, the System, including the Company, essentially completed its restructuring initiatives undertaken in 1995 to consolidate and reengineer operations to meet the competitive challenges of the changing electric utility industry. Although restructuring initiatives have been essentially completed, review of operations will be a continuing process. During 1996, restructuring activities included consolidation of operating divisions, customer services, and other functions. By reorganizing and eliminating certain processes and consolidating common decentralized functions, the System reduced employment by about 1,000 employees since October 1994. These reductions were accomplished through a voluntary separation plan,
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attrition, and layoffs. Due to efficiencies created by the restructuring process, a reduction in the rate of growth in operating and maintenance costs is expected. The costs associated with the restructuring program will be recovered through future cost savings. Restructuring activities are described further in Note B to the Consolidated Financial Statements.
Competitive forces within the electric utility industry were heightened in 1996 with the enactment of the Pennsylvania Electric Generation Customer Choice and Competition Act and issuance of the Federal Energy Regulatory Commission (FERC) Orders 888 and 889. The Company continues to advocate true competition in the electric utility industry and is proactive in its efforts to promote deregulation. See Competition in Core Business on page M-35 for a further discussion of competitive issues in the electric utility industry.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial customers are shown on pages D-7 and D-8. Such kWh sales increased 2% and 4% in 1996 and 1995, respectively. The changes in revenues from sales to residential, commercial, and industrial customers resulted from the following:
*Changes in revenues from fuel and energy cost adjustment clauses have little effect on consolidated net income. See "Rate Caps" under Competition in Core Business on page M-35 for information regarding a potential change in the fuel and energy cost adjustment clause (Energy Cost Rate or ECR) in Pennsylvania.
The increase in kWh sales in 1996 was attributable to increases in each of the residential, commercial, and industrial customer classes. Residential kWh sales increased 2% in 1996 and 1% in 1995. These increases, which are more weather sensitive than commercial and industrial sales, were due primarily to increased customer usage and continued growth in the number of customers. The Company measures the effect of weather conditions on its utility sales by using degree days, which reflect the differences between the average daily actual temperature and the baseline temperature of 65 degrees. In 1996, heating degree days in the relatively colder January- through-April period were about 8% greater than the corresponding 1995 period. This increase was somewhat offset by milder weather during the remainder of
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the year. In 1995, increased sales resulted from extremely hot summer weather and cooler-than-normal winter weather.
The 1% increase in commercial kWh sales in 1996 and the 4% increase in 1995 reflect growth in the number of customers, and, in 1995, also reflects increased customer usage. Industrial kWh sales increased 1% and 6% in 1996 and 1995, respectively. Excluding the decrease in the fuel and energy cost component of industrial sales, revenues from sales to industrial customers also increased over 1% in 1996. The increase in kWh sales reflects a trend of economic growth in the service territory and the efforts of the newly formed Retail Marketing Business Unit. With the increased potential for retail competition and in light of the Pennsylvania legislation (see Competition in Core Business on page M-35), this function has been expanded to increase efforts to retain and acquire customers and to expand into other markets.
There were no increases resulting from rate changes in 1996, as the base rate increases effective in 1994 have been fully reflected in both the 1996 and 1995 periods. As a result of the Pennsylvania competition legislation, the Company's rates have been capped effective January 1, 1997. This is more fully described on page M-35.
The increase in wholesale and other revenues in 1995 resulted primarily from an increase in sales of capacity, energy, and spinning reserve to affiliated companies. About $19 million of wholesale and other revenues in 1996 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 FERC). Competition in the wholesale market for electricity was enhanced by the 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. 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 the Company's customers. Also, effective April 1997, a new wholesale customer (formerly a retail customer) signed a five-year contract to become a Company customer.
KWh deliveries to and revenues from bulk power transactions consist of the following items:
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The final rules on open transmission access, issued by the FERC in early 1996, require utilities to offer to others transmission service that is comparable to service they provide to themselves. Increased transmission services in 1996 resulted primarily from increased activity from power marketers who have agreed to take service under the new open access tariffs filed by the Company in accordance with these rules. Deliveries from the sale of Company 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. Most of the aggregate benefits from bulk power transactions are passed on to retail customers through fuel cost adjustment clauses and have little effect on consolidated net income. See page M-37 for information regarding the potential change in the ECR for Pennsylvania.
Operating Expenses
The 1% increase in fuel expenses in 1996 was due to a 2% increase in kWh generated, offset in part by lower average coal prices. 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.
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. See page M-37 for information regarding the potential change in the ECR for Pennsylvania.
"Purchased power and exchanges, net" represents power purchases from and exchanges with nonaffiliated utilities 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 consists of the following items:
In 1996, the Company and the developers of a proposed Shannopin PURPA project reached an agreement to terminate the project at a buyout price of $31 million. The Pennsylvania Public Utility Commission (PUC) has
M-32
authorized full recovery of the buyout price, of which $24 million was recovered by reducing the Company's over-recovered fuel balance. The remaining $7 million was to be recovered in 1997 and 1998, but, pursuant to the recent Pennsylvania rate caps enacted by the new Pennsylvania Electric Generation Customer Choice and Competition Act, will be recovered through other means. The buyout will save the Company's customers approximately $665 million over the next 30 years by eliminating the need to buy the uneconomic power.
None of the Company's purchased power contracts is capitalized since there are no minimum payment requirements absent associated kWh generation. The cost of power purchased, including power from PURPA generation and affiliated transactions, is mostly recovered from customers currently through the regular fuel and energy cost recovery procedures with the result that changes in such costs have little effect on consolidated net income. See page M-37 for information regarding the potential change in the ECR in Pennsylvania.
The increase in other operation expense in 1996 resulted primarily from increased allowances for uncollectible accounts ($3 million) and the write-off of deferred CAAA compliance costs ($2 million). For 1997 and thereafter, operations expense is expected to reflect the benefits of savings related to the restructuring activities. Allowances for uncollectible accounts increased 60% in 1996 due to an increase in aged accounts receivable caused primarily by regulations in Pennsylvania which severely restrict curtailment of service to non-paying customers.
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. 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.
Restructuring charges and asset write-offs resulted primarily from the completion of restructuring initiatives undertaken in 1995 and the write-off of previously accumulated costs related to a proposed transmission line. See Note B to the Consolidated Financial Statements for additional information.
Depreciation expense increases resulted primarily from additions to electric plant. 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 planned capital expenditures.
The increase in taxes other than income in 1996 was due to higher property taxes and, in 1995, reflects increases in gross receipts taxes
M-33
resulting from higher revenues from retail customers. The net decrease in federal and state income taxes in 1996 resulted primarily from a decrease in income before taxes ($18 million), which was primarily related to restructuring charges recorded in 1996. The net increase of $15 million in federal and state income taxes in 1995 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 1996 and 1995 were $2 million and $6 million, respectively, and reflect decreases in capital expenditures due to substantial completion of the program to comply with Phase I of the CAAA.
The increase in interest on long-term debt associated with the June 1995 issuance of $70 million of Quarterly Income Debt Securities (QUIDS) was offset in 1996 by decreased interest on first mortgage bonds due primarily to refinancings to lower rate securities in 1995 and the redemption of $27 million of first mortgage bonds in 1995. 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. The increase in other interest expense in 1996 resulted primarily from interest on overcollections on the fuel cost portion of customer billings.
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 restructuring of the electric utility industry and the recently passed Pennsylvania restructuring legislation are discussed in Competition in Core Business on page M-35.
The significant costs of complying with Phase I of the CAAA have essentially been incurred and are being recovered currently from customers in rates. Studies to evaluate cost-effective options to comply with Phase II SO2 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, which have been completed at most of the System's 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, Pennsylvania, and West Virginia for ozone nonattainment (Title I) reasons.
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. A final determination has not been made for the Company's
M-34
share of the remediation costs based on the amount of materials sent to the site. 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.
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 1996 were $131 million and, for 1997 and 1998, are estimated at $140 million and $123 million, respectively. The 1997 and 1998 estimated expenditures include $17 million and $29 million, respectively, for construction of environmental control technology. Expenditures in the future to cover the costs of compliance with Phase II of the CAAA may be significant depending on the method chosen to meet the requirements. Based on current forecasts and considering the reactivation and repowering of capacity in cold reserve, peak diversity exchange arrangements, and a power supply agreement with affiliates, it is anticipated that generating capacity will be sufficient to meet the Company's needs until the year 2000 or beyond. It is the Company's goal to constrain future base capital spending, with the exception of mandated environmental expenditures, to the approximate level of depreciation currently in rates. The Company also has additional capital requirements for debt maturities (see Note J to the Consolidated Financial Statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $173 million in 1996 compared with $110 million in 1995. Current rate levels and reduced levels of capital expenditures permitted the Company to finance its entire capital expenditure program in 1996 and approximately 74% in 1995 through internal cash generation. It is expected that internal generation of cash over the next several years will continue to finance the majority of capital expenditures.
