ITEM 1. BUSINESS
Allegheny Energy, Inc. (AE), incorporated in Maryland in 1925, is an electric utility holding company which owns directly and indirectly various regulated and non-regulated subsidiaries (collectively and generically, Allegheny). In 1998, AE derived substantially all of its income from the electric utility operations of its direct and indirect regulated subsidiaries Monongahela Power Company (Monongahela), The Potomac Edison Company (Potomac Edison), West Penn Power Company (West Penn), and Allegheny Generating Company (AGC) (collectively, the Regulated Subsidiaries). The properties of the Regulated 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). The Operating Subsidiaries are doing business under the trade name Allegheny Power.
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 355,900 customers in a service area of about 11,900 square miles with a population of about 710,000. The seven largest communities served have populations ranging from 10,900 to 33,900. 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.
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 390,200 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. 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. In December 1996, Pennsylvania enacted the Electricity Generation Customer Choice and Competition Act (Customer Choice Act) to restructure the electric industry in Pennsylvania to create retail access to a competitive electric energy generation market. As of January 2, 1999, two-thirds of West Penn's retail load was able to choose their electric generation supplier. See ITEM 1. COMPETITION and ITEM 1. RATE MATTERS for a discussion of the status of competition in Pennsylvania. As a consequence of the Customer Choice Act, West Penn reorganized into a Delivery Business Unit (supplying transmission and distribution to customers in West Penn's service territory), and a Supply Business Unit (supplying retail generation throughout Pennsylvania, outside West Penn's service area, and other states in the region implementing customer choice, and wholesale generation anywhere). The next step for the Supply Business Unit is for it to become a separate, unregulated affiliate generation company, in 1999. Only one- third of West Penn's retail load remains regulated, about 224,100 customers. West Penn's service area contains about 9,900 square miles with a population of about 1,399,000. The 10 largest communities served by West Penn have populations ranging from 11,200 to 38,900. 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 their power from a pool that purchases a portion of its power from West Penn.
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).
AE, the Regulated Subsidiaries, and AYP Capital, Inc. and its subsidiaries have no employees. Their officers are employed by Allegheny Power Service Corporation (APSC), a wholly owned subsidiary of AE, incorporated in Maryland in 1963. APSC's employees provide all necessary services to AE, the Regulated Subsidiaries, and AYP Capital, Inc. and its subsidiaries. Those companies reimburse APSC for services provided by APSC's employees. On December 31, 1998, APSC had approximately 4,817 employees.
AYP Capital, Inc. (AYP Capital), incorporated in Delaware in 1994, is a wholly owned nonutility subsidiary of AE. AYP Capital has three wholly owned subsidiaries--AYP Energy, Inc. (AYP Energy), Allegheny Communications Connect, Inc. (ACC), and Allegheny Energy Solutions, Inc. (Allegheny Energy Solutions), all Delaware corporations. 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 and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Significant Events in 1998, 1997 and 1996 for a further description of AYP Capital and its subsidiaries' activities.) AYP Capital and its subsidiaries have no employees. However, as of December 31, 1998, 25 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. AE's total investment in AYP Capital and its subsidiaries as of December 31, 1998, was $19.7 million. AE is currently committed to invest up to an additional $3.2 million in AYP Capital to fund AYP Capital's investment in two limited partnerships.
The move to a more competitive environment presents Allegheny with a new set of opportunities and challenges, including determining the appropriate industry structure, determining recovery of transition 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.
FACTORS THAT MAY AFFECT FUTURE RESULTS
In addition to the historical information contained herein, this report contains a number of "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. These include statements with respect to deregulation activities and movements toward competition in states served by the Operating Companies, the merger with DQE, Inc., capital expenditures, earnings on assets, resolution and impact of litigation, regulatory matters, liquidity and capital resources, and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially include, but are not limited to: the impact of general economic changes in the U.S.; the impact of deregulation on the electric utility business; increased competition and electric utility restructuring in the U.S., including ongoing state and federal activities; potential Year 2000 operation problems; developments in the legislative, regulatory, and competitive environments in which Allegheny operates, including regulatory proceedings affecting rates charged by AE's subsidiaries; developments relating to the proposed merger of AE with DQE, Inc., including expenses that may be incurred in litigation; federal and state regulatory developments and changes in law which may have a substantial adverse impact on the value of the assets within the Allegheny system; timing and adequacy of rate relief; adverse changes in electric load and customer growth; climatic changes or unexpected changes in weather patterns; changing fuel prices; generating plant and distribution facility performance, including unscheduled maintenance or repair requirements; and other circumstances that could affect anticipated revenues and costs, such as significant volatility in the market prices of wholesale and retail power.
PROPOSED MERGER WITH DQE, INC.
On April 7, 1997, AE and DQE, Inc. (DQE) announced that they had entered into an Agreement and Plan of Merger dated April 5, 1997 (Merger Agreement). The Merger Agreement provided for the business combination of AE and DQE and was contingent upon the approval of each company's shareholders and state and federal regulators. At separate meetings held on August 7, 1997, the shareholders of AE and DQE approved the merger. AE and DQE made all necessary regulatory filings. Since then, AE and DQE received approval from the Nuclear Regulatory Commission, the Pennsylvania Public Utility Commission (Pennsylvania PUC) and the Federal Energy Regulatory Commission (FERC). The Pennsylvania PUC and FERC approvals are subject to certain conditions that are acceptable to AE. The Maryland Public Service Commission (Maryland PSC) and the Ohio Public Utilities Commission (Ohio PUC) have also indicated their approval of the merger.
In a letter to AE dated October 5, 1998, DQE stated that it had decided to unilaterally terminate the merger. In response, on October 5, 1998, AE filed a lawsuit in the United States District Court for the Western District of Pennsylvania against DQE for specific performance of the Merger Agreement or, in the alternative, for damages. AE also filed motions for a temporary restraining order and preliminary injunction against DQE. On October 28, 1998, the court denied AE's motions for a temporary restraining order and preliminary injunction. On October 30, 1998, AE appealed the District Court's order to the United States Court of Appeals for the Third Circuit. On March 11, 1999, the U.S. Court of Appeals for the Third Circuit vacated the district court's denial of Allegheny's motion for preliminary injunction, enjoining DQE from taking actions prohibited by the merger agreement. The Circuit Court stated that if DQE breached the Merger Agreement, AE would be entitled to specific performance of the Merger Agreement. The Circuit Court also stated that AE would be irreparably harmed if DQE took actions that would prevent AE from receiving the specific performance remedy. The Circuit Court remanded the case to the District Court for further proceedings consistent with its opinion.
In the District Court, discovery is ongoing, and AE cannot predict the outcome of this litigation. However, AE believes that DQE's basis for seeking to terminate the merger is without merit. Accordingly, AE continues to seek the remaining regulatory approvals from the Department of Justice and the Securities and Exchange Commission. It is not likely either agency will act on the requests unless AE obtains judicial relief requiring DQE to move forward.
COMPETITION
The electric supply portion of the electric utility industry in the United States is in the midst of becoming competitive. The Energy Policy Act of 1992 (EPACT) began the process by deregulating wholesale power sales within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers
over their transmission systems on a non-discriminatory basis. Since 1992, wholesale electricity markets have become increasingly competitive as companies began to engage in nationwide power marketing. In addition, some states have taken active steps toward allowing retail customers the right to choose their electric supplier.
Activities at the Federal Level
Allegheny has been an advocate of federal legislation to mandate competition in retail electricity markets nationwide to avoid regional dislocations and ensure level playing fields. The Operating Subsidiaries continue to participate in the Partnership for Customer Choice to seek enactment of federal legislation to bring choice to all retail electric customers, deregulate the generation and sale of electricity on a national level, and create a more liquid, free market for electric power. Fully meeting challenges in the emerging competitive environment will be difficult for Allegheny unless certain outmoded and anti- competitive laws, specifically the Public Utility Holding Company Act of 1935 (PUHCA) and Section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA), are repealed or significantly revised. Allegheny continues to advocate the repeal of PUHCA and PURPA, on the grounds that they are obsolete and anti-competitive, and that PURPA results in utility customers paying above-market prices for power. (See ITEM 3. LEGAL PROCEEDINGS for information concerning PURPA-related litigation.)
Activities at the State Level
In the absence of federal legislation, state-by-state implementation has begun. All of the states the Operating Subsidiaries serve are at various stages of implementation or investigation of programs that allow customers to choose their electric supplier. Pennsylvania is furthest along with a program in place, while Maryland and Virginia are moving to adopt plans in 1999 to implement retail choice. Ohio and West Virginia continue to study this issue.
Pennsylvania
The Customer Choice Act in Pennsylvania provides for customer choice of electric supplier and deregulation of generation in a competitive electric supply market. Pursuant to the Customer Choice Act, all electric utilities in Pennsylvania were required to establish and administer retail customer choice of electric supply pilot programs to 5% of the load of each class of their customer base. In order to assure participation in the pilot program, a credit was established by the Pennsylvania PUC. The credit for West Penn's customers participating in the pilot was artificially high, and resulted in West Penn's suffering a net loss of revenues of approximately $6.5 million for the total pilot period that ended December 31, 1998. In order to mitigate pilot losses, West Penn took action to become a licensed electric supplier to the pilot customers of the other electric utilities in Pennsylvania. However, sale prices were low and margins were commensurately thin. As a result, West Penn was unable to completely offset its pilot
losses with new revenues.<1> West Penn has authorization from the Pennsylvania PUC to seek recovery of this lost pilot revenue, and intends to do so in 1999.
Beginning in January 1999, two-thirds of West Penn's customer load was permitted to choose an alternate electric supplier. All of West Penn's customer load can choose an electric supplier beginning in January 2000. (See ITEM 1. RATE MATTERS for a discussion of the settlement agreement reached with the Pennsylvania PUC, which included recovery of transition costs and the ability to transfer generating assets to an affiliate at net book value.) One result of the Customer Choice Act was the bifurcation of West Penn's electricity supply and electricity delivery functions into two separate businesses. The transmission and distribution business remains under the traditional regulated ratemaking. As it is deregulated, the electric supply business pricing will be determined by the marketplace. The delivery business in Pennsylvania has responsibility as the electricity provider of last resort (for those customers of West Penn who choose not to select an alternate supplier or whose alternate supplier does not deliver) and will generally obtain necessary electric supply for this function from the market as the transition to competition is implemented. The electric supply business will be free to sell West Penn's deregulated generation in the wholesale and retail markets, subject to codes of conduct, and subject to the restriction that it may not, except under certain conditions, sell at retail in West Penn's service territory through the year 2003.
Maryland
The Maryland PSC, in December 1997, issued an order to implement retail competition in that state. The Maryland PSC's order and its revised second order call for a deregulation process, including a three-year phase-in beginning July 1, 2000, with recovery of prudent transition costs after mitigation. The orders recognized that many details were yet to be decided and called for roundtable discussions and adjudicatory proceedings for that purpose. On September 10, 1998, the Maryland PSC issued a third order that clarified certain issues and questions involved with the earlier orders. The main roundtable created by the orders has been meeting since April 1998. This roundtable formed six working groups to study various issues involved with restructuring the electric industry. Each of the working groups submitted their interim reports to the Maryland PSC on November 1, 1998. The roundtable's final report to the Maryland PSC is due May 1, 1999, and the PSC's final order in connection with the work of the roundtable is due August 1, 1999. Potomac Edison and other Maryland utilities appealed the Commission's orders on the grounds that the PSC did not have sufficient authority to implement its plan absent authorizing legislation. In a settlement of the appeal approved by the court, the Maryland PSC agreed that
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<1> In 1997, Allegheny formed Allegheny Energy Solutions, which also participated as a licensed electric supplier in the Pennsylvania pilot program in all electric utility service areas within Pennsylvania using electric energy purchased from the competitive wholesale market. (See p. 9 in ITEM 1. COMPETITION for a discussion of which part of the new corporate structure will be participating in the deregulated retail energy markets beginning in 1999.)
its orders in this case were not final and the utilities withdrew their appeal. Authorizing legislation has been introduced in the 1999 session of the Maryland legislature that would permit the Maryland PSC to implement its customer choice plan.
Two adjudicatory proceedings were established by the Maryland PSC to aid in its implementation of retail competition, one dealing with stranded cost quantification and recovery mechanisms, price protection and unbundled rates and the other with market power protective measures. Potomac Edison filed testimony in the stranded cost proceeding on July 1, 1998. The other parties filed testimony in mid-December and hearings are scheduled to begin April 26, 1999. The parties are informally exploring the possibility of settling this case subject to the Maryland legislature passing necessary enabling legislation this year.
Virginia
In February 1998, the Virginia General Assembly passed Senate Joint Resolution 91 (SJR 91), which established a subcommittee of the General Assembly to study electric utility restructuring. The SJR 91 Subcommittee met throughout 1998 and developed detailed restructuring legislation, which was introduced in the 1999 session. The legislation would implement a transition to choice for all Virginia electric customers beginning in 2002. It allows for stranded and transition cost recovery, and caps rates for retail customers during the transition period. A separate Tax Task Force examined tax issues arising from proposed restructuring and also introduced legislation in the 1999 session. Both the restructuring and tax bills passed the House and Senate in February and are awaiting the Governor's signature.
The Virginia State Corporation Commission (Virginia SCC) issued an order in 1998 that required Virginia Power and American Electric Power Company, Inc., to develop and submit retail pilot programs for customer choice. While Potomac Edison was not required to develop a pilot for its customers in Virginia, Potomac Edison is participating in the development of those programs through pilot task forces established by the Virginia SCC. The Virginia SCC also issued an order in 1998 requiring Virginia utilities to submit monthly reports on the progress of any Independent System Operator (ISO) discussions in which the utilities are involved. Potomac Edison has reported on AE's participation in certain activities related to the Midwest ISO. AE's membership in the Midwest ISO is contingent upon its merger with DQE. Virginia's ISO reporting obligation is ongoing.
By Order dated December 3, 1998, the Virginia SCC established a proceeding to adopt interim rules to govern issues common to both the natural gas and electricity restructuring retail access pilot programs ordered in other cases, specifically the issues of certification, code of conduct, and standards of conduct governing relationships among entities participating in pilot programs. The Task Force created in connection with this proceeding began meeting in early 1999 to consider proposed rules and issued its final report to the Commission in March 1999.
West Virginia
In December 1996, the Public Service Commission of West Virginia (West Virginia PSC) issued an order initiating a general investigation regarding the restructuring of the electric utility industry. A Task Force was established to further investigate restructuring issues. In December 1997, the Task Force approved legislative language that would have given the West Virginia PSC broad authority to implement retail choice. The proposed legislation was substantially modified by the West Virginia Legislature and passed in March 1998. The legislation directed the West Virginia PSC to meet with all interested parties to develop a restructuring plan, which plan would meet the dictates and goals of the legislation. Interested parties formed a new Task Force that met during 1998, but the Task Force was unable to reach a consensus on a model for restructuring. The Task Force anticipates reconvening in 1999 to further discuss restructuring. The Commission has since issued an order setting a schedule for a series of hearings in 1999 on major issues such as transition costs, codes of conduct, and customer protections.
Ohio
In 1998, the Ohio PUC continued informal roundtable discussions on issues concerning competition in the electric utility industry. Several bills on restructuring and deregulation were introduced in the Ohio Legislature and were the subject of numerous hearings and negotiations at the committee level but no consensus was achieved. In early 1999, a group of legislators began closed door discussions to develop a restructuring plan to be introduced in the 1999 session. The legislators intend to reveal their plan in March 1999.
Allegheny over the past several years has taken steps to better position itself to participate in the new competitive markets. These include AYP Capital (AE's nonutility subsidiary) forming two subsidiaries in 1996: AYP Energy and ACC. In addition, in 1997 AYP Capital formed Allegheny Energy Solutions. AYP Energy is a bulk power marketer. In October 1996, AYP Energy purchased a 50% interest (276 MW) in Unit No. 1 of the Fort Martin coal-fired power station in West Virginia. 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. AYP Energy's losses in 1998 resulted primarily from low selling prices in competitive markets and marketing losses. (For a discussion of the losses, see ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Earnings Summary.) 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. 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 has risk management policies and procedures, consistent with industry practice and its goals. (See also discussion in Note N to the Consolidated Financial Statements in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.)