M-35
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 currently 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.
The increase in current liabilities for restructuring activities is related primarily to payout provisions under employee severance packages. Materials and supplies continued to provide a source of cash in 1996, primarily related to lower contracted fuel prices and to maintaining optimum levels of inventories.
Financing
Short-term debt is used to meet temporary cash needs until the timing is considered appropriate to issue long-term securities. Short-term debt decreased $37 million to $33 million in 1996. At December 31, 1996, the Company had Securities and Exchange Commission authorization to issue up to $170 million of short-term debt. The Company and its regulated 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. The Company anticipates that it will be able to meet its 1997 cash needs through internal cash generation.
COMPETITION IN CORE BUSINESS
In December 1996, Pennsylvania became only the fourth state in the country to enact legislation on retail competition and electric utility restructuring. The transition to competition in Pennsylvania will be phased in over the periods described below. The legislation includes the following major provisions:
All electric utilities in Pennsylvania must file a restructuring plan by September 30, 1997, to implement direct access to a competitive market for electric generation. The plan must include unbundled rates for generation, jurisdictional transmission, distribution and other services, a proposed mechanism for recovery of stranded costs, and a proposed universal service and energy conservation cost recovery mechanism. The Company is scheduled to make its filing on or about June 1, 1997.
Retail customer choice will be phased in beginning with one- third of retail customers in the year 1999, another one- third in 2000, and the remaining customers in 2001.
Retail rates will be capped for at least 4-1/2 years for transmission and distribution charges and for as long as 9 years for generation charges. A utility may be exempted
M-36
from the caps only under very specific circumstances as determined by the PUC.
Pennsylvania utilities are permitted to recover PUC-approved transition or stranded costs over several years; however, the utilities are required to mitigate these costs to the extent practicable.
The Company is currently evaluating the new legislation to formulate its plan to implement direct access to a competitive market. As required in the legislation, in 1997 the Company and other Pennsylvania electric utilities are required to implement Retail Customer Choice Pilot Programs for up to 5% of the peak load of their customers. This will result in customers with as much as 165 MW of the Company's retail load being eligible to choose an alternate supplier of generation. The Company on the other hand anticipates the opportunity to offer capacity and/or energy to customers of other Pennsylvania utilities' pilot programs. The Company cannot predict the ultimate effect of this legislation, but the issues being evaluated include:
Stranded Cost Recovery - Stranded costs can generally be described as mandated costs (such as regulatory assets and obligations under PURPA contracts) and fixed costs of generating facilities in excess of market value. The Pennsylvania legislation permits recovery of both types from customers through a competitive transition charge (CTC), with the provision that utilities have an obligation to mitigate stranded costs to the extent practicable. Over the nine-year CTC recovery period, all Pennsylvania utilities are permitted a CTC charge to recover fixed costs in excess of market. Because the Company has no high cost nuclear power stations, its CTC charge for fixed costs in excess of market, if any, will be significantly less than the other utilities. The Company is concerned that it may be placed at a significant competitive disadvantage in the first several phase-in years because other utilities with excess capacity may be willing to sell energy at marginal cost rates, lower than the Company's full-cost rates, until the excess capacity is used. Under this possibility, the Company would have stranded fixed costs in the early years. The Company's restructuring plan filing on or about June 1, 1997, will address this issue.
Applicability of SFAS No. 71 - In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," the Company's financial statements reflect assets and liabilities based on current cost-based ratemaking regulation. Once the Pennsylvania transition to full retail competition is completed, the Company may not meet the criteria for applying SFAS No. 71 to its generation operations and assets. In that event, any remaining related regulatory assets and liabilities, if any, would be written off, and any related long-lived fixed and intangible assets would need to be evaluated for impairment under the provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." Because of the provisions in the new legislation related to stranded cost
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recovery, the Company does not believe any such write-offs or charges should be required.
Rate Caps - As a result of the Pennsylvania legislation, the Company's rates, including its energy cost rates, have been capped effective January 1, 1997. The legislation did not eliminate the ECR tracking procedure and left to PUC discretion the method of future rate adjustments for energy costs. In 1997, the Company is reviewing its option to file a Petition with the PUC to roll the energy cost rates into its base rates. Upon receipt of a PUC order to that effect, which is expected if a Petition is filed, the Company would then assume the risks of increases in the costs of fuel and purchased power and any declines in bulk power transaction sales. However, the Company would also retain the benefits of decreases in such costs and increases in such sales. The Company would accomplish this result by discontinuance of deferred fuel accounting.
Initiatives on comprehensive retail competition at the federal government level are also being undertaken. The Company believes that a federal framework of legislation to speed customer choice and provide a uniform framework for rules is necessary because of differences among the states. The System, including the Company, supports deregulation of all generation, regulation of transmission by the FERC, and regulation of distribution by the states. The System, including the Company, joined with seven other electric utilities in 1996 to form the Partnership for Customer Choice whose purpose is to seek enactment of federal legislation to bring choice to electrical customers no later than the year 2000. The legislation sought would deregulate the generation of electric power, creating a free market for electricity.
The System is also advocating federal legislation to repeal Section 210 of PURPA and the Public Utility Holding Company Act of 1935. Both of these laws severely impede the Company's ability to compete on equal terms with both utility and nonutility electric providers who are not subject to their requirements.
M-38
Allegheny Generating Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Review 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 1996 and 1995 decreased due to a reduction in net investment and reduced operating expenses and, additionally for 1996, due to the decrease in the Company's return on equity (ROE) from 11.2% to 11% described below.
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 decrease in interest on long-term debt in 1996 was primarily the result of a decrease in the average amount of 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). 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, depreciation, taxes, and a return on its investment.
The Company's rates are set by a formula filed with and previously accepted by the FERC. The only component which changes is the ROE. Through February 29, 1992, the Company's ROE was adjusted annually pursuant to a settlement agreement approved by the Federal Energy Regulatory Commission (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
M-39
Advocate, filed to reduce the ROE. A settlement agreement was filed with the FERC on January 12, 1995, which reduced the Company's ROE from 11.53% to 11.13% for the period from March 1, 1992 through December 31, 1994, and increased 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 revenues collected between March 1, 1992 and March 23, 1995 in excess of these levels. On December 21, 1995, the Company submitted a negotiated settlement to the FERC to address the Company's ROE effective after 1995. Interested parties representing less than 2% of the Company's eventual revenues filed exceptions. 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. On February 20, 1996, the FERC instituted an investigation of the proposed rate. Subsequently, the parties who filed exceptions removed their exceptions and accepted the settlement agreement providing for a 1996 return on equity of 11% and an ROE adjustment mechanism for future years. Pursuant to a settlement agreement filed April 4, 1996, with the FERC, the Company's ROE was set at 11% for 1996 and will continue at that rate until the time any affected party seeks renegotiation of the ROE. Notice of such intent to seek a revision in ROE must be filed during a notice period each year between November 1 and November 15. No requests for change were filed during the 1996 notice period. Therefore, the Company's ROE will remain at 11% for 1997.
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.
In July 1996, the Company filed a request with the Securities and Exchange Commission (SEC) for authority to pay common dividends from time to time through December 31, 2001, out of capital to the extent permitted under applicable corporation law and any applicable financing agreements which restrict distributions to shareholders. Due to the nature of being a single asset company with declining capital needs, the Company systematically reduces capitalization each year as its asset depreciates. This has resulted in the payment of dividends in excess of current earnings and the reduction of retained earnings. The Company's goal is to retire debt and pay dividends in amounts necessary to maintain a 45% common equity position. The payment of dividends out of capital surplus will not be detrimental to the financial integrity or working capital of either the Company or its parents, nor will it adversely affect the protections due debt security holders. On September 19, 1996, the SEC approved the Company's request to pay common dividends out of capital.
An internal money pool accommodates intercompany short-term borrowing needs to the extent that certain of the Company's regulated affiliates have funds available.
- 44 -
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements
All other schedules are omitted because they are not applicable or the required information is shown in the Financial Statements or Notes thereto.
Allegheny Power System
Report of Independent Accountants To the Board of Directors and the Shareholders of Allegheny Power System, Inc.
In our opinion, the accompanying consolidated balance sheet, consolidated statements of capitalization and of common equity and the related consolidated statements of income and of cash flows present fairly, in all material respects, the financial position of Allegheny Power System, Inc. and its subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, 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 New York, New York February 5, 1997
Consolidated Statement of Income Year ended December 31
See accompanying notes to consolidated financial statements.
Consolidated Statement of Cash Flows Year ended December 31
See accompanying notes to consolidated financial statements.