During 1998, 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 committed to invest up to $5 million in EnviroTech over 10 years, beginning in 1995. AYP Capital also participates 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 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. For example, AYP Capital offers engineering consulting services and project management for transmission and distribution facilities.
In 1997, ACC, an exempt telecommunications company, formed a limited liability company with Hyperion Communications of Pennsylvania, Inc., known as Allegheny Hyperion Telecommunications, L.L.C. Allegheny Hyperion Telecommunications began operations in the Altoona and State College markets in October of 1998. Allegheny Hyperion Telecommunications offers a full range of telecommunications services, including high- capacity dedicated telecommunications services between business and commercial locations; services connecting business locations with long-distance carriers; and local telephone service.
In August 1998, ACC and AEP Communications, LLC, a subsidiary of American Electric Power Company, Inc., announced plans to connect and jointly market their fiber optic networks in West Virginia, providing the state with increased access to high- speed, broadband communications services. Through this venture, the companies will provide high-speed communications services to several West Virginia cities. In November 1998, ACC and AEP Communications, LLC, widened their agreement to include the fiber optic networks of First Energy Telcom Corp. and GPU Telcom Services, Inc.
Allegheny Energy Solutions was formed in 1997 to market electric energy to retail customers in deregulated retail markets and to participate in the Pennsylvania pilot as an alternate supplier to customers with choice within and outside the West Penn service area, using electricity it purchased from the competitive wholesale market. The limited liability company formed between Allegheny Energy Solutions and DQE Energy Partners, Inc. to participate in the Pennsylvania pilot will no longer participate. (For a discussion of the activities undertaken by Allegheny Energy Solutions in 1998 and related nonutility losses, see ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Earnings Summary.) Because of organizational efficiencies gained by using an alternate corporate structure, Allegheny Energy Solutions will not compete in deregulated retail energy markets beyond 1998. Rather, that role will be assumed by the deregulated supply function of West Penn, acting under the name of Allegheny Energy Supply. Allegheny Energy Supply has gained several
hundred megawatts of load for 1999 through Pennsylvania customers' choice of Allegheny Energy Supply as their new supplier of generation services.
OPERATING SUBSIDIARIES' SALES
In 1998, consolidated regulated kilowatt-hour (kWh) sales to regular customers (retail and wholesale power) increased 2.8% from those of 1997 as a result of increases of .8%, 5.5% and 3.3% in residential, commercial and industrial sales, respectively. Consolidated regulated revenues from residential sales decreased 1.4%, while commercial and industrial sales increased 2.2% and .8%, respectively. (See ITEM 1. RATE MATTERS and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.)
Allegheny's all-time combined generation customer peak load of 7,500 MW occurred on February 5, 1996. The control area peak load in 1998 was 7,314 MW on July 22, 1998.
Consolidated regulated electric operating revenues for 1998 were derived as follows: Pennsylvania, 44.4%; West Virginia, 27.9%; Maryland, 19.2%; Virginia, 6.1%; Ohio, 2.4% (residential, 37.8%; commercial, 21.5%; industrial, 32.3%; bulk power transactions, 4.9%; and other, 3.5%). The following percentages of such revenues were derived from these industries: iron and steel, 6.5%; aluminum and other nonferrous metals, 3.4%; chemicals, 3.4%; coal mines, 3.3%; cement, 2.6%; fabricated products, 1.8%; and all other industries, 11.4%.
During 1998, Monongahela's kWh sales to retail customers increased 3.9%. Residential sales decreased .3% but commercial and industrial sales increased 5.8% and 5.5%, respectively. Revenues from residential, commercial, and industrial customers increased .5%, 6.4%, and 6.0%, respectively, primarily due to an increase in the fuel and energy cost component as well as an increase in the number of customers and usage. Revenues from bulk power transactions and sales to affiliates decreased 3.8%. Monongahela's revenues represented 24.7% of Allegheny's total regulated sales to regular customers. Monongahela's all-time peak load of 1,844 MW occurred on July 21, 1998.
Monongahela's electric operating revenues were derived as follows: West Virginia, 91.2%, and Ohio, 8.8% (residential, 31.1%; commercial, 19.6%; industrial, 32.3%; bulk power transactions, 3.1%; and other, 13.9%).
During 1998, Potomac Edison's kWh sales to retail customers increased 5.0%. Residential, commercial and industrial sales increased 2.6%, 7.2% and 5.9%, respectively. Revenues from residential, commercial and industrial customers increased 3.1%, 5.9% and 4.3%, respectively, primarily due to an increase in the number of customers and usage. Revenues from bulk power transactions and sales to affiliates increased 7.6%. Potomac Edison's revenues represented 31.9% of Allegheny's total regulated sales to regular customers. Potomac Edison's all-time peak load of 2,614 MW occurred on January 17, 1997. The peak load in 1998 was 2,413 MW on July 22, 1998.
Potomac Edison's electric operating revenues were derived as follows: Maryland, 61.9%; West Virginia 19.0%, and Virginia, 19.1%; (residential, 41.9%; commercial, 21.3%; industrial, 28.0%; bulk power transactions, 3.6%; and other, 5.2%). Revenues from one industrial customer, the Eastalco aluminum reduction plant near Frederick, Maryland, amounted to $64.8 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 $15.1 million in 1998. This agreement may be canceled before the year 2000 upon 90 days' notice in the event of a governmental decision resulting in a material modification of the agreement.
During 1998, West Penn's kWh sales to retail customers, including sales to Pennsylvania retail pilot participants, decreased 2.8% as a result of decreases of 4.6%, 1.6% and 2.2% in residential, commercial, and industrial sales, respectively. Revenues from residential, commercial and industrial customers decreased 5.7%, 2.4%, and 4.1%, respectively, primarily due to a $25.1 million rate refund resulting from the Pennsylvania restructuring settlement agreement, a reduction in previously bundled customers (full service customers) due to the Pennsylvania retail pilot program, and a reduction in usage. Revenues from bulk power transactions and sales to affiliates, including bulk power sales under the Pennsylvania retail pilot program, increased 43.3%. West Penn's regulated revenues represented 43.4% of Allegheny's total regulated sales to regular customers. West Penn's all-time peak load of 3,251 MW occurred on July 15, 1997. The regulated peak load in 1998 was 3,067 MW on June 25, 1998. The territorial West Penn share of the Allegheny control area peak load in 1998 was 3,192 MW on June 25, 1998.
West Penn's electric operating revenues were derived as follows: Pennsylvania, 100% (residential, 34.4%; commercial, 20.2%; industrial, 31.4%; bulk power transactions, 6.4%; and other, 7.6%).
In 1998, the Operating Subsidiaries provided approximately 3.0 billion kWh of energy to nonaffiliated companies and marketers from generation facilities operated by the Operating Subsidiaries. Revenues from those sales of generation, including Pennsylvania retail pilot sales, from the Operating Subsidiaries were approximately $69.8 million.
The Operating Subsidiaries transmitted approximately 7.4 billion kWh to others located outside their service territories under various forms of transmission service agreements. Revenues from those sales were about $45.2 million.
Sales of generation and transmission services to others vary with the needs of those customers 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. Revenues from sales of transmission services to others by the Operating Subsidiaries increased in 1998 relative to 1997 despite decreased transmission services activity. The increase in revenues was due in part to transmission services' reservation charges paid to the Operating Subsidiaries by others for the right to transmit energy. Transmission activity was affected as a result of some of the reservations to transmit
energy not being used. Sales of power generated by the Operating Subsidiaries increased in 1998 relative to 1997 primarily from increased sales to brokers and power marketers due to increased sales that occurred primarily in the second quarter as a result of warm weather which increased the demand and price for energy, and increased sales due to participation in the Pennsylvania retail pilot program. Substantially all of the benefits of power and transmission service sales to nonaffiliates by the Operating Subsidiaries, except West Penn, were passed on to retail customers and, as a result, had little effect on Monongahela Power's and Potomac Edison's net income. Effective May 1, 1997, West Penn no longer passes these benefits on to retail customers.
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 usually during each December, January, and February, at least through February 2000. Beyond February 2000, no diversity exchange is planned.
The Operating Subsidiaries have an exchange arrangement with Duquesne Light Company (Duquesne) which will continue through February 2000. In this exchange arrangement, the Operating Subsidiaries have, in the past, supplied 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 had supplied the Operating Subsidiaries with up to 100 MW, generally during each December, January, and February. Currently, there are no exchanges being made as Duquesne endeavors to sell off its generating assets. The total number of MWh to be delivered by each utility to the other over the active term of the arrangement will have been the same.
Regulatory Framework Affecting Power Sales
EPACT initiated the restructuring of the electric utility industry by permitting competition in the wholesale generation market. In order to facilitate the efficient use of generation facilities, on April 24, 1996, the FERC issued Orders 888 and 889. On March 4, 1997, the FERC issued Orders 888A and 889A reaffirming and clarifying the legal and policy issues as originally presented in the previous orders. In response to requests for rehearing, the FERC issued Orders 888B and 889B on November 25, 1997. The Commission again supported its original intentions and presented explanations and minor revisions to specific sections of the orders.
The FERC orders require all transmission providers to offer service to entities selling generation services in a manner that is comparable to their own use of the transmission system. The orders required each transmission provider to file standardized open access transmission service tariffs; therefore, the Operating Subsidiaries have on file a pro forma open access tariff under which they sell transmission services to all eligible customers. The Operating Subsidiaries (and AYP Energy, when appropriate) also arrange for transmission services for their own sales pursuant to the rates, terms, and conditions of the open access tariff. The tariff was accepted for filing by the FERC on November 25, 1998. The Commission's order specified a December 6, 1995, effective date and required refunds to be paid on the time
value of money based upon the difference between the originally filed rates and those authorized by the Commission.
To meet the objective of providing comparable or nondiscriminatory transmission services, the FERC orders further require that utilities functionally unbundle transmission operations and reliability functions from wholesale merchant functions within the Operating Subsidiaries. Accordingly, discrete businesses have been formed, including a Delivery Business Unit (inclusive of transmission) and a Supply Business Unit. The Delivery Business Unit includes several sub-units, including the System Planning and Operations group, which provides transmission system operations and reliability functions. Each unit has its own management, objectives, and facilities. The Operating Subsidiaries conduct their business in a manner that is consistent with FERC's Standards of Conduct.
The orders require that all transmission requests for service be made over the Open Access Same Time Information System (OASIS). The OASIS, an internet-based nationwide electronic network, became operational on January 3, 1997. The Operating Subsidiaries, in conjunction with a consortium of transmission providers, continue to work to implement a revised version of the OASIS Standards and Communications Protocols document issued by FERC. OASIS Phase 1A will become operational on March 1, 1999.
The FERC established its jurisdiction over unbundled retail as well as wholesale transmission services in Order 888. Although states retain the authority to determine if retail wheeling should be adopted, retail transmission service under the jurisdiction of the FERC is available once these historically franchised customers have access to alternate generation sources. Pennsylvania enacted legislation authorizing retail choice for selected customers as of November 1, 1997 (Customer Choice Act). The Operating Subsidiaries added Schedule 10--Retail Transmission Service to their open access tariff authorizing the sale of open access transmission services to unbundled retail customers. Initially, the Operating Subsidiaries will provide service to Pennsylvania's unbundled retail customers and eventually to retail customers with choice in Maryland, Virginia, West Virginia, and Ohio.
In compliance with Pennsylvania's restructuring requirements and in conjunction with the merger plans, AE and DQE filed jointly with the FERC an Allegheny Energy open access tariff in August 1997. No sales have been made under that tariff and none will be made until the merger is consummated.
The Operating Subsidiaries also have on file with the FERC a Standard Generation Service Rate Schedule for the sale of wholesale power at cost-based rates. In October 1997, the Operating Subsidiaries submitted a new wholesale tariff to the FERC, asking for authority to sell power at market-based rates. The Operating Subsidiaries began selling power at market-based rates upon the filing's acceptance by the FERC in August 1998.
The Operating Subsidiaries continue their involvement as General Agreement on Parallel Paths (GAPP) experiment participants. The purpose of the experiment is to collect operating data on the effect of parallel power flow on the interconnected transmission system and to develop an equitable
compensation system reapportioning current contract path-based revenues upon a reflection of the actual flow of power on the interconnected electrical system. During the two-year term of the experiment, many of the GAPP principles were successfully incorporated into certain industry-wide system operating practices established by the North American Electric Reliability Council (NERC). When the experiment concludes on March 31, 1999, the participants will publicly present information on the revenue reallocation method they developed.
AE and DQE, Inc., conditionally executed a membership agreement with the Midwest ISO; the commitment to join the Midwest ISO was expressly contingent upon consummation of a proposed merger between AE and DQE, Inc. The membership agreement was entered into on April 9, 1998, and filed with the FERC on April 13, 1998. AE's membership status remains conditional until the merger is consummated or it is determined that the Merger Agreement is terminated.
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 consistent with PURPA and ordered by appropriate state commissions. As a result of PURPA, the Operating Subsidiaries are committed to purchasing 299 MW of on- line PURPA capacity. Payments for PURPA capacity and energy in 1998 totaled approximately $129.0 million, at an average cost to the Operating Subsidiaries of 5.4 cents/kWh, as compared to the Operating Subsidiaries' own generating cost of about 3 cents/kWh. The Operating Subsidiaries project an additional 180 MW of PURPA capacity (Warrior Run) to come on-line in 1999. The Warrior Run project will result in rate increases for Potomac Edison's Maryland customers pursuant to a 1998 rate case settlement in that jurisdiction. (See ITEM 3. LEGAL PROCEEDINGS for a description of litigation and regulatory proceedings in Pennsylvania and West Virginia concerning other proposed PURPA projects.)
OTHER SUBSIDIARIES' SALES
In 1998, AYP Energy provided 7.3 billion kWh of energy to nonaffiliated customers, including generation from Fort Martin Unit No. 1, amounting to 1.8 billion kWh. Revenues from those sales were approximately $215.3 million. Total unregulated operating revenues in 1998, including sales by Allegheny Energy Solutions under the Pennsylvania retail pilot program, amounted to $247.0 million. Allegheny Energy Solutions participated in the pilot program as an alternate supplier to customers with choice within and outside the West Penn service area. (For a discussion of increases in nonutility losses in 1998, See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Earnings Summary.)
ELECTRIC FACILITIES
The following table shows Allegheny's December 31, 1998, operational generating capacity based on the maximum monthly normal seasonal operating capacity of each unit. The Regulated Subsidiaries' owned capacity totaled 8,121 MW, of which 7,091 MW (87%) are coal-fired, 840 MW (10%) are pumped-storage, 132 MW (2%) are oil-fired, and 58 MW (1%) are hydroelectric. AYP Energy, an exempt wholesale generator in 1998, also owns 276 MW of coal-fired generation. The term "pumped-storage" refers to the Bath County station which stores energy for use principally during peak load hours by pumping water from a lower to an upper reservoir, using the most economic available electricity, generally during off-peak hours. During the generating cycle, power is produced by water falling from the upper to the lower reservoir through turbine generators.
The weighted average age of the Regulated Subsidiaries' owned steam stations shown on the following page is about 28.6 years. In 1998, their book value was $1.8 billion, average heat rate was 9,939 Btu's/kWh, and their availability factor was 85.8%. The age of AYP Energy's owned generation is 32.0 years. In 1998, the book value of AYP Energy's owned generation was $163.5 million, average heat rate was 9,622 Btu's/kWh, and the availability factor was 88.9%.