See accompanying notes to consolidated financial statements.
See accompanying notes to consolidated financial statements.
Consolidated Statement of Common Equity Year ended December 31
See accompanying notes to consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (These notes are an integral part of the consolidated financial statements.) Note A: Summary of Significant Accounting Policies
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. These subsidiaries jointly own Allegheny Generating Company (AGC), which owns and sells to its parents 840 megawatts (MW) of pumped-storage generating capacity. The principal markets for the System's electric sales are in the states of Pennsylvania, West Virginia, Maryland, Virginia, and Ohio. In 1996, 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. (AYP Capital), formed in 1994, which is involved primarily in energy-related services, development of wholesale nonutility 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 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. Revenues from nonregulated activities are recorded in the period earned.
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 Utility 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 utility 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 postretirement benefits, taxes, and other fringe benefits related to employees engaged in construction.
The cost of depreciable utility 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 utility property, plant, and equipment with offsetting credits to other income and interest charges. Rates used by the subsidiaries for computing AFUDC in 1996, 1995, and 1994 averaged 8.41%, 8.73%, and 9.00%, 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 utility 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 1996 and 1995 and 3.3% in 1994. The cost of maintenance and of certain replacements of property, plant, and equipment is charged principally to operating expenses.
Nonutility Property Nonutility property is stated at cost and is depreciated by the straight-line method over its estimated useful life.
Investments The investment in subsidiaries consolidated represents the excess of acquisition cost over book equity (goodwill) prior to 1966. Goodwill is not being amortized because, in management's opinion, there has been no reduction in its value.
Benefit plans' investments primarily represent the estimated cash surrender values of purchased life insurance on qualifying management employees under executive life insurance, and supplemental executive retirement plans. Payment of future premiums will fully fund these benefits.
Temporary Cash Investments 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.
Regulatory Deferrals In accordance with the Financial Accounting Standards Board's Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," the Company's consolidated financial statements reflect assets and liabilities based on current cost-based ratemaking regulation.
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. For the regulated subsidiaries, 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 the maximum amount that can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee
Beneficiary Association trust funds. Medical benefits are self-insured; the life insurance plan is paid through insurance premiums.
Bulk Power Transactions Reclassification Effective in 1996, the regulated subsidiaries changed their method of reporting certain bulk power transmission transactions with nonaffiliated utilities and reclassified prior years' bulk power and other revenues and operation expenses to achieve a consistent presentation. In prior years, some use of the subsidiaries' transmission system was recorded as purchased power from selling utilities and as sales of power to buying utilities. The benefit to the subsidiaries was the difference between the two. Because of new FERC requirements, the subsidiaries predominantly do not "buy" and "sell" such energy, but rather a transmission fee is charged.
Under the new reporting method, all such transactions are recorded on a net revenue basis. The effect of the reclassifications was to reduce amounts previously reported for bulk power transactions revenues and operation expenses by $333 million and $267 million for 1995 and 1994, respectively, with no change in operating income or consolidated net income.
Accounting Change Effective January 1, 1994, the regulated subsidiaries changed their revenue recognition method to include the accrual of estimated unbilled revenues for electric services. 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 is not material.
Note B: Restructuring Charges and Asset Write-Offs In 1996, the Company and its subsidiaries essentially completed their restructuring initiatives undertaken in 1995, simplifying the management structure and streamlining operations. During 1996, restructuring activities included consolidating operating divisions, customer services, and other functions. By reorganizing and eliminating certain processes and consolidating common decentralized functions, the Company and its subsidiaries have reduced employment by about 1,000 employees since October 1994. These reductions were accomplished through a voluntary separation plan, attrition, and layoffs.
In 1996 and 1995, the subsidiaries recorded restructuring charges of $93.1 million ($56.2 million after tax) and $16.0 million ($9.6 million after tax) in operating expenses, including all restructuring charges associated with the reorganization, which is essentially complete. These charges reflect liabilities and payments for severance, employee termination costs, and other restructuring costs. The restructuring liability consists of:
In 1996 and 1994, the regulated subsidiaries wrote off $10.8 million ($6.3 million after tax) and $9.2 million ($5.3 million after tax), respectively, of previously accumulated costs related to a proposed transmission line and a potential future power plant site. In the industry's more competitive environment, it was no longer reasonable to assume future recovery of these costs in rates.
In connection with changes in inventory management objectives, the regulated subsidiaries in 1995 also recorded $7.4 million ($4.5 million after tax) for the write-off of obsolete and slow-moving materials.
Note C: Income Taxes
Details of federal and state income tax provisions are:
Note D: Dividend Restriction
Supplemental indentures relating to certain outstanding bonds of Monongahela Power Company and West Penn Power Company contain dividend restrictions under the most restrictive of which $121,015,000 of consolidated retained earnings at December 31, 1996, 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:
In determining the actuarial present value of the projected benefit obligation at September 30, 1996, 1995, and 1994, the discount rates used were 7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1996, 1995, and 1994.
The pension cost prepaid at December 31, 1996, includes the net result of a curtailment gain of $11.5 million and an expense for special termination benefits of $4.5 million associated with the workforce reduction.
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, a portion of which (about 25% to 30%) was charged to plant construction, included the following components:
In determining the accumulated postretirement benefit obligation (APBO) at September 30, 1996, 1995, and 1994, the discount rates used were 7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The
expected long-term rate of return on assets was 8.25% in each of the years 1996, 1995, and 1994. For measurement purposes, a health care trend rate of 7% for 1997, declining to 6.5% in 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, 1996, by $13.5 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1996 by $1.3 million.
The postretirement benefit liability at December 31, 1996, includes a curtailment loss of $14.6 million and an expense for special termination benefits of $6.2 million associated with the workforce reduction.
Note G: Nonutility Subsidiary Information AYP Capital has two wholly owned subsidiaries which were formed in 1996, AYP Energy, Inc. (AYP Energy) and Allegheny Communications Connect, Inc. (ACC). AYP Energy is an exempt wholesale generator and power marketer. ACC is an exempt telecommunications company under the Public Utility Holding Company Act of 1935 (PUHCA). ACC's purpose is to develop nonutility opportunities in the deregulated communications market.
AYP Capital's net loss was $2.9 million in 1996 and $.6 million in 1995. The following is a condensed consolidated balance sheet for AYP Capital. The allocation of net assets, including intangibles, related to the purchase of 276 MW at the Fort Martin Power Station will be completed in 1997. This financial information does not reflect the elimination of intercompany balances or transactions which are eliminated in the Company's consolidated financial statements.
Note H: Regulatory Assets and Liabilities
The Company's utility operations are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets, net of regulatory liabilities, reflected in the Consolidated Balance Sheet at December 31 relate to:
Note I: 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 was estimated based on cash surrender value. The Company has no financial instruments held or issued for trading purposes.
Note J: Capitalization
Preferred Stock All of the preferred stock is entitled on voluntary liquidation to its then current call price and on involuntary liquidation to $100 a share. 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: 1997, $26,900,000; 1998, $185,400,000; 1999, $4,300,000; 2000, $165,292,000; and 2001, $165,300,000. 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 1996, AYP Energy issued $160 million of medium-term notes under an arrangement provided by a syndicate of eight banks. The debt is priced at a floating rate based on the 90-day London Interbank Offering Rate plus a spread. AYP Energy entered into a floating-to-fixed interest rate swap to fix the rate at 6.78% to hedge against fluctuations in interest rates. Interest rate differentials to be paid or received are recorded as adjustments to interest expense. Throughout the five-year period, the floating rate may be above or below the fixed rate, but is only relevant in the event of termination prior to maturity. AYP Energy's obligation under the Credit Agreement is supported by the Company.
Commercial paper borrowings issuable by AGC are backed by a revolving credit agreement with a group of six banks, which provides for loans of up to $50 million at any one time outstanding through 2000. Each bank has the option to discontinue its loans after 2000 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, AGC borrowings are made through an internal money pool as described in Note K.
Note K: 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, 1996, unused lines of credit with banks were $325,000,000.
In addition to bank lines of credit, an internal money pool accommodates intercompany short-term borrowing needs, to the extent that certain of the regulated companies have funds available. Short-term debt outstanding for 1996 and 1995 consisted of:
Note L: Commitments and Contingencies
Construction Program The regulated subsidiaries have entered into commitments for their construction programs, for which expenditures are estimated to be $322 million for 1997 and $324 million for 1998. 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 Operations In 1996, AYP Energy was formed as a subsidiary of AYP Capital to operate as a power marketer in the wholesale electricity market. In October 1996, AYP Energy finalized the purchase of a 50% interest (276 MW) in a power station unit, selling the output as an exempt wholesale generator in the wholesale market. Power marketing is essentially participation in a commodity market which creates certain exposures. AYP Energy expects to use exchange-traded and over-the-counter futures, options, and swap contracts both to hedge its exposure to changes in electric power prices and for trading purposes.
The Company is currently committed to invest up to an additional $7 million in AYP Capital to fund its investment in two limited partnerships.
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 Protection Agency had identified them and approximately 875 others as potentially 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 Power Company
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of Monongahela Power Company
In our opinion, the accompanying balance sheet and statement of capitalization and the related statements of income, of retained earnings and of cash flows present fairly, in all material respects, the financial position of Monongahela Power Company (a subsidiary of Allegheny Power System, Inc.) at December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, 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
New York, New York February 5, 1997
See accompanying notes to financial statements.
STATEMENT OF CASH FLOWS
See accompanying notes to financial statements.
See accompanying notes to financial statements.
STATEMENT OF CAPITALIZATION
See accompanying notes to financial statements.
NOTES TO FINANCIAL STATEMENTS (These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company is a wholly owned subsidiary of Allegheny Power System, Inc. and is a part of the Allegheny Power integrated electric utility system (the System).
The Company is subject to regulation by the Securities and Exchange Commission (SEC), by various state bodies having jurisdiction, and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below.
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.
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 regulated 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 postretirement benefits, 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 1996, 1995, and 1994 were 7.90%, 7.29%, and 8.16%, 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 3.1%, 3.4%, and 3.6% of average depreciable property in 1996, 1995, and 1994, respectively. The cost of maintenance and of certain replacements of property, plant, and equipment is charged principally to operating expenses.
Temporary Cash Investments 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.
Regulatory Deferrals In accordance with the Financial Accounting Standards Board's Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," the Company's financial statements reflect assets and liabilities based on current cost-based ratemaking regulation.
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 the maximum amount that can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self- insured; the life insurance plan is paid through insurance premiums.
Bulk Power Transactions Reclassification Effective in 1996, the Company changed its method of reporting certain bulk power transmission transactions with nonaffiliated utilities and reclassified prior years' bulk power and other revenues and operation expenses to achieve a consistent presentation. In prior years, some use of the Company's transmission system was recorded as purchased power from selling utilities and as sales of power to buying utilities. The benefit to the Company was the difference between the two. Because of new FERC requirements, the Company predominantly does not "buy" and "sell" such energy, but rather a transmission fee is charged.
Under the new reporting method, all such transactions are recorded on a net revenue basis. The effect of the reclassifications was to reduce amounts previously reported for bulk power transactions revenues and operation expenses by $79 million and $64 million for 1995 and 1994, respectively, with no change in operating income or net income.
Accounting Change Effective January 1, 1994, the Company changed its revenue recognition method to include the accrual of estimated unbilled revenues for electric services. 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 $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 is not material.
NOTE B: RESTRUCTURING CHARGES AND ASSET WRITE-OFFS
In 1996, the System, including the Company, essentially completed its restructuring initiatives undertaken in 1995, simplifying the management structure and streamlining operations. During 1996, restructuring activities included consolidating operating divisions, customer services, and other functions. By reorganizing and eliminating certain processes and consolidating common decentralized functions, the System reduced employment by about 1,000 employees since October 1994. These reductions were accomplished through a voluntary separation plan, attrition, and layoffs.
In 1996 and 1995, the Company recorded restructuring charges of $24.3 million ($14.6 million after tax) and $4.1 million ($2.5 million after tax) in operating expenses, including its share of all restructuring charges associated with the reorganization, which is essentially complete. These charges reflect liabilities and payments for severance, employee termination costs, and other restructuring costs. The restructuring liability consists of:
*Includes $3,430,000 for benefit plans curtailment liabilities and special termination benefits which are primarily recorded in other deferred credits.
In connection with changes in inventory management objectives, the Company in 1995 also recorded $1.4 million ($.8 million after tax) for the write-off of obsolete and slow-moving materials.
NOTE C: INCOME TAXES
Details of federal and state income tax provisions are:
The total provision for income taxes is different from the amount produced by applying the federal income statutory tax rate of 35% to financial accounting income, as set forth below:
Federal income tax returns through 1993 have been examined and substantially settled through 1991.
At December 31, the deferred tax assets and liabilities consist of the following:
(Thousands of Dollars) 1996 1995
Deferred tax assets: Unamortized investment tax credit............ $ 13,744 $ 15,133 Deferred power costs......................... 5,297 7,483 Restructuring................................ 4,968 1,481 Tax interest capitalized..................... 4,300 4,759 Contributions in aid of construction......... 2,483 2,488 Advances for construction.................... 1,939 1,939 Other........................................ 10,153 10,565 42,884 43,848 Deferred tax liabilities: Book vs. tax plant basis differences, net.... 230,738 209,527 Other........................................ 31,545 32,964 262,283 242,491 Total net deferred tax liabilities............. 219,399 198,643 Add portion above included in current assets... 6,442 7,973 Total long-term net deferred tax liabilities... $225,841 $206,616
NOTE D: DIVIDEND RESTRICTION
Supplemental indentures relating to certain outstanding bonds of the Company contain dividend restrictions under the most restrictive of which $76,384,000 of retained earnings at December 31, 1996, 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 Electric and 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). AGC's ROE was 11.13% for 1994 and 11.2% for 1995. Pursuant to a settlement agreement filed April 4, 1996, with the FERC, AGC's ROE was set at 11% for 1996 and will continue until the time any affected party seeks renegotiation of the ROE. Notice of such intent to seek a revision in ROE must be filed during a notice period each year between November 1 and November 15. No requests for change were filed during the 1996 notice period. Therefore, AGC's ROE will remain at 11% for 1997.
Following is a summary of financial information for AGC:
The Company's share of the equity in earnings above was $7.2 million, $7.4 million, and $8.0 million for 1996, 1995, and 1994, 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:
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:
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, 1996, 1995, and 1994, the discount rates used
were 7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1996, 1995, and 1994.
The pension cost liability at December 31, 1996, includes the net result of a curtailment gain of $2.9 million and an expense for special termination benefits of $1.4 million associated with the work force reduction.
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, a portion of which (about 25% to 30%) was charged to plant construction, included the following components:
The benefits earned to date and funded status of the Company's share of the System plan at December 31 using a measurement date of September 30 were as follows:
In determining the accumulated postretirement benefit obligation (APBO) at September 30, 1996, 1995, and 1994, the discount rates used were 7.5%, 7.5%, and 7.75% and the rates of increase in future compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term rate of return on assets was 8.25% in each of the years 1996, 1995, and 1994. For measurement purposes, a health care trend rate of 7% for 1997, declining to 6.5% in 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, 1996, by $3.7 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1996 by $.3 million.
The postretirement benefit liability at December 31, 1996, includes a curtailment loss of $3.4 million and an expense for special termination benefits of $1.5 million associated with the workforce reduction.
NOTE H: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets, net of regulatory liabilities, reflected in the Balance Sheet at December 31 relate to:
NOTE I: 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 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 has no financial instruments held or issued for trading purposes.
NOTE J: CAPITALIZATION
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 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: 1997, $15,500,000; 1998, $20,100,000; 1999, $1,000,000; 2000, $66,000,000; 2001, $1,000,000. Substantially all of the properties of the Company are held subject to the lien securing its first mortgage bonds. Some properties are also subject to a second lien securing certain pollution control and solid waste disposal notes. Certain first mortgage bonds series are not redeemable by certain refunding until dates established in the respective supplemental indentures.
NOTE K: 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 regulated companies have funds available. Short-term debt outstanding for 1996 and 1995 consisted of:
NOTE L: COMMITMENTS AND CONTINGENCIES
Construction Program The Company has entered into commitments for its construction program, for which expenditures are estimated to be $83 million for 1997 and $91 million for 1998. 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 1996 was used by AGC solely as support for its indebtedness for commercial paper outstanding.
The Potomac Edison Company
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of The Potomac Edison Company
In our opinion, the accompanying balance sheet and statement of capitalization and the related statements of income, of retained earnings and of cash flows present fairly, in all material respects, the financial position of The Potomac Edison Company (a subsidiary of Allegheny Power System, Inc.) at December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, 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
New York, New York February 5, 1997
See accompanying notes to financial statements.
See accompanying notes to financial statements.
See accompanying notes to financial statements.
Preferred Stock: Cumulative preferred stock--par value $100 per share, authorized 5,378,611 shares, outstanding as follows (Note I):
See accompanying notes to financial statements.
NOTES TO FINANCIAL STATEMENTS (These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company is a wholly owned subsidiary of Allegheny Power System, Inc. and is a part of the Allegheny Power integrated electric utility system (the System).
The Company is subject to regulation by the Securities and Exchange Commission (SEC), by various state bodies having jurisdiction, and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below.