Allegheny Stations Maximum Generating Capacity (Megawatts) (a) AYP Dates When Station Monon- Potomac West Energy Service Station Units Total gahela Edison Penn (b) Commenced(c)
Coal-fired (steam): Albright 3 292 216 76 1952-4 Armstrong 2 352 352 1958-9 Fort Martin 2 1,107 249 304 278 276 1967-8 Harrison 3 1,920 480 629 811 1972-4 Hatfield's Ferry 3 1,660 456 332 872 1969-71 Mitchell 1 284 284 1963 Pleasants 2 1,252 313 376 563 1979-80 Rivesville 2 142 142 1943-51 R. Paul Smith 2 115 115 1947-58 Willow Island 2 243 243 1949-60 Oil-fired (steam): (a) Mitchell 2 132 132 1948 Pumped-storage and Hydro: Bath County 6 840 227(d) 235(d) 378(d) 1985 Lake Lynn(e) 4 52 52 1926 Potomac Edison (e) 21 6 6 Various Total Allegheny-owned Capacity 54 8,397 2,326 2,073 3,722 276
Other Generation Maximum Generating Capacity (Megawatts) (f)
AYP Contract Project Monon- Potomac West Energy Commencement Project Total gahela Edison Penn (b) Date Coal-fired: (steam) AES Beaver Valley 125 125 1987 Grant Town 80 80 1993 West Virginia University 50 50 1992
Hydro: Allegheny Lock and Dam 5 6 6 1988 Allegheny Lock and Dam 6 7 7 1989 Hannibal Lock and Dam 31 31 1988
Total Other Capacity 299 161 0(g) 138 0
Total Allegheny-owned and PURPA Committed 8,696 2,487 2,073 3,860 276 Generating Capacity (a)
(a) Winter rating. Excludes West Penn oil-fired capacity of 207 MW at Springdale Power Station which was placed on cold reserve status as of June 1, 1983. On December 31, 1994, 82 MW, and on July 1, 1998, 50 MW of the total MW at Mitchell Power Station were reactivated.
(b) AYP Energy owns 50% of Unit No. 1 at Fort Martin.
(c) 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.
(d) Capacity entitlement through ownership of AGC, 27%, 28%, and 45% by Monongahela, Potomac Edison, and West Penn, respectively.
(e) 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.
(f) Other generating capacity available through state utility commission-approved arrangements pursuant to PURPA.
(g) The 180-MW Warrior Run project is under construction and is planned to begin providing capacity and energy to Potomac Edison in 1999.
ALLEGHENY 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 Maryland, Ohio, Pennsylvania, Virginia, and West 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 capacity from 138 kV to 765 kV. Additionally, interconnections with other utilities are displayed.
The following table sets forth the existing miles of tower and pole transmission and distribution lines and the number of substations of the Regulated Subsidiaries as of December 31, 1998:
Miles of Above-Ground Transmission and Distribution Lines (a) and Number of Substations
Number of Portion of Total Transmission and Total Miles Representing Distribution Miles 500-Kilovolt (kV) Lines Substations(b)
Monongahela 21,035 283 331 Potomac Edison 18,135 202 276 West Penn 24,102 273 709 AGC(c) 85 85 1 Total 63,272 843 1,317
(a) The Operating Subsidiaries also have a total of 6,412 miles of underground distribution lines.
(b) The substations have an aggregate transformer capacity of 56,317,204 kilovoltamperes.
(c) Total Bath County transmission lines, of which AGC owns an undivided 40% interest and Virginia Power owns the remainder.
The Operating Subsidiaries have 12 extra-high-voltage (EHV), 345-kV and above, and 31 lower-voltage interconnections with neighboring utility systems. The interregional EHV transmission system, including System facilities, continued to operate near reliability limits during periods of heavy power flows that are predominantly in a west-to-east orientation. In early 1997, NERC implemented the development of a national security process. The Operating Subsidiaries serve as one of the 22 national Security Coordinators. This process includes a Transmission Loading Relief (TLR) procedure that identifies actual flow path consequences of power transactions, reduces loading on the transmission system when necessary and effectively addresses parallel path flows. The TLR procedure has been effective. Its use, and conditions in the Midwest that reversed the predominant west-to-east power flow pattern across the AE system during the summer of 1998, resulted in fewer constraints on System transmission facilities that would require curtailments of transmission service.
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 the Operating Subsidiaries' transmission facilities may add to heavy power flows on the Operating Subsidiaries' facilities and may, eventually, require construction of additional transmission facilities.
The Operating Subsidiaries have, since the early 1980s, provided managed contractual access to their transmission facilities under various tariffs. As described earlier, for new agreements starting in 1996, managed access is also governed by the provisions of the Operating Subsidiaries' Open Access Transmission Tariff mandated by and filed with the FERC.
RESEARCH AND DEVELOPMENT
The Operating Subsidiaries spent $7.9 million, $7.4 million, and $7.7 million, in 1998, 1997, and 1996, respectively, for research programs. Of these amounts, $5.5 million, $5.7 million, and $5.5 million were for Electric Power Research Institute (EPRI) dues in 1998, 1997, and 1996, respectively. EPRI is an industry-sponsored research and development institution. The Operating Subsidiaries plan to spend approximately $7.8 million for research in 1999, with EPRI dues representing $5.6 million of that total.
In addition to EPRI support, in-house research conducted by Allegheny concentrated on environmental protection, generating unit performance, future generation technologies, transmission system performance, delivery systems, customer- related research, clean power technology focused on power quality, and distributed resources technology for customers, delivery equipment, and marketing. All Allegheny-funded research is related to adapting both competitive and leading edge technology to Allegheny'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 (GHG), renewable resources, fuel cells, new combustion turbines, cogeneration technologies, and transmission loading mitigation using Flexible AC Transmission System (FACTS) devices. An investigation of the value of biodiversity of lands owned by Allegheny is being done. The financial effect of these issues on Allegheny, if any, cannot be determined at this time. During 1998, the Operating Subsidiaries supported the federal government's National EMF Research and Public Information Dissemination Program, a project on the interaction of biomechanisms and electric and magnetic fields (EMF); and an Edison Electric Institute (EEI) program to study employee and public health effects, if any, of EMF. The World Health Organization, the Director of the National Institute of Environmental Health Services, and an interagency group consisting of representation from nine federal agencies plan to issue reports over the next two to three years on EMF, which may affect future R&D funding. 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 nitrogen oxides (NOx) control requirements of the Clean Air Act Amendments of 1990 (CAAA), Allegheny 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, including optimizing existing low NOx burners to improve performance.
The Operating Subsidiaries continue to monitor and demonstrate technical solutions to greenhouse gas (GHG) reduction, sequestration, capture, and control. As part of their response to EPACT and President Clinton's subsequent Climate Action Plan, the Operating Subsidiaries, as part of an EEI program, have agreed to participate in research initiatives which are designed to reduce, sequester, or control GHG. 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 through 1998 included participation in EV America and the Electric Transportation Coalition, as well as the development of appropriate wiring and building code standards to accommodate electric vehicles. As a result, Allegheny is positioned to support commercial manufacturers when they move forward with EV development. Allegheny provided a grant to the University of Pittsburgh to build an electric car from the frame up.
In 1998, research was also directed into communication systems to develop and demonstrate a high-speed digital power line communication system using existing utility wires to serve information and automation needs of Allegheny's customers and to support system requirements in retail wheeling and marketing.
Allegheny 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-owned 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 for a residential home demonstration and the use of flue-gas desulfurization by- products for road building.
As part of customer research, a model home program is under way and adjustable speed drives for customer motor loads are being used at a steel company and at an extrusion process plant. West Penn participated in 1998 in the Pennsylvania Electric Energy Research Council (PEERC). PEERC was formed in 1987 as a partnership of Pennsylvania-based electric utilities and the State of Pennsylvania to promote technological advancements related to the electric utility industry.
In 1998, 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 and to conduct
research. A grant was provided to West Virginia University to evaluate the effect of Distributed Resources on feeders and for customer uses.
CAPITAL REQUIREMENTS AND FINANCING
Construction expenditures by the Regulated Subsidiaries in 1998 amounted to $229.4 million. Construction expenditures for 1999 and 2000 are expected to aggregate $280.1 million and $283.6 million, respectively. Construction expenditures by AYP Capital, the wholly owned nonutility (unregulated) subsidiary of AE, in 1998 amounted to $1.8 million and for 1999 and 2000 are expected to aggregate $34.9 million and $10.6 million, respectively. The 1999 and 2000 estimated regulated expenditures include $10.6 million and $55.7 million, respectively, to cover the costs of compliance with the CAAA. Expenditures to cover the costs of compliance with the CAAA and other environmental requirements have been and are likely to continue to be significant. Additionally, new environmental initiatives (See ITEM 1. ENVIRONMENTAL MATTERS) may substantially increase Allegheny's construction requirements as early as 2000.
On October 27, 1998, the EPA finalized rules for reducing ground level ozone. The EPA is requiring 22 states and the District of Columbia to submit state implementation plans (SIPs) that address the regional transport of ozone. All of the states served by Allegheny are required to submit the SIP call. The intent of the SIP call is to reduce NOx emissions from power plants, on average, to 0.15 pounds of NOx per million BTU (MBTU). Although Allegheny has joined with other parties to contest the EPA's actions in court, it is also formulating plans to comply by making modifications to existing generating units. The cost to comply will be about $360 million of capital investments, to be spent during the 1999-2003 period. Of this amount, about $50 million was already scheduled to be spent, so an additional $310 million of capital will be required. Under the EPA's plan, Allegheny would be required to reduce emissions to the 0.15 pounds per MBTU requirement by May 2003.
Construction Expenditures
1998 1999 2000
Millions of Dollars (Actual) (Estimated) Monongahela Generation $ 25.5 $ 26.1 $ 26.9 Transmission 7.6 11.2 4.6 Distribution 39.7 38.4 47.7 Total* $ 72.8 $ 75.7 $ 79.2
Potomac Edison Generation $ 15.4 $ 31.2 $ 29.9 Transmission 0.9 2.1 13.8 Distribution 44.2 52.3 54.4 Total* $ 60.5 $ 85.6 $ 98.1
West Penn Generation $ 34.2 $ 58.8 $ 54.8 Transmission 10.2 2.3 4.2 Distribution 49.2 54.2 46.3 Other 2.4 3.4 .7 Total* $ 96.0 $ 118.7 $ 106.0
AGC & APSC $ .1 $ 0.1 $ 0.3
Total Construction Expenditures, $ 229.4 $ 280.1 $ 283.6 Regulated
Nonutility $ 1.8 $ 34.9 $ 10.6
Total Construction Expenditures $ 231.2** $ 315.0** $ 294.2**
*Includes allowance for funds used during construction (AFUDC), or capitalized interest in the case of the generation business of West Penn, for 1998, 1999, and 2000 of: Monongahela $1.0, $1.7, and $1.3; Potomac Edison $1.6, $1.8, and $1.5; and West Penn $2.4, $3.5, and $2.7.
**Includes amounts for projects connected with Allegheny's corporate restructuring of $17.9, $5.9, and $0.0 for 1998, 1999, and 2000, respectively.
These capital expenditures include major projects at existing generating stations, upgrading distribution lines and substations, and the strengthening of the transmission and subtransmission systems.
On a collective basis for the Regulated Subsidiaries, expenditures for 1998, 1999, and 2000 include $12.8 million, $62.8 million, and $84.9 million, respectively, for construction of currently mandated environmental control technology. Outages for construction, CAAA compliance, and other environmental work is, and will continue to be, coordinated with other planned outages, where possible.
Allegheny continues to study ways to reduce and meet existing regulated customer generation service demand and future increases in that demand, including 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 generating facilities; reducing internal electrical use and transmission and distribution losses; and acquisition of energy and capacity from third-party suppliers. The advent of retail choice of generation service supplier is expected to have a significant effect on regulated generation service load growth and the Operating Subsidiaries' obligation to meet such load growth.
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 for the regulated load of Monongahela and Potomac Edison and the provider of last resort load of West Penn of 0.7% and 0.6%, respectively, in the period 1999-2009. Competition for existing loads can have a substantial effect on those projections. It is anticipated that existing resources, purchased power arrangements, reactivation of existing capacity, and/or the acquisition of capacity will be sufficient for Allegheny's future needs.
In connection with its construction and demand-side management programs, Allegheny must make estimates of the availability and cost of capital as well as the future demands of its customers that are necessarily subject to regional, national, and international developments, changing business conditions, and other factors. The construction of facilities and their cost are affected by laws and regulations; lead times in manufacturing; availability of labor, materials and supplies; inflation; interest rates; and licensing, rate, environmental, and other proceedings before regulatory authorities. Decisions regarding construction of facilities must now also take into account retail competition. As a result, future plans of Allegheny are subject to continuing review and substantial change.
Financing Programs
The Regulated 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 AE (or, in the case of AGC, by the Operating Subsidiaries), and, where necessary, interim short-term debt. The future ability of the Regulated Subsidiaries to finance their construction
programs by these means depends on many factors, including effects of competition and creditworthiness, and adequate revenues to produce satisfactory internally generated funds and return on the common equity portion of the Regulated Subsidiaries' capital structures and to support their issuance of senior and other securities. AE obtains funds for equity investments in its subsidiaries through retained earnings and the issuance and sale of its common stock publicly.
Beginning in the third quarter of 1997, AE began buying shares in the open market for its Dividend Reinvestment and Stock Purchase Plan, its Employee Stock Ownership and Savings Plan, and in 1998 AE began buying shares in the open market for the Performance Share Plan.
In February 1998, Monongahela, Potomac Edison and West Penn issued $17.5 million, $30 million, and $45 million, respectively, of 9-year and 14-year Pollution Control Revenue Notes to Pleasants County, West Virginia. Pleasants County, in turn, issued $92.5 million of 9-year and 14-year Pollution Control Revenue Bonds with interest rates ranging from 4.70% to 5.05% to refund $92.5 million of three series due in 2007 and 2012, with rates ranging from 6.125% to 6.375%.
In March 1998, Monongahela, Potomac Edison and West Penn issued $6.06 million, $3.2 million and $14.435 million, respectively, in 4-year, 9-year, and 14-year Pollution Control Revenue Notes to Greene County, Pennsylvania. Greene County, in turn, issued $23.695 million of 4-year, 9-year, and 14-year Pollution Control Revenue Bonds with interest rates ranging from 4.35% to 5.10% to refund $23.695 million of three series due in 2002, 2007, and 2012, with rates ranging from 6.1% to 6.4%.
Also in March 1998, Monongahela issued $19.1 million in 4.5% 5-year Pollution Control Revenue Notes to Marion, Pleasants, and Preston Counties, West Virginia. These counties, in turn, issued $19.1 million of 5-year Pollution Control Revenue Bonds to pay at maturity $19.1 million of three series, with rates of 6.875%.
In September 1998, Monongahela and West Penn issued an aggregate of $77.025 million of unsecured medium-term notes at interest rates ranging from 5.56% to 5.71%. Monongahela issued five-year unsecured medium-term notes totaling $43.475 million at interest rates ranging from 5.56% to 5.71%. West Penn issued four-year unsecured medium-term notes totaling $33.55 million at interest rates of 5.56% and 5.66%.
In June and October 1998, Monongahela and Potomac Edison redeemed an aggregate $115 million of First Mortgage Bonds. Monongahela exercised its right of optional redemption in June 1998 to redeem its $65 million, 8.5% Series, prior to maturity. Potomac Edison exercised its right of optional redemption in October 1998 to redeem its $50 million 8-7/8% Series, prior to maturity.
During 1998, 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 3.95%, 4.084%, 4.019%, and 4.12%. The rate set at auction on January 14, 1999, was 3.55%.
At December 31, 1998, short-term debt was outstanding in the following amounts: AE $258.8 million, AGC $66.8 million, Monongahela $49.0 million, and West Penn $65.1 million. At December 31, 1998, Potomac Edison had $76.1 million invested.
The Regulated Subsidiaries' ratios of earnings to fixed charges for the year ended December 31, 1998, were as follows: Monongahela, 4.40; Potomac Edison, 4.09; West Penn, excluding the effect of the extraordinary charge, 3.52; and AGC, 3.41.
Allegheny's consolidated capitalization ratios as of December 31, 1998, were: common equity, 46.4%; preferred stock, 3.9%; and long-term debt, 49.7%, including Quarterly Income Debt Securities (3.5%). AE's long-term objective is to maintain the common equity portion above 46%.