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. Revenues of $64 million from one industrial customer were 9% of total electric operating revenues in 1996.
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 regulated affiliates in the System, are stated at original cost, less contributions in aid of construction. Cost includes direct labor and material, allowance for funds used during construction (AFUDC) on property for which construction work in progress is not included in rate base, and such indirect costs as administration, maintenance, and depreciation of transportation and construction equipment, and postretirement benefits, 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 1996, 1995, and 1994 were 9.32%, 9.71%, and 9.73%, 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% of average depreciable property in 1996 and 1995 and 3.4% in 1994. The cost of maintenance and of certain replacements of property, plant, and equipment is charged principally to operating expenses.
Temporary Cash Investments 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.
Regulatory Deferrals In accordance with the Financial Accounting Standards Board's Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," the Company's financial statements reflect assets and liabilities based on current cost-based ratemaking regulation.
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 the maximum amount that can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self-insured; the life insurance plan is paid through insurance premiums.
Bulk Power Transactions Reclassification Effective in 1996, the Company changed its method of reporting certain bulk power transmission transactions with nonaffiliated utilities and reclassified prior years' bulk power and other revenues and operation expenses to achieve a consistent presentation. In prior years, some use of the Company's transmission system was recorded as purchased power from selling utilities and as sales of power to buying utilities. The benefit to the Company was the difference between the two. Because of new FERC requirements, the Company predominantly does not "buy" and "sell" such energy, but rather a transmission fee is charged.
Under the new reporting method, all such transactions are recorded on a net revenue basis. The effect of the reclassifications was to reduce amounts previously reported for bulk power transactions revenues and operation expenses by $108 million and $86 million for 1995 and 1994, respectively, with no change in operating income or net income.
Accounting Change Effective January 1, 1994, the Company changed its revenue recognition method to include the accrual of estimated unbilled revenues for electric services. 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 is not material.
NOTE B: RESTRUCTURING CHARGES AND ASSET WRITE-OFFS
In 1996, the System, including the Company, essentially completed its restructuring initiatives undertaken in 1995, simplifying the management structure and streamlining operations. During 1996, restructuring activities included consolidating operating divisions, customer services, and other functions. By reorganizing and eliminating certain processes and consolidating common decentralized functions, the System reduced employment by about 1,000 employees since October 1994. These reductions were accomplished through a voluntary separation plan, attrition, and layoffs.
In 1996 and 1995, the Company recorded restructuring charges of $26.1 million ($16.5 million after tax) and $4.6 million ($2.9 million after tax) in operating expenses, including its share of all restructuring charges associated with the reorganization, which is essentially complete. These charges reflect liabilities and payments for severance, employee termination costs, and other restructuring costs. The restructuring liability consists of:
*Includes $5,082,000 for benefit plans curtailment liabilities and special termination benefits which are primarily recorded in other deferred credits.
In connection with changes in inventory management objectives, the Company in 1995 also recorded $2.2 million ($1.4 million after tax) for the write-off of obsolete and slow-moving materials.
NOTE C: INCOME TAXES
The total provision for income taxes is different from the amount produced by applying the federal income statutory tax rate of 35% to financial accounting income, as set forth below:
Federal income tax returns through 1993 have been examined and substantially settled through 1991.
At December 31, the deferred tax assets and liabilities consist of the following:
NOTE D: ALLEGHENY GENERATING COMPANY
The Company owns 28% of the common stock of Allegheny Generating Company (AGC), and affiliates of the Company own the remainder. AGC owns an undivided 40% interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric station in Bath County, Virginia operated by the 60% owner, Virginia Electric and 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). AGC's ROE was 11.13% for 1994 and 11.2% for 1995. Pursuant to a settlement agreement filed April 4, 1996, with the FERC, AGC's ROE was set at 11% for 1996 and will continue until the time any affected party seeks renegotiation of the ROE. Notice of such intent to seek a revision in ROE must be filed during a notice period each year between November 1 and November 15. No requests for change were filed during the 1996 notice period. Therefore, AGC's ROE will remain at 11% for 1997.
Following is a summary of financial information for AGC:
The Company's share of the equity in earnings above was $7.5 million, $7.6 million, and $8.3 million for 1996, 1995, and 1994, respectively, and is included in other income, net, on the Statement of Income.
NOTE E: PENSION BENEFITS The Company's share of net pension costs under the System's pension plan, a portion of which (about 25% to 30%) was charged to plant construction, included the following components:
The benefits earned to date and funded status of the Company's share of the System plan at December 31 using a measurement date of September 30 were as follows:
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, 1996, 1995, and 1994, the discount rates used were 7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1996, 1995, and 1994.
The pension cost prepaid at December 31, 1996, includes the net result of a curtailment gain of $3.8 million and an expense for special termination benefits of $1.6 million associated with the workforce reduction.
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, a portion of which (about 25% to 30%) was charged to plant construction, included the following components:
The benefits earned to date and funded status of the Company's share of the System plan at December 31 using a measurement date of September 30 were as follows:
In determining the accumulated postretirement benefit obligation (APBO) at September 30, 1996, 1995, and 1994, the discount rates used were 7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term rate of return on assets was 8.25% in each of the years 1996, 1995, and 1994. For measurement purposes, a health care trend rate of 7% for 1997, declining to 6.5% in 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, 1996, by $4 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1996 by $.4 million.
The postretirement benefit liability at December 31, 1996, includes a curtailment loss of $4.9 million and an expense for special termination benefits of $2.4 million associated with the workforce reduction.
NOTE G: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets, net of regulatory liabilities, reflected in the Balance Sheet at December 31 relate to:
NOTE H: 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 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 has no financial instruments held or issued for trading purposes.
NOTE I: CAPITALIZATION
Other Paid-In Capital Other paid-in capital decreased $34,000 in 1995 and increased $10,000 in 1994 as a result of preferred stock transactions.
Preferred Stock All of the preferred stock is entitled on voluntary liquidation to its then current call price and on involuntary liquidation to $100 a share.
Long-Term Debt and QUIDS Maturities for long-term debt for the next five years are: 1997, $800,000; 1998, $1,800,000; 1999, $1,800,000; 2000, $76,800,000; and 2001, $1,800,000. Substantially all of the properties of the Company are held subject to the lien securing its first mortgage bonds. Some properties are also subject to a second lien securing certain pollution control and solid waste disposal notes. Certain first mortgage bond series are not redeemable by certain refunding until dates established in the respective supplemental indentures.
NOTE J: SHORT-TERM 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 regulated companies have funds available. Short-term debt outstanding for 1996 and 1995 consisted of:
NOTE K: COMMITMENTS AND CONTINGENCIES
Construction Program The Company has entered into commitments for its construction program, for which expenditures are estimated to be $98 million for 1997 and $109 million for 1998. 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 1996 was used by AGC solely as support for its indebtedness for commercial paper outstanding.
West Penn Power Company and Subsidiaries
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors of West Penn Power Company
In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, of retained earnings and of cash flows present fairly, in all material respects, the financial position of West Penn Power Company (a subsidiary of Allegheny Power System, Inc.) and its subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, 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
New York, New York February 5, 1997
CONSOLIDATED STATEMENT OF INCOME
See accompanying notes to consolidated financial statements.
See accompanying notes to consolidated financial statements.
See accompanying notes to consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (These notes are an integral part of the consolidated financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company is a wholly owned subsidiary of Allegheny Power System, Inc. and is a part of the Allegheny Power integrated electric utility system (the System).
The Company is subject to regulation by the Securities and Exchange Commission (SEC), by various state bodies having jurisdiction, and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below.
Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries (the companies).
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.
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 regulated 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 postretirement benefits,
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 1996, 1995, and 1994 were 7.83%, 8.90%, and 8.88%, 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 4.0%, 3.9%, and 3.5% of average depreciable property in 1996, 1995, and 1994, respectively. The cost of maintenance and of certain replacements of property, plant, and equipment is charged principally to operating expenses.
Temporary Cash Investments 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.
Regulatory Deferrals In accordance with the Financial Accounting Standards Board's Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," the Company's consolidated financial statements reflect assets and liabilities based on current cost-based ratemaking regulation.
Income Taxes The companies join with their 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 the maximum amount that can be deducted for federal income tax purposes. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self-insured; the life insurance plan is paid through insurance premiums.
Bulk Power Transactions Reclassification Effective in 1996, the Company changed its method of reporting certain bulk power transmission transactions with nonaffiliated utilities and reclassified prior years' bulk power and other revenues and operation expenses to achieve a consistent presentation. In prior years, some use of the Company's transmission system was recorded as purchased power from selling utilities and as sales of power to buying utilities. The benefit to the Company was the difference between the two. Because of new FERC requirements, the Company predominantly does not "buy" and "sell" such energy, but rather a transmission fee is charged.