During 1999, Monongahela, Potomac Edison, and West Penn anticipate meeting their capital requirements through a combination of internally generated funds, cash on hand, and short-term borrowing as necessary.
However, due to the restructuring of electric generation by Pennsylvania, a special-purpose subsidiary of West Penn is expected to issue up to $670 million of bonds to securitize transition costs related to West Penn's restructuring settlement, which West Penn may use to reduce its capitalization.
FUEL SUPPLY
Allegheny stations burned approximately 17.5 million tons of coal in 1998. Of that amount, 88% was either cleaned (5.8 million tons) or used in stations equipped with scrubbers (9.6 million tons). The use of desulfurization equipment and the cleaning and blending of coal make burning local higher-sulfur coal practical. In 1998, almost 100% of the coal received at Allegheny-operated stations came from mines in West Virginia, Pennsylvania, Maryland, and Ohio. Allegheny 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 are in effect to provide for approximately 14.3 million tons of coal in 1999. The Operating Subsidiaries will depend on short-term arrangements and spot purchases for their remaining requirements. Through the year 2001, the total coal requirements of present Allegheny-operated stations are expected to be met with coal acquired under existing contracts or from known suppliers.
For each of the years 1994 through 1997, the average cost per ton of coal burned was $35.88, $32.68, $32.25, and $32.66, respectively. For the year 1998, the cost per ton decreased to $32.26.
Long-term arrangements, subject to price change, are in effect and will provide for the lime requirements of scrubbers at Allegheny'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 a discussion of research projects in ITEM 1. RESEARCH AND DEVELOPMENT.) In 1998, the Operating Subsidiaries received approximately $708,419 from the sale of 1,743,918 tons of fly ash and 387,769 tons of bottom ash for various uses, including cement replacement, mine grouting, oil well grouting, soil extenders, anti-skid material, and grit blast material.
In 1998, the Operating Subsidiaries signed an agreement with wallboard manufacturers to supply a minimum of 600,000 tons of synthetic gypsum for use in making wallboard. The Operating Subsidiaries will break ground in early 1999 to construct a processing plant which will convert the Pleasants Power Station flue gas desulfurization by-product into a commercial grade synthetic gypsum for use in manufacturing wallboard. This will reduce the amount of by-product going to landfill.
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.
RATE MATTERS
On November 19, 1998, the Pennsylvania PUC approved an agreement between West Penn and intervenors in West Penn's restructuring proceedings related to legislation in Pennsylvania to provide customer choice of electric supplier and deregulate electricity generation. (See Notes B and C to the Consolidated Financial Statements for details of the settlement agreement and other information about the deregulation process.)
Under the Customer Choice Act, all utilities were provided an opportunity to recover their transition (or stranded) costs. The determination of transition costs relied heavily on projections of future market prices of electricity. West Penn's transition cost recovery claim of $1.2 billion was the subject of significant disagreement and debate by intervenors in the restructuring proceedings, as were the transition cost claims of the other Pennsylvania utilities.
Under the settlement agreement, West Penn has been authorized to recover $670 million ($630 million if the DQE merger is consummated) of transition costs, plus a return over a ten-year period, and to record most of the income therefrom in the earlier years of the transition period when electricity market prices are assumed to be lowest. Additionally, West Penn has written off as an extraordinary item in 1998 about $467 million ($275.4 after taxes) of costs which it deemed not recoverable under the deregulation process. Of this amount, $451 million ($265.4 million after taxes) was recorded in the second quarter and $16 million ($10 million after taxes) was recorded in the fourth quarter. The settlement also provides for a rate
refund from 1998 revenue (about $25 million) via a 2.5% rate decrease throughout 1999, capped rate provisions and authorization to issue bonds to securitize up to $670 million in transition costs.
Under the terms of the settlement agreement, two-thirds of West Penn's customers were permitted to choose an alternate electric supplier beginning in January 1999. All West Penn customers can do so beginning in January 2000. (West Penn customers represent about 45% of Allegheny's electricity supply business.) They can choose to remain as a West Penn customer at West Penn's capped generation rates or to alternate back and forth. Under the law, all electric utilities, including West Penn, retain the responsibility of electricity provider of last resort (PLR) to all customers in their respective franchise territories that do not choose an alternate supplier.
Beginning in 1999, in Pennsylvania, electric supply and electric delivery will be two separate businesses. The transmission and distribution business will be under traditional regulated rate making, and the electric supply business will be deregulated with pricing determined by the market place. The transmission and distribution business will have the PLR responsibility and will generally obtain its electric supply from the market primarily by bidding, including bids from the affiliated supply business.
The settlement agreement permits the transfer of West Penn's generation assets to the unregulated supply business at West Penn's book values. The new, unregulated supply business will be free to sell, subject to a code of conduct, West Penn's deregulated generation capacity and energy in the open wholesale and retail markets, except that it is not permitted to sell at retail, except under certain conditions, in West Penn's franchise territory through the year 2003.
Current electric supply prices are below the level required to produce results of operations equal to that obtained in the regulated environment in part because, in Allegheny's opinion, of abundant generation from other states, as well as in Pennsylvania, to supply the deregulated market of Pennsylvania. Allegheny believes that the utilities in states that are not yet deregulated may now be selling and may continue to sell electricity into Pennsylvania on average at a cost which is lower than their total cost since their fixed costs are recovered from franchise customers in their home state territories.
The Pennsylvania PUC's projections of electricity market prices recognized this possibility, among others, and accordingly assumed depressed prices in the earlier years of the transition process from regulation to deregulation. The projections further assumed that prices would increase in later years due to increasing demand from deregulation in other states and normal increases in customer demand, particularly because of competition.
As stated above, West Penn made a filing concerning its transition cost requirements in Pennsylvania based on its early 1997 projection of market prices. The Pennsylvania PUC issued an order on May 29, 1998, to West Penn, as well as orders to all other Pennsylvania electric utilities in 1998, based on alternative projections. Current prices, which West Penn believes are being influenced, among other things, by price volatility in the summer of
1998, are equal to and in some cases slightly higher than the projections adopted by the Pennsylvania PUC in its deregulation orders issued to West Penn and other utilities in Pennsylvania. If the Pennsylvania PUC's projections are correct, West Penn believes that the transition costs provided will be sufficient to permit it to recover its embedded costs, with a return, during the transition from regulation to deregulation of electricity generation.
The forward-looking statements above are provided to describe Allegheny's plans and its reasoning for actions taken. Of necessity, its plans are based on assessments of future events. There can be no assurance that actual results will not materially differ from those presented. (For a discussion of West Penn's restructuring plan, see ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Significant Continuing Issues - Electric Energy Competition and Notes B and C to the Consolidated Financial Statements in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.)
After substantial negotiations, Potomac Edison reached a settlement agreement with various parties on the Office of People's Counsel's (OPC) petition for a reduction in Potomac Edison's Maryland rates. The agreement, which includes recognition and dollar-for-dollar recovery of costs to be incurred from the Warrior Run PURPA project, was filed with the Maryland PSC on July 30, 1998, and approved by that Commission on October 27, 1998. Rates to each customer class were approved by the Maryland PSC on December 22, 1998. Under the terms of the agreement, Potomac Edison will increase its rates about 4% ($13 million) in each of the years 1999, 2000, and 2001 (a $39 million annual effect in 2001). The increases are designed to recover additional costs of about $131 million, over the period 1999- 2001, for capacity purchases from the Warrior Run generation project net of alleged overearnings of $52 million for the same period absent these adjustments. The net effect of these changes over the 1999-2001 time frame results in a pre-tax income reduction of $12 million in 1999, $18 million in 2000, and $22 million in 2001. In the event the merger with DQE is consummated, an additional rate reduction of $4.4 million annually will occur, based upon expected synergy savings. In addition, the settlement requires that Potomac Edison share, on a 50% customer, 50% shareholder basis, earnings above a threshold return on equity (ROE) level of 11.4% for 1999-2001. This sharing will occur through an after-the-fact true-up conducted after each calendar year is completed. Warrior Run is a cogeneration project being built by AES Enterprise, a non- affiliated PURPA developer, in western Maryland. Potomac Edison is required to purchase the project's energy at above-market prices pursuant to the requirements of the federal PURPA law.
As required by the Maryland PSC, Potomac Edison, on July 1, 1998, filed testimony in Maryland's investigation into transition costs, price protection, and unbundled rates. The filing also requested a surcharge to recover the cost of the Warrior Run cogeneration project, which is scheduled to commence production on October 1, 1999. Hearings are scheduled to begin in April 1999. A second Maryland PSC proceeding is planned to begin examining market power protective measures in December 1999. Under the Maryland PSC's current timetable, and assuming the necessary legislation is passed, one-third of the state's electricity customers would be able to
choose their electricity supplier beginning in July 2000, and all customers would have choice by mid-2002.
The West Virginia PSC, the Ohio PUC, and the Virginia SCC began or continued investigations during 1998 regarding the restructuring of and competition in the electric utility industry. (See ITEM 1. BUSINESS - Competition for a description of these activities.)
On September 23, 1998, the Maryland PSC accepted the recommendations of Potomac Edison and its Collaborative Partners to phase out three demand-side management (DSM) programs in Maryland. Potomac Edison reexamined the cost-effectiveness of the programs, and removed the savings associated with production capacity and energy beginning in the year 2000, which is the proposed start date for competition in Maryland. The analysis indicated that the current programs are no longer cost-effective. As a result, these programs will be terminated by December 1999. Since 1993, Potomac Edison has spent $20 million to help customers install energy-saving measures in their homes and businesses through these programs. During 1998, Potomac Edison expended $966,855 on program costs and rebates. These costs are recoverable through a Commission-approved energy conservation surcharge.
In 1997, the Maryland PSC instituted a proceeding to investigate the effect of the proposed AE and DQE merger on Potomac Edison's Maryland customers and operations. The Maryland PSC approved a settlement agreement in this case on March 28, 1998. Upon merger consummation, Maryland retail rates will be reduced by $4.4 million annually to reflect a portion of expected synergy savings.
Potomac Edison and the Virginia Commission Staff entered into discussions which resulted in a settlement agreement of Potomac Edison's Annual Informational Filing (AIF) which the Virginia SCC approved August 7, 1998. Effective September 1, 1998, Potomac Edison reduced base rates by $2.5 million and wrote off $2.3 million of restructuring costs which had been deferred for ratemaking purposes only, and $0.5 of loss on reacquired debt. The return on equity (ROE) range was maintained at 11-12% with the computed ROE, after adjustments, of 11.4%. Potomac Edison agreed to file a full AIF for calendar year 1998 by March 31, 1999, with an earnings test. In the event Potomac Edison is in an over-earning position at that time, its rates will immediately become interim.
Currently, all state regulatory jurisdictions except Pennsylvania and the FERC use fuel clause procedures to recognize changes in fuel and other energy costs in rates. These procedures use an expedited proceeding which permits energy costs to be adjusted on a more timely basis than other costs. Differences between revenues received for energy costs and actual energy costs are deferred until the next proceeding when energy rates are adjusted to return or recover previous overrecoveries or underrecoveries, respectively. This procedure minimizes the effect on net income associated with changes in energy costs.
On June 30, 1998, the West Virginia PSC issued an order in the annual Expanded Net Energy Cost proceedings under which Monongahela and Potomac Edison received annual increases of $8.9 million and $1.0 million,
respectively. The increases were primarily due to fuel cost increases and to the removal of a credit, which had been refunding to customers a prior overrecovery of fuel costs. The new rates became effective July 1, 1998.
Fuel proceedings before the Ohio PUC require a mid-term filing, financial audit, management performance audit, and an annual filing. The Ohio PUC approved a stipulated agreement for Monongahela on January 21, 1999, which granted a decrease of $1.4 million. The new rate was effective February 3, 1999.
On January 15, 1998, Potomac Edison filed with the Virginia SCC for an annual increase in fuel rates of $2.1 million to become effective March 9, 1998. The increase was primarily due to the need to collect prior underrecovery of fuel costs and a small increase in fuel costs. On February 25, 1998, the Virginia SCC approved the increase. On January 15, 1999, Potomac Edison filed for an annual decrease in fuel rates of $2.2 million to become effective March 9, 1999. The decrease is primarily due to the refunding of a prior overrecovery of fuel costs, coupled with a small decrease in projected energy costs. On February 25, 1999, the Virginia SCC approved the decrease.
AGC's rates are set by a formula filed with and previously accepted by the FERC. The only component that can change is the 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 requests a change. No party has requested any change.
ENVIRONMENTAL MATTERS
The operations of the Allegheny-owned facilities, including generating stations, are subject to regulation as to air and water quality, hazardous and solid waste disposal, and other environmental matters by various federal, state, and local authorities. That portion of Fort Martin Unit 1 (50%) owned by AYP Energy is subject to the same environmental regulations as other units owned by the Operating Subsidiaries. Compliance strategies, compliance assurance, permitting, compliance costs, allowance allocation, etc., for this unit are closely coordinated with AYP Capital.
Meeting known environmental standards is estimated to cost the Operating Subsidiaries about $260 million in construction expenditures over the next three years. Additional legislation or regulatory control requirements have been proposed and, if enacted, will require modifying, supplementing, or replacing equipment at existing stations at substantial additional cost.
Air Standards
Allegheny currently meets applicable standards as to particulate and opacity at its power stations through high- efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, and, at times, reduction of output. From time to time, minor excursions of opacity, normal to fossil
fuel operations, are experienced and are accommodated by the regulatory process.
Allegheny meets current emission standards as to sulphur dioxide (SO2) by the use of scrubbers, the burning of low-sulfur coal, the purchase of cleaned coal to lower the sulfur content, and the blending of low-sulfur with higher sulfur coal.
The CAAA, among other things, requires 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 plants are affected in Phase I, and the remaining plants will be affected in Phase II. Installation of scrubbers at the Harrison Power Station was the strategy undertaken by Allegheny to meet the required SO2 emission reductions for Phase I (1995-1999). Allegheny estimates that its banked emission allowances will allow it to comply with Phase II SO2 limits through 2005. Studies to evaluate cost-effective options to comply with Phase II SO2 limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing. It is expected that burner modifications at most of the Allegheny-operated stations will satisfy the NOx emission reduction requirements for the acid rain (Title IV) provisions of the CAAA. Additional NOx reductions are being mandated in Maryland, Pennsylvania, and West Virginia for ozone nonattainment (Title I) reasons. Continuous emission monitoring equipment has been installed on all Phase I and Phase II units.
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 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 that the Operating Subsidiaries receive of approximately 356,000 per year during the Phase I years. Ownership of these allowances permits Allegheny to operate in compliance with Phase I, and, as noted above, is expected to facilitate compliance during the early years of Phase II. As part of its compliance strategy, Allegheny 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, Allegheny chose to treat eight Phase II boilers as Phase-I-affected units (Substitution Units) for calendar year 1998. The status of all substitution units is evaluated on an annual basis to ascertain the financial benefits of retaining these units as Phase I-affected units. As a result of being Phase I-affected, these Substitution Units are required to comply with the Phase I SO2 limits for each year that they are accorded substitution status by Allegheny.
Title I of the CAAA established an Ozone Transport Region (OTR) consisting of the District of Columbia, the northern part of Virginia, and 11 northeastern states including Maryland and Pennsylvania. 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 Standard (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 utilities within the OTR 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-operated stations located in Maryland and Pennsylvania are required to reduce NOx emissions by approximately 55% from the 1990 baseline emissions, with a compliance date of May 1999. RACT controls installed in Allegheny's Maryland and Pennsylvania generating plants are expected to meet the 55% reduction requirement through the year 2002. Further reductions of 75% from the 1990 baseline may be required by May 2003 under Phase III of the MOU. However, the MOU Phase III NOx reductions will most likely be suspended by the EPA's NOx SIP call as discussed below. Pennsylvania promulgated regulations to implement Phase II of the MOU in November 1997. Maryland promulgated regulations to implement Phase II of the MOU in May 1998.