Under the new reporting method, all such transactions are recorded on a net revenue basis. The effect of the reclassifications was to reduce amounts previously reported for bulk power transactions revenues and operation expenses by $145 million and $117 million for 1995 and 1994, respectively, with no change in operating income or consolidated net income.
Accounting Change Effective January 1, 1994, the Company changed its revenue recognition method to include the accrual of estimated unbilled revenues for electric services. 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 is not material.
NOTE B: RESTRUCTURING CHARGES AND ASSET WRITE-OFFS In 1996, the System, including the Company, essentially completed its restructuring initiatives undertaken in 1995, simplifying the management structure and streamlining operations. During 1996, restructuring activities included consolidating operating divisions, customer services, and other functions. By reorganizing and eliminating certain processes and consolidating common decentralized functions, the System reduced employment by about 1,000 employees since October 1994. These reductions were accomplished through a voluntary separation plan, attrition, and layoffs.
In 1996 and 1995, the Company recorded restructuring charges of $42.6 million ($25.1 million after tax) and $7.3 million ($4.3 million after tax) in operating expenses, including its share of all restructuring charges associated with the reorganization, which is essentially complete. These charges reflect liabilities and payments for severance, employee termination costs, and other restructuring costs. The restructuring liability consists of:
*Includes $5,237,000 for benefit plans curtailment liabilities and special termination benefits which are primarily recorded in other deferred credits.
In 1996 and 1994, the Company wrote off $10.8 million ($6.3 million after tax) and $8.9 million ($5.2 million after tax), respectively, of previously accumulated costs related to a proposed transmission line and a potential future power plant site. In the industry's more competitive environment, it was no longer reasonable to assume future recovery of these costs in rates.
In connection with changes in inventory management objectives, the Company in 1995 also recorded $3.8 million ($2.3 million after tax) for the write-off of obsolete and slow-moving materials.
NOTE C: INCOME TAXES
Details of federal and state income tax provisions are:
The total provision for income taxes is different from the amount produced by applying the federal income statutory tax rate of 35% to financial accounting income, as set forth below:
Federal income tax returns through 1993 have been examined and substantially settled through 1991.
At December 31, the deferred tax assets and liabilities consist of the following:
NOTE D: DIVIDEND RESTRICTION
Supplemental indentures relating to certain outstanding bonds of the Company contain dividend restrictions under the most restrictive of which $70,576,000 of consolidated retained earnings at December 31, 1996, 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 Electric and 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). AGC's ROE was 11.13% for 1994 and 11.2% for 1995. Pursuant to a settlement agreement filed April 4, 1996, with the FERC, AGC's ROE was set at 11% for 1996 and will continue until the time any affected party seeks renegotiation of the ROE. Notice of such intent to seek a revision in ROE must be filed during a notice period each year between November 1 and November 15. No requests for change were filed during the 1996 notice period. Therefore, AGC's ROE will remain at 11% for 1997.
Following is a summary of financial information for AGC:
The Company's share of the equity in earnings above was $12.1 million, $12.3 million, and $13.4 million for 1996, 1995, and 1994, 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:
It is expected that regulatory deferrals amounting to $1,520,000 will be amortized to operating expenses in 1997 and 1998 in accordance with authorized rate recovery.
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:
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, 1996, 1995, and 1994, the discount rates used were 7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term rate of return on assets was 9% in each of the years 1996, 1995, and 1994.
The pension cost prepaid at December 31, 1996, includes the net result of a curtailment gain of $4.8 million and an expense for special termination benefits of $1.5 million associated with the workforce reduction.
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, a portion of which (about 25% to 30%) was charged to plant construction, included the following components:
In determining the accumulated postretirement benefit obligation (APBO) at September 30, 1996, 1995, and 1994, the discount rates used were 7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term rate of return on assets was 8.25% in each of the years 1996, 1995, and 1994. For measurement purposes, a health care trend rate of 7% for 1997, declining to 6.5% in 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, 1996, by $4.1 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1996 by $.4 million.
The postretirement benefit liability at December 31, 1996, includes a curtailment loss of $6.2 million and an expense for special termination benefits of $2.3 million associated with the workforce reduction.
NOTE H: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets, net of regulatory liabilities, reflected in the Consolidated Balance Sheet at December 31 relate to:
NOTE I: 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 Company has no financial instruments held or issued for trading purposes.
NOTE J: CAPITALIZATION
Common Stock and Other Paid-In Capital The Company issued and sold 2,000,000 shares of common stock to its parent, at $20 per share, in October 1994. Other paid-in capital decreased $212,000 in 1995 as a result of preferred stock transactions.
Preferred Stock All of the preferred stock is entitled on voluntary liquidation to its then current call price and on involuntary liquidation to $100 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: 1997, none; 1998, $103,500,000; 1999, $1,500,000; 2000, $2,500,000; and 2001, $2,500,000. Substantially all of the properties of the Company are held subject to the lien securing its first mortgage bonds. Some properties are also subject to a second lien securing certain pollution control and solid waste disposal notes. Certain first mortgage bond series are not redeemable by certain refunding until dates established in the respective supplemental indentures.
NOTE K: 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 regulated companies have funds available. Short-term debt outstanding for 1996 and 1995 consisted of:
NOTE L: COMMITMENTS AND CONTINGENCIES
Construction Program The Company has entered into commitments for its construction program, for which expenditures are estimated to be $140 million for 1997 and $123 million for 1998. 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 45% of a $50 million revolving credit agreement of AGC, which in 1996 was used by AGC solely as support for its indebtedness for commercial paper outstanding.
Allegheny Generating Company
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors of Allegheny Generating Company
In our opinion, the accompanying balance sheet and the related statements of income, of retained earnings and of cash flows present fairly, in all material respects, the financial position of Allegheny Generating Company (an Allegheny Power System, Inc. affiliate) at December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, 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
New York, New York February 5, 1997
See accompanying notes to financial statements.
See accompanying notes to financial statements.
See accompanying notes to financial statements.
NOTES TO FINANCIAL STATEMENTS (These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company was incorporated in Virginia in 1981. Its common stock is owned by Monongahela Power Company - 27%, The Potomac Edison Company - 28%, and West Penn Power Company - 45% (the Parents). The Parents are wholly-owned subsidiaries of Allegheny Power System, Inc. and are a part of the Allegheny Power integrated electric utility system. The Company is subject to regulation by the Securities and Exchange Commission (SEC) and by the Federal Energy Regulatory Commission (FERC). Significant accounting policies of the Company are summarized below.
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 1996, 1995, and 1994. The cost of maintenance and of certain replacements of property, plant, and equipment is charged to operating expenses.
Income Taxes The Company joins with its parents and affiliates in filing a consolidated federal income tax return. The consolidated tax liability is allocated among the participants generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return tax liability.
Financial accounting income before income taxes differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in another period. Differences between income tax expense computed on the basis of financial accounting income and taxes payable based on taxable income are deferred. Deferred tax assets and liabilities 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.
NOTE B: INCOME TAXES
Details of federal income tax provisions are:
In 1996, the total provision for income taxes ($13,297,000) was less than the amount produced by applying the federal income tax statutory rate of 35% to financial accounting income before income taxes ($14,030,000), due primarily to amortization of deferred investment credit ($1,322,000).
Federal income tax returns through 1993 have been examined and substantially settled through 1991.
At December 31, the deferred tax assets and liabilities were comprised of the following:
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 $14.5 million and $14.6
million as of December 31, 1996 and 1995, respectively. Regulatory liabilities of $27.5 million as of December 31, 1996, and 1995, 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:
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: CAPITALIZATION
The Company systematically reduces capitalization each year as its asset depreciates, and this has resulted in the payment of dividends in excess of current earnings. The SEC has approved the Company's request to pay common stock dividends out of capital. In 1996 common dividends of $30,942,000 were paid from retained earnings, reducing the account balance to zero, and common dividends of $7,045,000 were paid from other paid-in capital.
(1) Weighted average interest rate at December 31, 1996.
The Company has a revolving credit agreement with a group of six banks, which provides for loans of up to $50 million at any one time outstanding through 2000. Each bank has the option to discontinue its loans after 2000 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 regulated affiliates have funds available.
Maturities for long-term debt for the next five years are: 1997, $10,600,000; 1998, $60,000,000; 1999, none; 2000, $19,992,000; and 2001, none.
S-1 SCHEDULE II
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts For Years Ended December 31, 1996, 1995, and 1994
(A) Recoveries. (B) Uncollectible accounts charged off.
S-2 SCHEDULE II
MONONGAHELA POWER COMPANY
Valuation and Qualifying Accounts For Years Ended December 31, 1996, 1995, and 1994
(A) Recoveries. (B) Uncollectible accounts charged off.
(A) Recoveries. (B) Uncollectible accounts charged off.
S-4 SCHEDULE II
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts For Years Ended December 31, 1996, 1995, and 1994
(A) Recoveries. (B) Uncollectible accounts charged off.
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Supplementary Data Quarterly Financial Data (Unaudited) (Thousands of Dollars)
These notes do not pertain to AGC.
* Amounts for 1996 quarters have been reclassified for comparative purposes to reflect a change in 1996 for reporting certain bulk power transmission transactions.
** Results for the quarters ended September and December 1995 and for each of the quarters in 1996 include restructuring charges and asset write-offs.
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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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, 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
New York, New York February 5, 1997
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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, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, 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
New York, New York February 5, 1997
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REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of The Potomac Edison Company
In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of The Potomac Edison Company (a subsidiary of Allegheny Power System, Inc.) at December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, 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
New York, New York February 5, 1997
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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, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, 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
New York, New York February 5, 1997
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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, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, 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
New York, New York February 5, 1997
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ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
For APS and the Subsidiaries, none.
PART III
ITEM 10.
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 as of December 31, 1996, 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 of Accreditation Board for Engineering and Technology. Formerly, 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., Noel Group, Inc. and Sylvan, Inc.
(c) Wendell F. Holland. Vice President, American Water Works Service Company. Formerly, Of Counsel, Law Firm of Reed, Smith, Shaw & McClay; Partner, Law Firm of LeBoeuf, Lamb, Greene & MacRae; and Commissioner of the Pennsylvania Public Utility Commission.
(d) Phillip E. Lint. Retired. Formerly, partner, Price Waterhouse.
(e) Edward H. Malone. Retired. Formerly, Vice President of General Electric Company and Chairman, General Electric Investment Corporation. Director of Fidelity Group of Mutual Funds, General Re Corporation, and Mattel, Inc.
(f) Frank A. Metz, Jr. Retired. Formerly, Senior Vice President, Finance and Planning, and Director of International Business Machines Corporation. Director of Monsanto Company and Norrell Corporation.
(g) Steven H. Rice. Bank and real estate 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 Member of Temblor Petroleum Company L.L.C., a privately owned oil and gas exploration and production company operating exclusively in California, and an Individual General Partner of Panther Partners, L.P., a closed-end, non-diversified management company. Formerly, managing director of Hydrocarbon Energy, Inc., a privately owned oil and gas development drilling and production company.
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ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
During 1996, and for 1995 and 1994, the annual compensation paid by the System companies, APS, APSC, Monongahela, Potomac Edison, West Penn and AGC directly or indirectly for services in all capacities to such companies to their Chief Executive Officer and each of the four most highly paid executive officers of the System whose cash compensation exceeded $100,000 was as follows:
(a) The individuals appearing in this chart perform policy-making functions for each of the Registrants. The compensation shown is for all services in all capacities to APS, APSC and the Subsidiaries. All salaries and bonuses of these executives are paid by APSC.
(b) APS has no paid employees.
(c) AGC has no paid employees.
(d) See Executive Officers of the Registrants for all positions held.
(e) Incentive awards are based upon performance in the year in which the figure appears but are paid in the following year. The incentive award plan will be continued for 1997.
(f) In 1994, the Boards of Directors of APS, APSC and the Operating Subsidiaries implemented a Performance Share Plan (the "Plan") for senior officers which was approved by the shareholders of APS at the annual meeting in May 1994. The first Plan cycle began on January 1, 1994 and ended on December 31, 1996. The figure shown represents the dollar value to be paid to each of the named executive officers who participated in Cycle I. A second cycle began on January 1, 1995 and will end on December 31, 1997. A third cycle began on January 1, 1996 and will end on December 31, 1998. A fourth cycle began on January 1, 1997 and will end on December 31, 1999. After completion of each cycle, APS stock
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or cash may be paid if performance criteria have been met.
(g) Effective January 1, 1992, the basic group life insurance provided employees was reduced from two times salary during employment, which reduced to one times salary after 5 years in retirement, to a new plan which provides one times salary until retirement and $25,000 thereafter. Some executive officers and other senior managers remain under the prior plan. In order to pay for this insurance for these executives, during 1992 insurance was purchased on the lives of each of them. Effective January 1, 1993, APS started to provide funds to pay for the future benefits due under the supplemental retirement plan (Secured Benefit Plan) as described in note (d) on p. 54. To do this, APS purchased, during 1993, life insurance on the lives of the covered executives. The premium costs of both the 1992 and 1993 policies plus a factor for the use of the money are returned to APS at the earlier of (a) death of the insured or (b) the later of age 65 or 10 years from the date of the policy's inception. The figures in this column include the present value of the executives' cash value at retirement attributable to the current year's premium payment (based upon the premium, future valued to retirement, using the policy internal rate of return minus the corporation's premium payment), as well as the premium paid for the basic group life insurance program plan and the contribution for the 401(k) plan. For 1996, the figure shown includes amounts representing (a) the aggregate of life insurance premiums and dollar value of the benefit to the executive officer of the remainder of the premium paid on the Group Life Insurance program and the Executive Life Insurance and Secured Benefit Plans, and (b) 401(k) contributions as follows: Mr. Noia $88,269 and $4,500; Mr. Bergman $58,700 and $4,500; Mr. Skrgic $20,330 and $4,500; Mr. Pifer $26,449 and $4,500; Mr. Gagliardi $13,398 and $4,500; and Mr. Jones $21,188 and $4,500, respectively.
(h) Mr. Bergman retired effective June 1, 1996 from his position as Chief Executive Officer of APS and each Subsidiary. He will retire from his position as Chairman of the Board effective May 8, 1997. Mr. Bergman did not receive an incentive award for 1996 because six months of service is required before an award may be granted.
(i) Included in this amount is $56,058 representing accrued vacation for which he was paid.
ALLEGHENY POWER SYSTEM PERFORMANCE SHARE PLAN UNITS AWARDED IN LAST FISCAL YEAR - (CYCLE III)
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The named executives were awarded the above number of shares for Cycle III. Such number of shares are only targets. As described below, no payouts will be made unless certain criteria are met. Each executive's 1996-1998 target long-term incentive opportunity was converted into performance shares equal to an equivalent number of shares of APS common stock based on the price of such stock on December 31, 1995. At the end of this three-year performance period, the performance shares attributed to the calculated award will be valued based on the price of APS common stock on December 31, 1998 and will reflect dividends that would have been paid on such stock during the performance period as if they were reinvested on the date paid. If an executive retires, dies or otherwise leaves the employment of the Allegheny Power prior to the end of the three-year period, the executive may still receive an award based on the number of months worked during the period. However, an executive must work at least eighteen months during the three-year period to be eligible for an award payout. The final value of an executive's account, if any, will be paid to the executive in stock or cash in early 1999.
The actual payout of an executive's award may range from 0 to 200% of the target amount, before dividend re-investment. The payout is based upon customer and stockholder performance factors and APS's rankings versus the peer group. The combined customer and stockholder rating is then compared to a pre- established percentile ranking chart to determine the payout percentage of target. A ranking below 30% results in a 0% payout. The minimum payout begins at the 30% ranking, which results in a payout of 60% of target, ranging up to a payout of 200% of target if there is a 90% or higher ranking.
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE (a) APS(b), Monongahela, Potomac Edison, West Penn and AGC (c)
(a) The individuals appearing in this chart perform policy-making functions for each of the Registrants.
(b) APS has no paid employees.
(c) AGC has no paid employees.
(d) Assumes present insured benefit plan and salary continue and retirement at age 65 with single life annuity. Under plan provisions, the annual rate of benefits payable at the normal retirement age of 65 are computed by adding (i) 1% of final average pay up to covered compensation times years of service up to 35 years, plus (ii) 1.5% of final average pay in excess of covered compensation times years of service up to 35 years, plus (iii) 1.3% of final average pay times years of service in excess of 35 years. Covered
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compensation is the average of the maximum taxable Social Security wage bases during the 35 years preceding the member's retirement. The final average pay benefit is based on the member's average total earnings during the highest-paid 60 consecutive calendar months or, if smaller, the member's highest rate of pay as of any July 1st. Effective July 1, 1994 the maximum amount of any employee's compensation that may be used in these computations was decreased to $150,000. Benefits for employees retiring between 55 and 62 differ from the foregoing.