During 1995, the Environmental Council of States and the U.S. Environmental Protection Agency (EPA) established the Ozone Transport Assessment Group (OTAG) to develop recommendations for the regional control of NOx and Volatile Organic Compounds in 37 states east of and bordering the west bank of the Mississippi River plus Texas. OTAG issued its final report in June 1997 that recommended EPA consider a range of utility NOx controls between existing Clean Air Act (Title IV) controls and the less stringent of 85% reduction from the 1990 emission rate or 0.15 lb/mmBtu. According to OTAG recommendations, the states would have the opportunity to conduct additional local and subregional modeling in order to develop and propose appropriate levels and timing of controls. The EPA initiated the regulatory process to adopt the OTAG recommendations with a proposed SIP call issued October 1998. The EPA NOx SIP call requires the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Maryland, Pennsylvania, and West Virginia, without the benefit of the OTAG recommended additional subregional modeling evaluation. Implementation of controls will be required by summer 2003. States are required to develop and submit implementing regulations to the EPA by September 1999. Allegheny's compliance with such stringent regulations will require the installation of expensive post-combustion control technologies on most of its power stations, with a total capital cost of approximately $360 million.
In August 1997, eight northeastern states filed Section 126 petitions with the EPA requesting the immediate imposition of up to an 85% NOx reduction from utilities located in the Midwest and Southeast (West Virginia included). The petitions claim NOx emissions from these upwind sources are preventing their attainment of the ozone standard. In December 1997, the petitioning states and EPA signed a Memorandum of Agreement to address these petitions in conjunction with the OTAG-related SIP call mentioned above. In October 1998, the EPA proposed approval of the petitions. However, the EPA has stated its
belief that implementation of the NOx SIP call will alleviate the need to grant the petitions. EPA intends to issue a final rule by April 1999.
The EPA is required by law to regularly review the NAAQS for criteria pollutants. Recent court orders in litigation by the American Lung Association have expedited these reviews. The EPA in 1996 decided not to revise the SO2 and NOx standards. Revisions to particulate matter and ozone standards were promulgated by the EPA in July 1997. State attainment plans to meet the revised standards will not be developed for several years. Also, in July 1997, EPA proposed regional haze regulations to improve visibility in Class I federal areas (natural parks and wilderness areas). If finalized, subsequent state regulations could require additional reduction of SO2 and/or NOx emissions from Allegheny facilities. The effect on Allegheny of revision to any of these standards or regulations is unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase III of the MOU, SIP calls, and Section 126 petitions cannot be determined at this time. All are being challenged via rulemaking, petition, and/or litigation.
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 more than $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.
In March 1998, the EPA released its Utility Air Toxics Report to Congress. The report itself does not recommend regulatory controls. However, the EPA is expected to make a recommendation on regulatory controls by December 2000. The EPA has identified mercury emissions as requiring further research and monitoring because of the potential concern for public health. While it appears that EPA wants to control utility mercury
emissions, it currently lacks the technical justification. In late November 1998, the EPA issued a mercury data collection request that requires utilities to sample and analyze coal shipments for mercury and chlorine throughout 1999. In addition, some plants may be required to conduct stack testing to determine the effectiveness of existing particulate and SO2 control equipment in the reduction of mercury emissions.
Water Standards
Under the National Pollutant Discharge Elimination System (NPDES), permits for all of Allegheny's stations and disposal sites are in place. However, NPDES permit renewals for several West Virginia and Pennsylvania disposal sites contain what Allegheny believes are overly stringent discharge limitations. Allegheny, in cooperation with the states and EPA, has developed alternate water quality criteria which, if approved by the agencies, will result in less stringent permit limits. If their criteria are not approved, installation of wastewater treatment facilities may become necessary. The cost of such facilities, if required, cannot be predicted at this time.
As the result of a lawsuit by environmental groups, the EPA and WVDEP, on October 27, 1997, proposed total maximum daily loads (TMDLs) for the Blackwater River and South Fork of the Potomac River and five of its tributaries. This is the first of 44 court-ordered waste load allocations for West Virginia to be issued over six years which will, when implemented, reduce the amount of pollutants that can be discharged into rivers that do not meet water quality standards. The final Blackwater TMDL allows the existing waste loads to continue but eliminates unused waste load allocations, including those owned by Allegheny, thereby precluding further development in the area. Because of the precedent setting nature of the Blackwater TMDL, Allegheny and others have challenged the TMDL before the West Virginia Environmental Quality Board. Environmental groups have also filed lawsuits in a number of other states, including Pennsylvania and Maryland, which will, when settled, force these states and the EPA to develop and implement wastewater discharge restrictions. The direct result of these actions will be further reductions in the amount of pollutants that can be discharged by certain company-owned power stations which are located on rivers whose water quality does not meet standards. Indirectly, the TMDL process can adversely affect the region's economy and therefore the financial performance of Allegheny by limiting economic development and curtailing the wastewater discharges of existing industrial customers in certain areas. The total implications of the pending waste load allocations will not be known until the agencies develop and implement TMDLs in specific watersheds.
The Pennsylvania Land Recycling Act, adopted in 1996, and the West Virginia Voluntary Cleanup Act, adopted in 1997, allow 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. The implementing regulations provide for reasonable and cost- effective groundwater cleanup of Allegheny facilities should it become necessary and will encourage economic development in Allegheny'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, the EPA regulates the disposal of hazardous and solid waste materials. Maryland, Ohio, Pennsylvania, Virginia, and West Virginia have also enacted hazardous and solid waste management regulations that are as stringent as or more stringent than the corresponding EPA regulations.
Allegheny is in a continual process of either permitting new or re-permitting existing disposal capacity to meet future disposal needs. All disposal areas are currently operated to be in compliance with their permits.
Allegheny 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. The Operating Subsidiaries will break ground in early 1999 to construct a processing plant which will convert the Pleasants Power Station flue gas desulfurization by-product into a commercial grade synthetic gypsum for use in manufacturing wallboard.
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.)
Toxic Release Inventory (TRI)
On Earth Day 1997, President Clinton announced the expansion of TRI to include electric utilities, limited to facilities that combust coal and/or oil for the purpose of generating power for distribution in commerce. The purpose of TRI is to provide site- specific information on chemical releases to the air, land, and water. The first TRI report is due on July 1, 1999, for calendar year 1998. The reports will be filed with EPA and made available through publication of the reported information and posting on the
Internet. Allegheny is actively working on a communications plan to proactively educate employees and the community on the TRI program and the amounts of reportable chemicals released by Allegheny.
Global Climate Change
Climate change is alleged to be the result of the atmospheric accumulation of certain gases collectively referred to as GHG, the most significant of which is carbon dioxide (CO2). Human activities, including combustion of fossil fuels, are alleged to be responsible for this accumulation of GHG. The Clinton Administration has signed an international treaty called the Kyoto Protocol, which will require the U.S. to reduce emissions of GHG by 7% from 1990 levels in the 2008-2012 time period. The U.S. Senate must ratify the Kyoto Protocol before it enters into force, as must other nations subject to the treaty's provisions. The Senate passed a resolution in 1997 (S.R. 98) by a vote of 95-0 that placed two conditions on entering into any international climate change treaty. First, any treaty must include all nations, and, second, any treaty must not cause serious harm to the U.S. economy. The Kyoto Protocol does not appear to satisfy either of these conditions and, therefore, the Clinton Administration has withheld it from consideration by the Senate. Because coal combustion in power plants produces about 33% of U.S. CO2 emissions, implementation of the Kyoto Protocol would raise considerable uncertainty about the future viability of coal as a fuel source for new and existing power plants.
If and when the need for reducing greenhouse gas emissions has been identified and scientifically supported, Allegheny believes that a global solution involving all nations and must give credit for preventive actions taken. Allegheny believes precipitous and urgent action under strict limits and timetables will result in severe economic dislocation and is not warranted. Allegheny does believe that appropriate results can be achieved domestically by continuing to build upon the notable progress of existing voluntary programs.
For these reasons, Allegheny actively participates in a number of groups to address this environmental matter. Allegheny supports research on the climate change issue through EPRI and participates in a number of organizations to help influence policy matters at the domestic and international levels. Allegheny has also undertaken a program to identify cost- effective and voluntary measures that reduce emissions of GHG in all areas of its business and in other areas, such as forestry, international projects, and emissions trading.
The Operating Subsidiaries maintain an active climate- related research program and are responsive to the greenhouse gas guidelines suggested in the 1992 National Energy Policy Act. As a result, the Operating Subsidiaries have voluntarily reduced their total annual emissions of GHG by 1,090,501, as described in the latest filing with the Department of Energy.
The Operating Subsidiaries support EPRI which funds climate research targets at around $7 to $10 million per year and Edison Electric Institute's Climate Challenge Initiative funded at $100,000 per-year; and have committed
to invest $3.11 million in an electrotechnology and renewable energy venture capital fund.
The Operating Subsidiaries' in-house research program has contributed to applications of new technology, operating efficiencies, reduced electrical losses and pollution emission reductions.
West Penn recently settled a restructuring plan with the Pennsylvania PUC that included five important climate related issues: 1) Renewable Energy Development, 2) Sustainable Energy Fund ($11,425,721 paid on December 31, 1998), 3) Renewable Energy Pilot Program ($300,000 each year), 4) Energy Cooperative Association of Pennsylvania (contribution of $4 million) and 5) Universal Service and Energy Conservation Program ($8.082 million per year).
In response to environmental issues over the past 18 years, the Operating Subsidiaries spent over $1.6 billion in capital expenditures and approximately $200 million annually in operations and maintenance and are committed to environmental stewardship and the research needed to provide answers to difficult compliance problems. These actions will mitigate the impact of the Operating Subsidiaries' operations on the environment and ameliorate the global warming problem.
REGULATION
Allegheny is subject to the broad jurisdiction of the SEC under PUHCA. The Regulated Subsidiaries are regulated as to substantially all of their operations by regulatory commissions in the states in which they operate. The Regulated Subsidiaries, West Penn's unregulated generation, and AYP Energy are also regulated as to various aspects of their business by the FERC. In addition, they are subject to numerous other local, state, and federal laws, regulations, and rules.
In June 1995, the SEC published its report which recommended changes to PUHCA, including a recommendation to Congress to repeal the entire act. Bills have been introduced in the Congress to repeal PUHCA, but have not passed. Allegheny cannot predict what changes, if any, will be made to PUHCA as a result of these activities.
In 1998, 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.
YEAR 2000
Year 2000 (Y2K) readiness is a top priority. Allegheny has an Executive Task Force, led by a Vice President, that is coordinating the efforts of 24 individual Y2K teams, representing all business and support units in Allegheny. The teams are actively working to investigate, evaluate, and mitigate all critical Y2K concerns.
The teams have completed their inventory of all critical elements (computer hardware and software, embedded chips and vendors) that may be affected by Y2K and are well into their remediation, testing, and contingency planning efforts. Allegheny's goal is to have most mission critical components and systems Y2K-ready by the first quarter of 1999, and all of them ready by mid-year.
Allegheny's Y2K teams are involved in contingency planning and are working with other utilities, customers, government agencies, financial institutions, suppliers, and vendors to achieve a cooperative and thorough effort. Allegheny believes its critical equipment will be ready for the Year 2000, but Allegheny must prepare for any contingency. In 1999, Allegheny will participate in two nationwide testing drills.
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 of the Operating Subsidiaries' 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 MAP.)
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In a letter to AE dated October 5, 1998, DQE stated that it had decided to unilaterally terminate the merger. In response, on October 5, 1998, AE filed a lawsuit in the United States District Court for the Western District of Pennsylvania against DQE for specific performance of the Merger Agreement or, in the alternative, for damages. AE also filed motions for a temporary restraining order and preliminary injunction against DQE. On October 28, 1998, the court denied AE's motions for a temporary restraining order and preliminary injunction. On October 30, 1998, AE appealed the District Court's order to the United States Court of Appeals for the Third Circuit. On March 11, 1999, the U.S. Court of Appeals for the Third Circuit vacated the district court's denial of Allegheny's motion for preliminary injunction, enjoining DQE from taking actions prohibited by the merger agreement. The Circuit Court stated that if DQE breached the Merger Agreement, AE would be entitled to
specific performance of the Merger Agreement. The Circuit Court also stated that AE would be irreparably harmed if DQE took actions that would prevent AE from receiving the specific performance remedy. The Circuit Court remanded the case to the District Court for further proceedings consistent with its opinion.
In the District Court, discovery is ongoing, and AE cannot predict the outcome of this litigation. However, AE believes that DQE's basis for seeking to terminate the merger is without merit. Accordingly, AE continues to seek the remaining regulatory approvals from the Department of Justice and the Securities and Exchange Commission. It is not likely either agency will act on the requests unless AE obtains judicial relief requiring DQE to move forward.
On September 29, 1997, the City of Pittsburgh filed an antitrust and conspiracy lawsuit in the Federal District Court for the Western District of Pennsylvania against AE, West Penn, DQE, and Duquesne. The complaint alleged eight counts, two of which were claimed violations of the antitrust statutes and six were state law claims. The relief sought included a request that the proposed merger between AE and DQE be stopped, and requested unspecified monetary damages relating to alleged collusion between the two companies in their actions dealing with proposals to provide electric service to redevelopment zones in the city. On October 27, 1997, all defendants filed motions to dismiss the complaint. On January 6, 1998, the District Court issued an order which granted the motions to dismiss. On January 14, 1998, the City appealed the order to the United States Court of Appeals for the Third Circuit. On June 12, 1998, the Third Circuit upheld the District Court's order. This matter was subsequently settled.
On September 7, 1995, MidAtlantic Energy (MidAtlantic) sued Monongahela, Potomac Edison, and AE in state court in Marshall County, W.Va., alleging 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 to 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 AE filed an answer and B and W filed an answer and counterclaim. Monongahela, Potomac Edison, and AE cannot predict the outcome of this litigation.
On August 13, 1996, American Bituminous Partners, L.P., (AmBit), filed a request for arbitration alleging that the energy rate payable under its purchase power contract with Monongahela had been improperly calculated. The arbitration proceeding was bifurcated into a liability phase and, if necessary, a damages phase. A hearing in the liability phase of the arbitration proceeding has been completed and briefed. On February 18, 1998, the arbitration panel made a determination in the liability phase. They determined that certain lime handling costs should have been a component of the energy rate and therefore were improperly accounted for in 1995 and 1996. The damages phase of the arbitration on this issue will be limited to determination of the extent of these costs and any related lime handling
costs that AmBit can show should have been included in the calculation of the energy rate. Monongahela cannot predict the outcome of this proceeding.
As of January 19, 1999, Monongahela has been named as a defendant along with multiple other defendants in a total of 7,680 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 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 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 filed a declaratory judgment action in the Court of Common Pleas of Westmoreland County, Pa., against its historic comprehensive general liability (CGL) insurers. This suit 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 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 175 other PRPs involved. A Remedial Investigation/Feasibility Study (RI/FS) prepared by the EPA originally indicated remedial alternatives which ranged as high as $113 million, to be shared by all responsible parties. A PRP Group consisting of approximately 40 members, and to which the Operating Subsidiaries belong, has been formed and has submitted an addendum to the RI/FS which proposes a substantially less expensive cleanup remedy. In January 1998, this PRP Group has made a good-faith offer to the EPA to settle this matter. 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 effect on 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, Pa. Potomac Edison notified the EPA that it has no records or recollection of any business relations with the site or any of the companies identified in the questionnaire. It is not possible to determine at this time what effect, if any, this matter may have on Potomac Edison.
After protracted litigation concerning the Operating Subsidiaries' application for a license to build a 1,000-MW energy-storage facility near Davis, W.Va., 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. The Operating Subsidiaries cannot predict the outcome of this proceeding.
In 1979, National Steel Corporation (National Steel) filed suit against AE and certain subsidiaries in the Circuit Court of Hancock County, W.Va., alleging damages of approximately $7.9 million as a result of an order issued by the West Virginia PSC requiring curtailment of National Steel's use of electric power during the United Mine Workers' strike of 1977-8. A jury verdict in favor of AE and the subsidiaries was rendered in June 1991. National Steel has filed a motion for a new trial, which is still pending before the Circuit Court of Hancock County. AE and the subsidiaries believe the motion is without merit; however, they cannot predict the outcome of this case.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
AE, Monongahela, Potomac Edison, West Penn, and AGC did not submit any matters to a vote of shareholders during the fourth quarter of 1998.