Pursuant to a supplemental plan (Secured Benefit Plan), senior executives of Allegheny Power System companies who retire at age 60 or over with 40 or more years of service are entitled to a supplemental retirement benefit in an amount that, together with the benefits under the basic plan and from other employment, will equal 60% of the executive's highest average monthly earnings for any 36 consecutive months. The earnings include 50% of the actual annual bonus paid effective February 1, 1996. The figures shown do not give any effect to bonus payments. The supplemental benefit is reduced for less than 40 years service and for retirement age from 60 to 55. It is included in the amounts shown where applicable. In order to provide funds to pay such benefits, effective January 1, 1993 the Company purchased insurance on the lives of the plan participants. The Secured Benefit Plan has been designed that if the assumptions made as to mortality experience, policy dividends, and other factors are realized, the Company will recover all premium payments, plus a factor for the use of the Company's money. The amount of the premiums for this insurance required to be deemed "compensation" by the SEC is described and included in the "All Other Compensation" column on page 52. All executive officers are participants in the Secured Benefit Plan. The figures shown do not include benefits from an Employee Stock Ownership and Savings Plan (ESOSP) established as a non-contributory stock ownership plan for all eligible employees effective January 1, 1976, and amended in 1984 to include a savings program. Under the ESOSP for 1996, all eligible employees may elect to have from 2% to 7% of their compensation contributed to the Plan as pre-tax contributions and an additional 1% to 6% as post-tax contributions. Employees direct the investment of these contributions into one or more available funds. Each System company matches 50% of the pre-tax contributions up to 6% of compensation with common stock of Allegheny Power System, Inc. Effective January 1, 1994 the maximum amount of any employee's compensation that may be used in these computations was decreased to $150,000. Employees' interests in the ESOSP vest immediately. Their pre-tax contributions may be withdrawn only upon meeting certain financial hardship requirements or upon termination of employment.
(e) See Executive Officers of the Registrants for all positions held.
(f) The total estimated annual benefits on retirement payable to Messrs. Noia, Skrgic, Pifer, Gagliardi and Jones for services in all capacities to APS, APSC and the Subsidiaries is set forth in the table.
(g) Mr. Bergman retired effective June 1, 1996 as Chief Executive Officer and will retire effective May 8, 1997 as Chairman of the Board. The actual amount he is receiving for service in all capacities to APS, APSC and the Subsidiaries is set forth in the table.
Change In Control Contracts
In March 1996, APS entered into Change in Control 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 thirty-six months after a Change in Control.
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Compensation of Directors
In 1996, APS directors who were not officers or employees of System companies received for all services to System companies (a) $16,000 in retainer fees, (b) $800 for each committee meeting attended, except Executive Committee meetings, for which fees are $200, and (c) $250 for each Board meeting of each company attended, and 200 shares of APS common stock pursuant to the Restricted Stock Plan for Outside Directors. 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. Subsequent to June 1, 1996, Mr. Bergman has received a fixed fee at the annual rate of $100,000 for services in all capacities to APS and the Subsidiaries.
In addition to the fees mentioned above, the Chairperson of each of the Audit, Finance, Management Review, New Business, and Strategic Affairs Committees receives a further fee of $4,000 per year. The outside Directors also were covered by a Directors' Retirement Plan (Plan) in 1996 which provides an annual pension equal to the retainer fee paid to the outside director at the time of his or her retirement, provided the director was serving at December 5, 1996, has at least five (5) years of service and, except under special circumstances described in the Plan, serves until age 65. Directors elected after December 5, 1996 will not be covered under the Plan.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The table below shows the number of shares of APS common stock that are beneficially owned, directly or indirectly, by each director and named executive officer of APS, Monongahela, Potomac Edison, West Penn, and AGC and by all directors and executive officers of each such company as a group as of December 31, 1996. To the best of the knowledge of APS, there is no person who is a beneficial owner of more than 5% of the voting securities of APS.
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All of the shares of common stock of Monongahela (5,891,000), Potomac Edison (22,385,000), and West Penn (24,361,586) are owned by APS. All of the common stock of AGC is owned by Monongahela (270 shares), Potomac Edison (280 shares), and West Penn (450 shares).
ITEM 13.
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 loan terms required repayment to Allegheny Power upon actual relocation. In addition, relocating employees were reimbursed by Allegheny Power for interest paid on a new mortgage 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. On June 21, 1996, Allegheny Power made an interest-free loan in the amount of $85,000 to Eileen M. Beck, Secretary of APS, Monongahela, Potomac Edison, West Penn and AGC. All outstanding balances on these loans were repaid in full in 1996.
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PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1)(2) The financial statements and financial statement schedules filed as part of this Report are set forth under ITEM 8. and reference is made to the index on page 44.
(b) No reports on Form 8-K were filed by System companies during the quarter ended December 31, 1996.
(c) Exhibits for APS, Monongahela, Potomac Edison, West Penn, and AGC are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ALLEGHENY POWER SYSTEM, INC.
By: ALAN J. NOIA (Alan J. Noia) President and Chief Executive Officer Date: March 6, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. MONONGAHELA POWER COMPANY
By: JAY S. PIFER (Jay S. Pifer) President and Director
Date: March 6, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. THE POTOMAC EDISON COMPANY
By: JAY S. PIFER (Jay S. Pifer) President and Director Date: March 6, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
WEST PENN POWER COMPANY
By: JAY S. PIFER (Jay S. Pifer) President and Director Date: March 6, 1997
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ALLEGHENY GENERATING COMPANY
By: ALAN J. NOIA (Alan J. Noia) Chief Executive Officer
Date: March 6, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
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CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectus constituting part of Allegheny Power System, Inc.'s Registration Statements on Form S-3 (Nos. 33-36716 and 33-57027) relating to the Dividend Reinvestment and Stock Purchase Plan of Allegheny Power System, Inc.; in the Prospectus constituting part of Allegheny Power System, Inc.'s Registration Statement on Form S-3 (No. 33-49791) relating to the common stock shelf registration; in the Prospectus constituting part of Monongahela Power Company's Registration Statements on Form S-3 (Nos. 33-51301, 33-56262 and 33-59131); in the Prospectus constituting part of The Potomac Edison Company's Registration Statements on Form S-3 (Nos. 33-51305 and 33-59493); and in the Prospectus constituting part of West Penn Power Company's Registration Statements on Form S-3 (Nos. 33-51303, 33-56997, 33-52862, 33-56260 and 33-59133); of our reports dated February 5, 1997 included in ITEM 8 of this Form 10-K. We also consent to the references to us under the heading "Experts" in such Prospectuses.
PRICE WATERHOUSE LLP
New York, New York March 21, 1997
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POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Power System, Inc., a Maryland corporation, Monongahela Power Company, an Ohio corporation, The Potomac Edison Company, a Maryland and Virginia corporation, and West Penn Power Company, a Pennsylvania corporation, do hereby constitute and appoint THOMAS K. HENDERSON and EILEEN M. BECK, and each of them, a true and lawful attorney in his or her name, place and stead, in any and all capacities, to sign his or her name to Annual Reports on Form 10-K for the year ended December 31, 1996 under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Companies, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratifies and confirms all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.
Dated: March 6, 1997
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POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Monongahela Power Company, an Ohio corporation, The Potomac Edison Company, a Maryland and Virginia corporation, and West Penn Power Company, a Pennsylvania corporation, do hereby constitute and appoint THOMAS K. HENDERSON and EILEEN M. BECK, and each of them, a true and lawful attorney in his name, place and stead, in any and all capacities, to sign his or her name to the Annual Report on Form 10-K for the year ended December 31, 1996 under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.
Dated: March 6, 1997
MICHAEL P. MORRELL (Michael P. Morrell)
JAY S. PIFER (Jay S. Pifer)
PETER J. SKRGIC (Peter J. Skrgic)
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POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Generating Company, a Virginia corporation, do hereby constitute and appoint THOMAS K. HENDERSON and EILEEN M. BECK, and each of them, a true and lawful attorney in his name, place and stead, in any and all capacities, to sign his or her name to the Annual Report on Form 10-K for the year ended December 31, 1996 under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said Company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.
Dated: March 6, 1997
THOMAS K. HENDERSON (Thomas K. Henderson)
KENNETH M. JONES (Kenneth M. Jones)
MICHAEL P. MORRELL (Michael P. Morrell)
ALAN J. NOIA (Alan J. Noia)
PETER J. SKRGIC (Peter J. Skrgic)
E-4
West Penn Power Company
* There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the Commission on its request with copies of such Supplemental Indentures.
E-4, (Cont'd)
West Penn Power Company
Incorporation Documents by Reference
21 Subsidiaries: West Penn Power Company has a 45% equity ownership in Allegheny Generating Company, incorporated in Virginia; a 50% equity ownership in Allegheny Pittsburgh Coal Company, incorporated in Pennsylvania; and a 100% equity ownership in West Virginia Power and Transmission Company, incorporated in West Virginia, which owns a 100% equity ownership in West Penn West Virginia Water Power Company, incorporated in Pennsylvania.