Executive Officers of the Registrants
The names of the executive officers of each company, their ages as of December 31, 1998, the positions they hold, or held during 1998, and their business experience during the past five years appears below:
Executive Officers of the Registrants, cont'd.
The names of the executive officers of each company, their ages as of December 31, 1998, the positions they hold, or held during 1998, and their business experience during the past five years appears below:
(a) All officers and directors are elected annually. (b) Prior to his appointment as Vice President and Treasurer of AE and Treasurer of MP, PE, WPP, and AGC, Mr. Binder was Executive Director, Regulation and Rates for APSC (1997-1998); General Manager, Industrial Marketing for APSC (1996-1997); Director, Rates for APSC (1995-1996); and Assisant Director Rates for APSC (1993-1995). (c) Ms. Campbell retired effective December 1, 1998. (d) Prior to his appointment as Vice President, Mr. Estel was Director, Communications (12/95-4/96), Asst. Director Communications (10/95-12/95), Director, Human Resources (1/95-10/95) and Director, Personnel 12/90-1/95). Mr. Estel resigned as a Vice President in October 1998.
(e) Prior to his appointment as Vice President Customer Operations, Mr. Haney was Executive Director, Operating Business Unit (8/98-10/98); Director, Operations Services (5/96-8/98); Director, Transmission Projects (12/95-5/96); Manager, Construction (APSC) (2/95-12/95); and Division Manager, Monongahela (12/90-2/95).
(f) Prior to joining Allegheny, Mr. Morrell was 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).
(g) Prior to joining Allegheny, Ms. Schaff was a Federal Affairs Representative with the Union Electric Company (4/88-12/95).
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
AE
AYE is the trading symbol of the common stock of AE 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, 1998, there were 48,869 holders of record of AE's common stock.
The tables below show the dividends paid and the high and low sale prices of the common stock for the periods indicated:
1998 1997 Dividend High Low Dividend High Low 1st Quarter 43 cents $33-9/16 $30-1/8 43 cents $31-5/8 $29-1/8 2nd Quarter 43 cents 34 $27-5/16 43 cents $30-1/8 $25-1/2 3rd Quarter 43 cents 31-15/16 $26-5/8 43 cents $30-3/8 $26-5/8 4th Quarter 43 cents 34-15/16 $29-1/2 43 cents $32-19/32 $27-1/4
The high and low prices through March 4, 1999 were $34-l/2 and $28-11/16. The last reported sale on that date was at $31-5/16.
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 AE.
AGC. The information required by this Item is not applicable as all the common stock of AGC is held by Monongahela, Potomac Edison, and West Penn.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Page No.
AE D- 1
Monongahela D- 4
Potomac Edison D- 6
West Penn D- 8
AGC D-10
Allegheny Energy, Inc.
Condensed Financial Statements
D-1
Allegheny Energy, Inc.
D-2
Allegheny Energy, Inc.
Consolidated Statistics (continued)
a Write-off in connection with deregulation proceedings in Pennsylvania. b To record unbilled revenues, net of income taxes. c Reflects a two-for-one common stock split effective November 4, 1993. d Basic and diluted earnings per average share. e Excludes the cumulative effect of the accounting change in 1994, and the extraordinary charge, net and Pennsylvania restructuring activities in 1998. Includes the effect of internal restructuring in 1995 and 1996. f Excludes 432 gWh delivered to customers participating in the Pennsylvania pilot program that are included in regular utility transactions sales volumes. g Capability available through contractual arrangements with nonutility generators.
h Preliminary D-3
Monongahela Power Company
QUARTERLY FINANCIAL INFORMATION (Thousands of Dollars)
SUMMARY OF OPERATIONS Year ended December 31 (Thousands of Dollars)
(a) To record unbilled revenues, net of income taxes. (b) Excludes the cumulative effect of the accounting change in 1994 and includes the effect of internal restructuring in 1995 and 1996.
D-4
Monongahela Power Company
FINANCIAL AND OPERATING STATISTICS
(a) Capability available through contractual arrangements with nonutility generators.
D-5
The Potomac Edison Company
QUARTERLY FINANCIAL INFORMATION (Thousands of Dollars)
SUMMARY OF OPERATIONS Year ended December 31 (Thousands of Dollars)
(a) To record unbilled revenues, net of income taxes. (b) Excludes the cumulative effect of the accounting change in 1994 and includes the effect of internal restructuring in 1995 and 1996.
D-6
The Potomac Edison Company
FINANCIAL AND OPERATING STATISTICS
D-7
West Penn Power Company and Subsidiaries
QUARTERLY FINANCIAL INFORMATION (Thousands of Dollars)
SUMMARY OF OPERATIONS Year ended December 31 (Thousands of Dollars)
(a) Write-off in connection with Pennsylvania deregulation proceedings. (b) To record unbilled revenues, net of income taxes. (c) Excludes the cumulative effect of the accounting change in 1994, and the extraordinary charge, net and Pennsylvania restructuring activities in 1998. Includes the effect of internal restructuring in 1995 and 1996.
D-8
West Penn Power Company and Subsidiaries
FINANCIAL AND OPERATING STATISTICS
(a) Capability available through contractual arrangements with nonutility generators. (b) Excludes 907,526 kWh (in thousands) delivered to customers participating in the Pennsylvania pilot program that are included in regular customer transactions sales volumes.
D-9
Allegheny Generating Company
QUARTERLY FINANCIAL INFORMATION (Thousands of Dollars)
D-10
Allegheny Generating Company
STATISTICS
SUMMARY OF OPERATIONS Year ended December 31 (Thousands of Dollars)
*Reflects a balance sheet reclassification in 1995 of $12 million from deferred charges to plant for a prior tax payment, and a related settlement of $8.8 million in 1997 that was recorded as a reduction to plant.
D-11
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Page No.
AE M- 1
Monongahela M-21
Potomac Edison M-36
West Penn M-51
AGC M-67
Allegheny Energy, Inc.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Factors That May Affect Future Results
This management's discussion and analysis of financial condition and results of operations contains forecast information items that are "forward- looking statements" as defined in the Private Securities Litigation Reform Act of 1995. These include statements with respect to deregulation activities and movements toward competition in states served by the Company, the merger with DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., and results of operations. All such forward- looking information is necessarily only estimated. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially include, among other matters, electric utility restructuring, including the ongoing state and federal activities; potential Year 2000 operation problems; developments in the legislative, regulatory, and competitive environments in which the Company operates, including regulatory proceedings affecting rates charged by the Company's subsidiaries; environmental, legislative, and regulatory changes; future economic conditions; earnings retention and dividend payout policies; developments relating to the proposed merger with DQE, including expenses that may be incurred in litigation; and other circumstances that could affect anticipated revenues and costs such as significant volatility in the market price of wholesale power, unscheduled maintenance or repair requirements, weather, and compliance with laws and regulations.
Significant Events in 1998, 1997, and 1996
Pennsylvania Deregulation
On November 19, 1998, the Pennsylvania Public Utility Commission (Pennsylvania PUC) approved a settlement agreement between West Penn Power Company (West Penn), the Company's Pennsylvania electric utility subsidiary, and intervenors in West Penn's restructuring proceedings related to legislation in Pennsylvania to provide customer choice of electric suppliers and deregulate electricity generation.
As a result of the May 29, 1998, Pennsylvania PUC Order and as revised by the November 19, 1998, settlement agreement, West Penn determined that under the provisions of Statement of Financial Accounting Standards No. 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71," an extraordinary charge of $466.9 million ($275.4 million after taxes) was required to reflect a write-off of certain disallowances. In addition, charges of $40.3 million ($23.7 million after taxes) related to the West Penn revenue refund and energy program payments were also recorded.
Under the terms of the settlement agreement, two-thirds of West Penn's customers were permitted to choose an alternate generation supplier beginning in January 1999. All West Penn customers can do so beginning in January 2000. They can also choose to remain as West Penn customers at West Penn's capped generation rates or to alternate back and forth. Under the law, all electric utilities, including West Penn, retain the responsibility of electricity provider of last resort to all customers in their respective franchise territories who do not choose an alternate supplier. See Notes B and C to the consolidated financial statements for details of the settlement agreement and other information about the deregulation process.
M-1
Allegheny Energy, Inc.
Merger with DQE
See page 38 and also Note D to the consolidated financial statements for more information about the merger.
Maryland Settlement and Deregulation
The Company's Maryland subsidiary, The Potomac Edison Company (Potomac Edison), reached a settlement agreement with various parties on the Office of People's Counsel's petition for a reduction in Potomac Edison's Maryland rates. Further information on the settlement agreement is provided under Sales and Revenues starting on page 31.
On July 1, 1998, Potomac Edison filed testimony in Maryland's investigation into transition costs, price protection, and unbundled rates. See Electric Energy Competition on page 38 for more information regarding the restructuring in Maryland.
Nonutility Operations
In 1996, the Company's nonutility subsidiary, AYP Capital, Inc. (AYP Capital) expanded its nonutility operations by forming AYP Energy, Inc. (AYP Energy) and Allegheny Communications Connect, Inc. (ACC). ACC was formed to develop opportunities in the deregulated telecommunications market. AYP Energy is a bulk power marketer. In October 1996, AYP Energy purchased for about $170 million a 50%, 276-megawatt (MW), interest in Unit No. 1 of the Fort Martin coal-fired power station in West Virginia. Two of the Company's utility subsidiaries own the other 50%.
In 1997, AYP Capital formed Allegheny Energy Solutions, Inc. (Allegheny Energy Solutions). Allegheny Energy Solutions was formed to market electric energy to retail customers in deregulated markets. Because of organizational efficiencies available in an alternate corporate structure, Allegheny Energy Solutions no longer competes in deregulated energy markets as of January 1999. Rather, that role has been assumed by the Energy Supply Division of the Supply Business of West Penn. With customer choice now under way in Pennsylvania, the Energy Supply Division attracted about 1,300 MW of load for 1999. West Penn lost only about 400 MW of load in this competitive environment, giving it a net gain of about 900 MW.
AYP Capital, in its own name, also markets various services related to the electric industry and has investments in two limited energy partnerships.
PURPA Power Project Terminations
On August 26, 1997, and December 3, 1997, West Penn announced that it had negotiated agreements to buy out and settle disputes with developers of proposed power plants (the Milesburg and Washington Power projects) for $15 million and $48 million, respectively, reducing costs over the proposed 30- and 33-year lives of the projects by an estimated $1.4 billion. The disputed projects were being developed under the Public Utility Regulatory Policies Act of 1978 (PURPA) and would have required West Penn to buy 43 MW and 80 MW of capacity and energy, respectively, over the lives of the projects at
M-2
Allegheny Energy, Inc.
prices well above current market price estimates. In 1996, West Penn and the developers of a proposed Shannopin PURPA project reached an agreement to terminate that project at a buyout price of $31 million. The Shannopin buyout will reduce West Penn's costs approximately $665 million over 30 years by eliminating the need to buy the uneconomic power.
Internal Restructuring
In 1994, the Company and its subsidiaries initiated an internal restructuring process to consolidate and re-engineer their utility operations to meet the competitive challenges of the changing electric utility industry. As a result of this process, the subsidiaries reduced employment by about 1,000 employees through a voluntary separation plan, attrition and layoffs, and changed processes to obtain efficiencies to reduce operating and maintenance costs. This process resulted in internal restructuring charges and an asset write-off in 1996 as described in Note E to the consolidated financial statements.
Review of Operations
Earnings Summary
*Pennsylvania deregulation settlement costs in 1998 and internal restructuring costs in 1996.
The increase in 1998 earnings from utility operations, before costs related to Pennsylvania restructuring and settlement activities, resulted from increased kilowatt-hour (kWh) sales to commercial and industrial customers and from reduced power station operation and maintenance (O&M) spending. The 1998 costs from restructuring activities and the extraordinary charge are related to Pennsylvania deregulation and the Pennsylvania restructuring Order. These costs are described in Notes B and C to the consolidated financial statements. The 1996 restructuring costs resulted from internal restructuring initiated in 1994 which is described in Note E to the consolidated financial statements and Internal Restructuring on page 30. The increase in 1997 earnings from utility operations resulted primarily from reductions in O&M expenses from the internal restructuring process and additional actions taken during the year to achieve further O&M reductions in response to significant decreases in residential kWh sales caused primarily by mild weather.
M-3
Allegheny Energy, Inc.
The increase in losses from nonutility operations in 1998 resulted primarily from AYP Energy sales commitments for energy in excess of owned generating capacity which required settlement by open market purchases during a period of high wholesale prices. Other marketing activities served to mitigate these losses as described on page 33. After purchasing a 50% ownership interest in Unit No. 1 of Fort Martin power station in October 1996, AYP Energy completed its first full year of operation in 1997. Because of considerable excess generating capacity pursuing limited demand in 1997 and 1998, AYP Energy's operating margins were insufficient to cover all of its fixed costs. This condition may continue until further deregulation activities expand market opportunities and competing excess capacity is absorbed by demand growth. Another item contributing to the nonutility losses was Allegheny Energy Solutions' net losses of $1.7 million and $1.4 million in 1998 and 1997, respectively, for its participation in the Pennsylvania pilot program (see Note B to the consolidated financial statements for more information about the pilot program)
Sales and Revenues
Total operating revenues for 1998, 1997, and 1996 were as follows:
M-4
Allegheny Energy, Inc.
Bundled retail sales revenues (full service sales to retail customers) include a $25.1 million rate refund from 1998 revenues, pursuant to the terms of the Pennsylvania restructuring settlement agreement. This refund to customers will be made in 1999. Excluding this rate decrease, bundled retail sales increased $21.1 million in 1998 primarily due to increased kWh sales to commercial and industrial customers. The increase in 1998 was also due to an increase in the number of customers. Retail sales include sales to residential, commercial, industrial, and street lighting customers. Bundled retail sales revenues were also affected by the Electricity Generation Customer Choice and Competition Act (Customer Choice Act) in Pennsylvania. As part of the Customer Choice Act, all utilities in Pennsylvania were required to administer retail access pilot programs under which customers, representing 5% of the load of each rate class, would choose a generation supplier other than their own local franchise utility. As a result, 5% of previously fully bundled customers participated in the Pennsylvania pilot program and were required to buy energy from another supplier of their choice. The pilot program began on November 1, 1997, and continued through December 31, 1998. Unbundled retail sales revenues represent transmission and distribution revenues from Pennsylvania pilot customers who chose another supplier to provide their energy needs.
To assure participation in the pilot program, pilot participants received an energy credit from their local utility and a price for energy pursuant to an agreement with an alternate supplier. The credit established by the Pennsylvania PUC was artificially high to encourage customer shopping, with the result that West Penn incurred a revenue loss of $6.5 million for the pilot. The Pennsylvania PUC has approved West Penn's pilot compliance filing and thus has indicated its intent to treat the revenue loss as a regulatory asset. Wholesale and other revenues include an accrual of such revenue losses, as well as sales to wholesale customers (cooperatives and municipalities that own their own distribution systems and buy all or part of their bulk power needs from the subsidiaries under Federal Energy Regulatory Commission (FERC) regulation) and non-kWh revenues.
On August 7, 1998, the Virginia State Corporation Commission (Virginia SCC) approved an agreement reached between Potomac Edison and the Staff of the Virginia SCC which reduced base rates for Virginia customers beginning September 1, 1998, by about $2.5 million annually. The review of rates was required by an annual information filing in Virginia.
In 1999, utility revenues will reflect a reduction for a settlement agreement with various parties on the Maryland Office of People's Counsel's petition for a reduction in Potomac Edison's Maryland rates. The agreement, which includes recognition of costs to be incurred from the Applied Energy Services (AES) Warrior Run PURPA cogeneration project, was approved by the Maryland Public Service Commission (Maryland PSC) on October 27, 1998. Under the terms of that agreement, Potomac Edison will increase its rates about 4% ($13 million) in each of the years 1999, 2000, and 2001 (a $39 million annual effect in 2001). The increases are designed to recover additional costs of about $131 million over the period 1999-2001 for capacity purchases from the AES Warrior Run cogeneration project, net of alleged over-earnings of $52 million for the same period. The net effect of these changes over the 1999-2001 timeframe results in a pre-tax income reduction of $12 million in 1999,
M-5
Allegheny Energy, Inc.
$18 million in 2000, and $22 million in 2001. In addition, the settlement requires that Potomac Edison share, on a 50% customer, 50% shareholder basis, earnings above a return on equity of 11.4% for 1999-2001. This sharing will occur through an annual true-up.
Bundled retail revenues reflect not only changes in kWh sales and base rate changes, but also any changes in revenues from fuel and energy cost adjustment clauses (fuel clauses) which are still applicable in all Company jurisdictions served, except for Pennsylvania. Changes in fuel revenues in those jurisdictions have no effect on consolidated net income because increases and decreases in fuel and purchased power costs and sales of transmission services and bulk power are passed on to customers by adjustment of customers' bills through fuel clauses.
Effective May 1, 1997, as a result of the Customer Choice Act, West Penn obtained Pennsylvania PUC authorization to set its fuel clause to zero and to roll its then-applicable fuel clause rates into base rates. Thereafter, West Penn assumed the risks and benefits of changes in fuel and purchased power costs and sales of transmission services and bulk power. The decrease in 1997 bundled retail revenues resulted primarily from a decrease in the fuel component of revenues and a decrease in residential kWh sales due to mild weather in 1997.
The increase in wholesale and other revenues in 1998 was due primarily to deferred net revenue losses. West Penn recorded a regulatory asset of $6.4 million in 1998 and $.1 million in 1997 to offset revenue losses suffered as a result of the pilot program.
Nonutility retail and other revenues increased in 1998 due to Allegheny Energy Solutions' electric energy sales to retail customers in deregulated markets.
Utility and nonutility revenues include sales of bulk power to power marketers and other utilities. Utility revenues also include sales of transmission services to such marketers and utilities. Significant bulk power sales in 1998 acted to offset certain second and third quarter marketing losses in nonutility operations. The Company has discontinued the types of marketing activities which caused the losses. Bulk power and transmission services sales for 1998, 1997, and 1996 were as follows:
1998 1997 1996 KWh Transactions (in billions):
Utility: Bulk power $ 3.0 1.7 1.0 Transmission services 7.4 12.3 17.4 Total utility 10.4 14.0 18.4 Nonutility bulk power 7.3 3.7 .1 Revenues (in millions): Utility: Bulk power $ 69.8 $39.6 $22.4 Transmission services 45.2 41.1 52.4 Total utility $115.0 $80.7 $74.8 Nonutility bulk power $215.3 $80.9 $ .7
M-6
Allegheny Energy, Inc.
The 1998 increase in revenues from utility bulk power was due to increased sales that occurred primarily in the second quarter as a result of warm weather which increased the demand and price for energy. In 1998, revenues from utility transmission services were affected by a revenue refund resulting from a reduction in the Company's standard transmission rate and rates for ancillary services which were recently approved by the FERC. A provision for these rate reductions was recorded in 1998, with the revenues to be refunded to customers in the first quarter of 1999.
Revenues from utility operations' transmission services in 1998 increased, despite decreased transmission services activity. The increase in revenues was due in part to transmission services' reservation charges paid to the Company by others for the right to transmit energy. Transmission services activity was affected as a result of some of the reservations to transmit energy not being used.
Revenues from utility operations' transmission services in 1997 decreased due to reduced demand, primarily because of mild weather.
In June and July 1998, certain events combined to produce significant volatility in the spot prices for electricity at the wholesale level. These events included extremely hot weather, Midwest generation unit outages, and transmission constraints. Wholesale prices for electricity rose from a normal range of from $25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per mWh. The potential exists for such volatility to significantly affect the Company's operating results. The effect may be either positive or negative, depending on whether the Company's subsidiaries are net buyers or sellers of electricity during such periods, the open commitments which exist at such times, and whether the effects of such transactions by the Company's utility subsidiaries are includable in fuel or energy cost recovery clauses in their respective jurisdictions. The effect of such price volatility in June and the third quarter of 1998 differed between the Company's utility and nonutility subsidiaries, but was insignificant in total.
The increase in nonutility bulk power revenues resulted primarily from increased bulk power sales by the Company's nonutility bulk power marketer, AYP Energy, which began operations in late 1996, and from Allegheny Energy Solutions, which was formed in the third quarter of 1997 to market energy to retail customers in deregulated markets and other energy-related services. Increased prices for energy in the wholesale market also contributed to the increase. Allegheny Energy Solutions recorded $24.9 million and $1.2 million of revenues in 1998 and 1997, respectively. Allegheny Energy Solutions ceased operations as an electric generation supplier in January 1999. The Company will continue to market nonutility energy supply to retail customers under the brand name of Allegheny Energy Supply under the direction of a newly created Energy Supply Division of the Supply Business. The Energy Supply Division will also market nonutility energy supply to wholesale customers.
Operating Expenses
M-7
Allegheny Energy, Inc.
Fuel expenses for 1998, 1997, and 1996 were as follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $545.4 $535.7 $512.5 Nonutility operations 21.1 24.2 .7
Total fuel expenses $566.5 $559.9 $513.2
Fuel expenses for utility operations in 1998 and 1997 increased 2% and 5%, respectively, due primarily to an increase in kWhs generated. The increase in kWhs generated for utility operations was primarily the result of increased bulk power sales to power marketers and other utilities.
Fuel expenses for nonutility operations reflect the kWhs generated by the 50% of Unit No. 1 of the Fort Martin power station purchased by AYP Energy in late 1996.
The 1998 decrease in fuel expense for nonutility operations was due to a decrease in kWhs generated as a result of a scheduled outage at the unit.
Purchased power and exchanges, net, represents power purchases from and exchanges with other companies and purchases from qualified facilities under PURPA, and consists of the following items:
(Millions of Dollars) 1998 1997 1996
Purchased power: Utility operations: From PURPA generation* $129.0 $134.8 $132.7 Other 50.0 41.2 47.3
Total purchased power for utility operations 179.0 176.0 180.0 Power exchanges, net (.7) .3 3.3 Nonutility operations 210.5 43.5 1.1
Purchased power and exchanges, net $388.8 $219.8 $184.4
*PURPA cost (cents per kWh) 5.4 5.6 5.5
The decrease in utility purchased power from PURPA generation in 1998 was due primarily to reduced generation at hydroelectric plants due to river flow. PURPA purchased power costs will be reduced $197 million during the period 1999-2016 related to the AES Beaver Valley nonutility generation contract as a result of the 1998 extraordinary charge. See Notes B and C to the consolidated financial statements for further information.
M-8
Allegheny Energy, Inc.
The increase in other purchased power in 1998 for utility operations resulted primarily from increased purchases for sales. An increase in price caused by volatility in the spot prices for electricity at the wholesale level in the second and third quarters of 1998 also contributed to the increase. The decrease in 1997 was a result of decreased demand due to decreased sales to retail customers related to mild 1997 weather, as well as increased availability of the subsidiaries' power stations.
Nonutility operations purchased power is the result of power replacement requirements and transaction opportunities by AYP Energy which began operations in late 1996. The increases in nonutility purchases in 1998 and 1997 are due primarily to an increase in volume attributable to AYP Energy's increased participation in the market and increased prices.
The AES Warrior Run PURPA cogeneration project in Potomac Edison's Maryland service territory, scheduled to commence generation in October 1999, will increase the cost of power purchases $60 million or more annually. The settlement, described under Sales and Revenues starting on page 31, is designed to recover all such costs through 2001.
Other operation expenses for 1998, 1997, and 1996 were as follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $319.2 $292.3 $298.5 Nonutility operations 18.2 16.7 1.3
Total other operation expenses $337.4 $309.0 $299.8
The increase in utility other operation expenses in 1998 was due primarily to increased expenses related to competition and the Pennsylvania restructuring Order ($24.3 million). See Note B to the consolidated financial statements for additional information related to Pennsylvania restructuring.
Utility other operation expenses in 1997 include $3.3 million for increased allowances for uncollectible accounts and $4.4 million of legal expenses incurred by West Penn to defend itself against an antitrust lawsuit filed by the developers of the proposed Washington Power PURPA project. The dispute was settled in December 1997. Nevertheless, utility other operation expense decreased in 1997 because of a reduction in embedded expenses achieved through the 1996 internal restructuring process. The increase in nonutility other operation expenses was due to startup expenses incurred by the Company's nonutility subsidiary, AYP Capital.
Maintenance expenses for 1998, 1997, and 1996 were as follows:
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(Millions of Dollars) 1998 1997 1996
Utility operations $212.3 $227.1 $242.5 Nonutility operations 5.3 3.5 .8
Total maintenance expenses $217.6 $230.6 $243.3
The decrease in utility maintenance in 1998 was due primarily to a management program to postpone such expenses for the year in response to limited sales growth in the first quarter due to the warm winter weather. The Company is postponing these expenses primarily by extending the time between maintenance outages. The 1997 decrease in utility maintenance expenses resulted from reduced expenses achieved through internal restructuring efforts and other cost controls. 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. The increases in nonutility maintenance expense in 1998 and 1997, respectively, were primarily related to a 1998 planned outage for maintenance of Unit No. 1 of the Fort Martin power station, 50% owned by AYP Energy, and in 1997 due to the first full year of AYP Energy operations.
Internal restructuring charges and an asset write-off in 1996 resulted from internal restructuring activities, which have been completed, and the write-off of previously accumulated costs related to a proposed transmission line.
Depreciation expenses for 1998, 1997, and 1996 were as follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $264.6 $259.1 $263.2 Nonutility operations 5.8 6.6
Total depreciation expense $270.4 $265.7 $263.2
Higher utility depreciation in 1998 resulted from increased investment. The decrease in utility depreciation expense in 1997 was the result of a change in the retirement dates for West Penn for the Mitchell power station and the Pleasants power station scrubbers. The increase in nonutility depreciation expense in 1997 was the result of depreciation incurred by AYP Energy because of its purchase in October 1996 of a 50% ownership in Unit No. 1 of the Fort Martin power station.
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Allegheny Energy, Inc.
Taxes other than income taxes for 1998, 1997, and 1996 were as follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $187.7 $181.4 $185.4 Nonutility operations 6.9 5.6
Total taxes other than income taxes $194.6 $187.0 $185.4
The increase in utility taxes other than income taxes in 1998 was due primarily to increased West Virginia Business and Occupation Taxes (B&O) resulting from an adjustment for a prior period and increased property taxes. The nonutility increase in 1998 was due to gross receipts taxes resulting from higher revenues from retail customers. The 1997 increase in taxes other than income taxes was due to an increase in nonutility taxes of $5.6 million in B&O and property taxes resulting from AYP Energy's purchase of an ownership interest in the Fort Martin power station offset by a $4 million decrease in utility taxes because of a decrease in gross receipts taxes due to lower retail revenues and lower FICA taxes due to the Company's prior year internal restructuring.
The 1997 increase in federal and state income taxes was primarily due to increased income in 1997 compared with 1996. Note F to the consolidated financial statements provides a further analysis of income tax expenses. The decrease in allowance for other than borrowed funds used during construction of $2.8 million in 1998 reflects lower-cost short-term debt financing. The allowance for borrowed funds used during construction component of the formula receives greater weighting when short-term debt increases. The decrease also reflects adjustments of prior periods.
The decrease in other income, net, of $9.8 million in 1998 and the increase in 1997 of $13.6 million was primarily due to 1997 increases for an interest refund on a tax-related contract settlement ($8.3 million, net of taxes) and income on the sale of land ($2.8 million, net of taxes).
Interest on long-term debt for 1998, 1997, and 1996 was as follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $151.0 $162.8 $164.3 Nonutility operations 10.1 10.8 2.1
Total interest on long-term debt $161.1 $173.6 $166.4
The decrease in interest on long-term debt in 1998 of $12.5 million resulted from reduced long-term debt and lower interest rates. Interest on nonutility long-term debt in 1997 increased due to October 1996 bank borrowings of $160 million by AYP Energy related to its purchase of an ownership interest in the Fort Martin power station. 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.
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The extraordinary charge of $466.9 million ($275.4 million after taxes) was required to reflect a write-off of certain disallowances in the Pennsylvania PUC's May and November 1998 orders as described in Notes B and C to the consolidated financial statements.
Financial Condition, Requirements, and Resources
Liquidity and Capital Requirements
To meet cash needs 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 financings depend upon the financial health of the companies seeking those funds and market conditions.
Construction expenditures of all the subsidiaries in 1998 were $231 million and, for 1999 and 2000, are estimated at $315 million and $294 million, respectively. The 1999 and 2000 estimated expenditures include $63 million and $85 million, respectively, for construction of environmental control technology. It is the Company's goal to constrain future utility construction spending to the approximate level of depreciation currently in rates. The subsidiaries also have additional capital requirements for debt maturities (see Note K to the consolidated financial statements).
Internal Cash Flow
Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $381 million in 1998, compared with $268 million in 1997. Reduced 1997 cash flow was the result of the $48 million buyout of the Washington Power PURPA project and payment of internal restructuring liabilities. Current rate levels and reduced levels of construction expenditures permitted the subsidiaries to finance all of their construction expenditures in 1998 and nearly all in 1997 with internal cash flow. As described under Environmental Issues starting on page 39, the subsidiaries could potentially face significant mandated increases in construction expenditures and operating costs related to environmental issues. Whether the regulated subsidiaries can continue to meet the majority of their construction needs with internally generated cash is largely dependent upon the outcome of these issues.
Dividends paid on common stock in each of the years 1998 and 1997 were $1.72 per share. The dividend payout ratio, excluding the extraordinary charge and Pennsylvania settlement costs in 1998, decreased slightly from 1997.
Financing
The Company did not issue any common stock in 1998. The shares for its Dividend Reinvestment and Stock Purchase Plan, Employee Stock Ownership and
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Allegheny Energy, Inc.
Savings Plan, and Performance Share Plan were purchased on the open stock market. Short-term debt is used to meet temporary cash needs. Short-term debt increased $52.4 million to $258.8 million in 1998. At December 31, 1998, unused lines of credit with banks were $300 million. The utility subsidiaries anticipate meeting their 1999 cash needs through internal cash generation, cash on hand, and short-term borrowings as necessary. However, West Penn is expected to issue up to $670 million of bonds to "securitize" transition costs related to its restructuring settlement described in Note B to the consolidated financial statements.
Significant Continuing Issues
Proposed Merger with DQE
The Company believes that DQE's basis for seeking to terminate the merger (described in Note D to the consolidated financial statements) is without merit. Accordingly, the Company continues to seek the remaining regulatory approvals from the Department of Justice and the Securities and Exchange Commission (SEC). It is not likely either agency will act on the requests unless the Company obtains judicial relief requiring DQE to move forward.
Electric Energy Competition
The electricity supply segment of the electric utility industry in the United States is in the midst of becoming a competitive marketplace. The Energy Policy Act of 1992 began the process of deregulating the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. Since 1992, the wholesale electricity market has become increasingly competitive as companies began to engage in nationwide power trading. In addition, some states have taken active steps toward allowing retail customers the right to choose their electricity supplier. All of the states served by the utility subsidiaries have investigated or implemented retail access to alternate electricity suppliers. The Company has been an advocate of federal legislation to create competition in the retail electricity markets to avoid regional dislocations and ensure level playing fields. In the absence of federal legislation, state-by-state implementation has begun.
The Customer Choice Act in Pennsylvania has created retail access to a competitive electric energy market. Pursuant to the Customer Choice Act, all electric utilities in Pennsylvania were required in 1998 to establish and administer retail access pilot programs to 5% of the load of each class of their customers. Beginning in January 1999, two-thirds of West Penn's customers were permitted to choose an alternate electricity supplier. Remaining West Penn customers can do so in January 2000. See Note B to the consolidated financial statements for additional information on the settlement agreement reached with the Pennsylvania PUC, which included transition costs and the ability to transfer generating assets to an affiliate at net book value.
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Allegheny Energy, Inc.
One result of the Customer Choice Act is the bifurcation of electricity supply and electricity delivery into two separate businesses. The transmission and distribution (wires) business remains under the traditional regulated ratemaking, while the electricity supply business in Pennsylvania is deregulated, and its pricing will be determined by the marketplace. The wires business will have responsibility as the electricity provider of last resort and will generally obtain its electricity supply from the market, primarily by competitive bidding. Provider of last resort service will continue to be regulated and provided at capped rates. The electricity supply business will be free to sell West Penn's generation capacity and energy in the open wholesale and retail market, subject to codes of conduct and the restriction that it may not sell at retail, except under certain conditions, in West Penn's service territory through 2003. Because of these new regulations, West Penn reorganized for 1999 into a Delivery Business (wires) and a Supply Business (marketing capacity and energy). West Penn's Delivery Business will continue to provide transmission and distribution service and will bill a Competitive Transition Charge to native load customers exercising choice.
The Maryland PSC in December 1997 issued an Order to implement retail competition in that state. The Maryland PSC's Order and its revised second Order call for a deregulation process, including a three-year phase-in beginning July 1, 2000, with recovery of prudent transition costs after mitigation. On September 10, 1998, the Maryland PSC issued a third Order which clarified certain issues and questions involved with the earlier orders. A court-approved settlement of appeals of these orders provides that the Maryland PSC orders are not final. Roundtable discussions created by the orders have been held since April 1998. The roundtable's final report to the Maryland PSC is due May 1, 1999, and the Maryland PSC's final Order in connection with the work of the roundtable is due August 1, 1999. As required by the Maryland PSC, Potomac Edison, on July 1, 1998, filed testimony in Maryland's investigation into transition costs, price protection, and unbundled rates. The filing requested recovery of transition costs and a surcharge to recover the cost of the AES Warrior Run cogeneration project which is scheduled to commence production on October 1, 1999. Hearings are scheduled to begin in April 1999. Several electricity competition bills have been introduced in the 1999 legislative session, and we continue to support bringing customer choice to Maryland customers.
Throughout 1998, a Subcommittee of the Virginia General Assembly studied electric utility restructuring and made recommendations to the General Assembly. The process led to the introduction of detailed restructuring legislation in both the House and Senate in the 1999 session. The legislation would implement a transition to choice beginning in 2002. The Senate passed the bill and referred it to the House. We expect the bill to be signed into law this year.
In December 1996, the Public Service Commission of West Virginia (W.Va. PSC) issued an Order initiating a general investigation regarding the restructuring of the regulated electric utility industry. A task force was established to further investigate restructuring issues. Legislation passed in March 1998 directed the W.Va. PSC to meet with all interested parties to develop a restructuring plan, which meets the dictates and goals of the
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Allegheny Energy, Inc.
legislation, and to then submit that plan to the Legislature for review and possible approval. The W.Va. PSC has since issued an Order setting a schedule for a series of hearings this summer on major issues such as transition costs, codes of conduct, and customer protections.
The Public Utilities Commission of Ohio (Ohio PUC) has continued informal roundtable discussions on issues concerning competition in the electric utility industry. The Governor established a legislative committee from members of both the Senate and House to further review issues regarding deregulation. Several bills on restructuring and deregulation have been introduced in the Ohio Legislature and are subject to continuing hearings and negotiations at the committee level.
Fully meeting challenges in the emerging competitive environment will be challenging for the Company unless certain outmoded and anti-competitive laws, specifically the Public Utility Holding Company Act of 1935 (PUHCA) and Section 210 of PURPA, are repealed or significantly revised. The Company continues to advocate the repeal or reform of PUHCA and PURPA on the grounds that they are obsolete and anti-competitive, and that PURPA, in particular, results in utility customers paying above- market prices for power.
Business Strategy
Generation will continue to be a core part of the Company's business. The Company's goal is to grow generation through building and buying generating facilities. The energy delivery or wires business will also continue to be a core part of the Company's business. The Company plans to expand the energy delivery business primarily through acquisitions of other electric distribution properties. Existing nonutility businesses, primarily telecommunications, that are closely tied to our core business will continue to be developed.
The Company's settlement agreement in Pennsylvania permitted the transfer of West Penn's 3,722 MW of generating capacity to a new, unregulated, wholly owned subsidiary. The Company plans to transfer these generating assets at book value. The unregulated generation will be sold in both the wholesale and retail competitive marketplace, allowing greater earnings growth potential, subject to market risk, while allowing us to capitalize on the Company's strengths in the generation business.
The Company continues to study ways to meet existing and future increases in regulated customer demand, including new and efficient electric technologies, construction of various types and sizes of generating units, increasing the efficiency and availability of Company generating facilities, reducing internal electrical use and transmission and distribution losses, and acquisition of energy and capacity from third-party suppliers.
Environmental Issues
In the normal course of business, the subsidiaries are subject to various contingencies and uncertainties relating to their operations and
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Allegheny Energy, Inc.
construction programs, including legal actions and regulations and uncertainties related to environmental matters.
The significant costs of complying with Title IV (acid rain) provisions of Phase I of the Clean Air Act Amendments of 1990 (CAAA) have been incurred and are being recovered currently from customers in rates. The Company estimates that its banked emission allowances will allow it to comply with Phase II sulfur dioxide (SO2) limits through 2005. Studies to evaluate cost- effective options to comply with Phase II limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.
Title I of the CAAA established an Ozone Transport Commission to ascertain additional nitrogen oxides (NOx) reductions to allow the Ozone Transport Region (OTR) to meet the ozone National Ambient Air Quality Standards (NAAQS). Under terms of a Memorandum of Understanding (MOU) among the OTR states, the Company's generating stations located in Maryland and Pennsylvania were 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 under Phase III of the MOU. However, this reduction will most likely be suspended by the proposed NOx State Implementation Plan (SIP) call rule discussed below. While the SIP call is being litigated, the Company is making preliminary plans to comply by applying NOx reduction facilities to existing units at various power stations. If reductions of 75% are required, installation of post-combustion control technologies would be very expensive. Pennsylvania and Maryland promulgated regulations to implement Phase II of the MOU in November 1997 and May 1998, respectively.
The Ozone Transport Assessment Group issued its final report in June 1997 that recommended the Environmental Protection Agency (EPA) consider a range of NOx controls between existing CAAA Title IV controls and the less stringent of 85% reduction from the 1990 emission rate or 0.15 lb/mmBtu. The EPA initiated the regulatory process to adopt the recommendations and issued its final NOx SIP call rule on September 24, 1998. The EPA's SIP call rule finds that 22 eastern states (including Maryland, Pennsylvania, and West Virginia) and the District of Columbia are all contributing significantly to ozone nonattainment in downwind states. The final rule declares that this downwind nonattainment will be eliminated (or sufficiently mitigated) if the upwind states reduce their NOx emissions by an amount that is precisely set by the EPA on a state-by-state basis. The final SIP call rule requires that all state-adopted NOx reduction measures must be incorporated into SIPs by September 24, 1999, and must be implemented by May 1, 2003. The Company's compliance with these requirements would require the installation of post-combustion control technologies on most, if not all, of its power stations. The Company continues to work with other coal-burning utilities and other affected constituencies in coal-producing states to challenge this EPA action.
In August 1997, eight northeastern states filed Section 126 petitions with the EPA requesting the immediate imposition of up to an 85% NOx reduction from utilities located in the Midwest and Southeast (West Virginia included). The petitions claim NOx emissions from these upwind sources are
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Allegheny Energy, Inc.
preventing their attainment with the ozone standard. In December 1997, the petitioning states and the EPA signed a Memorandum of Agreement to address these petitions in conjunction with the related SIP call mentioned above. In October 1998, the EPA proposed approval of the petitions. However, the EPA believes implementation of the NOx SIP call will alleviate the need to grant the petitions. The EPA intends to issue a final rule by April 1999.
The EPA is required by law to regularly review the NAAQS for criteria pollutants. Recent court orders in litigation by the American Lung Association have expedited these reviews. The EPA in 1996 decided not to revise the SO2 and NOx standards. Revisions to particulate matter and ozone standards were proposed by the EPA in 1996 and finalized in July 1997. State attainment plans to meet the revised standards will not be developed for several years. Also, in July 1997, the EPA proposed regional haze regulations to improve visibility in Class I federal areas (national parks and wilderness areas). If finalized, subsequent state regulations could require additional reduction of SO2 and/or NOx emissions from Company facilities. The effect on the Company of revision to any of these standards or regulations is unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase III of the MOU, SIP calls, and Section 126 petitions cannot be determined at this time. All are being challenged by rulemaking, petition, and/or the litigation process. Implementation dates are also uncertain at this time, but could be as early as 2003, which would require substantial capital expenditures in the 1999-2000 period. The Company's construction forecast includes the expenditure of $360 million of capital costs during the 1999-2003 period to comply with the SIP call.
Climate change is alleged to be the result of the atmospheric accumulation of certain gases collectively referred to as greenhouse gases (GHG), the most significant of which is carbon dioxide (CO2). Human activities, particularly combustion of fossil fuels, are alleged to be responsible for this accumulation of GHG. The Clinton Administration has signed an international treaty called the Kyoto Protocol, which will require the United States to reduce emissions of GHG by 7% from 1990 levels in the 2008-2012 time period. The United States Senate must ratify the Kyoto Protocol before it enters into force. The Senate passed a resolution in 1997 that placed two conditions on entering into any international climate change treaty. First, any treaty must include all nations, and, second, any treaty must not cause serious harm to the United States' economy. The Kyoto Protocol does not appear to satisfy either of these conditions, and, therefore, the Clinton Administration has withheld it from consideration by the Senate. Because coal combustion in power plants produces about 33% of the United States' CO2 emissions, implementation of the Kyoto Protocol would raise considerable uncertainty about the future viability of coal as a fuel source for new and existing power plants.
The utility subsidiaries previously reported that the EPA had identified them as potentially responsible parties, along with approximately 175 others, in a Superfund site subject to cleanup. A final determination has not been made for the utility subsidiaries' share of the remediation costs based on the amount of materials sent to the site. The utility subsidiaries
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Allegheny Energy, Inc.
have also been named as defendants along with multiple other defendants in pending asbestos cases involving one or more plaintiffs. The utility subsidiaries believe that provisions for liability and insurance recoveries are such that final resolution of these claims will not have a material effect on their financial position.
Independent Transmission System Operator
The Company conditionally executed a membership agreement with the Midwest Independent System Operator expressly contingent upon consummation of a proposed merger with DQE. The membership agreement was entered into on April 9, 1998, and filed with the FERC on April 13, 1998. The Company's membership status remains conditional upon the outcome of the merger. Many industry participants, including customers and regulatory authorities, believe that an entity independent of the utilities which own the transmission systems is needed to operate the systems to ensure nondiscriminatory access to the transmission systems by all users. Should these beliefs result in a mandate, the Company may either voluntarily or involuntarily sustain membership or achieve new membership in some form of Independent System Operator.
Year 2000 Readiness Disclosure
As the Year 2000 (Y2K) approaches, most organizations, including the Company, could experience serious problems related to software and various equipment with embedded chips which may not properly recognize calendar dates. To minimize such problems, the Company is proceeding with a comprehensive effort to continue operations without significant problems in 2000 and beyond. An Executive Task Force is coordinating the efforts of 24 separate Y2K Teams, representing all business and support units in the Company.
In May 1998, the North American Electric Reliability Council (NERC), of which the Company is a member, accepted a request from the United States Department of Energy to coordinate the industry's Y2K efforts. The electric utility industry and the Company have segmented the Y2K problem into the following components: - - Computer hardware and software; - - Embedded chips in various equipment; and - - Vendors and other organizations on which the Company relies for critical materials and services.
The industry's and the Company's efforts for each of these three components include assessment of the problem areas and remediation, testing, and contingency plans for critical functions for which remediation and testing are not possible or which do not provide reasonable assurance.
The NERC has established a goal of having the industry achieve a state of Y2K readiness for critical systems by June 30, 1999, and, to monitor progress, requires each utility to prepare and submit a monthly report showing progress and dated plans. By Order dated July 9, 1998, the Pennsylvania PUC initiated a proceeding requiring each utility that cannot meet a Y2K readiness date of March 31, 1999, for mission critical systems to
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Allegheny Energy, Inc.
file contingency plans by that date. The Company's Y2K plans are designed to achieve the NERC and Pennsylvania PUC goals.
Integrated electric utilities are uniquely reliant on each other to avoid, in a worst case situation, cascading failure of the entire electrical system. The Company is working with the Edison Electric Institute, the Electric Power Research Institute, the NERC, and the East Central Area Reliability Agreement group to capitalize on industry-wide experiences and to participate in industry-wide testing and contingency planning. The NERC, on January 11, 1999, issued a press release stating, based on the individual NERC reports it had received from 98% of the electrical industry, that "although there is clearly much more work to be done, we have found that North America's electric power supply and delivery systems are well on their way to being Y2K ready."
The SEC requires that each company disclose its estimate of the "most reasonably likely worst case scenario" of a negative Y2K event. Since the Company and the industry are working diligently to avoid any disruption of electric service, the Company does not believe it or its customers will experience any significant long-term disruptions of electric service. It is the Company's opinion that the "most reasonably likely worst case scenario" is that there could be isolated problems at various Company facilities or at the facilities of neighboring utilities that may have somehow escaped discovery in the identification, remediation, and testing process, and that these problems may cause isolated disruptions of service. All utilities, including the Company, have experience in the implementation of existing emergency plans and are currently expanding their emergency plans to include contingency plans to respond quickly to any such events.
The Company is aware of the importance of electricity to its customers and is using its best efforts to avoid any serious Y2K problems. Despite the Company's best efforts, including working with internal resources, external vendors, and industry associations, the Company cannot guarantee that it will be able to conduct all of its operations without Y2K interruptions. To the extent that any Y2K problem may be encountered, the Company is committed to resolution as expeditiously as possible to minimize the effect of any such event.
Expenditures for Y2K readiness are not expected to have a material effect on the Company's results of operations or financial position primarily because of the significant time and money expended over the past several years on upgrading and replacing its large mainframe computer systems and software. While the remaining Y2K work is significant, it primarily represents a labor-intensive effort of remediation, component testing, multiple systems testing, documentation, and contingency planning. While outside contractors and equipment vendors will be employed for some of the work, the Company believes it must rely on its own employees for most of the effort because of their experience with the Company's systems and equipment. The Company currently estimates that its total incremental expenditures for the Y2K effort since it began identification of Y2K costs will be within a range of $15 to $20 million. Of that amount, about $9 million has been incurred through 1998.
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Allegheny Energy, Inc.
The descriptions herein of the Company's Y2K effort are made pursuant to the Year 2000 Information and Readiness Disclosure Act. Forward-looking statements herein are made pursuant to the Private Securities Litigation Reform Act of 1995. Of necessity, the Company's Y2K effort is based on estimates of assessment, remediation, testing, and contingency planning activities. There can be no assurance that actual results will not materially differ from expectations.
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Monongahela Power Company
1998 Financial Statements
Monongahela Power Company
Part of Allegheny Energy
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Monongahela Power Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FACTORS THAT MAY AFFECT FUTURE RESULTS
This management's discussion and analysis of financial condition and results of operations contains forecast information items that are "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. These include statements with respect to deregulation activities and movements toward competition in states served by Monongahela Power Company (the Company), the proposed merger of Allegheny Energy, Inc. (Allegheny Energy) with DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., and results of operations. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially include, among other matters, electric utility restructuring, including the ongoing state and federal activities; potential Year 2000 operation problems; developments in the legislative, regulatory, and competitive environments in which the Company operates, including regulatory proceedings affecting rates charged by the Company; environmental, legislative, and regulatory changes; future economic conditions; developments relating to the proposed merger of Allegheny Energy with DQE, including expenses that may be incurred in litigation; and other circumstances that could affect anticipated revenues and costs such as significant volatility in the market price of wholesale power, unscheduled maintenance or repair requirements, weather, and compliance with laws and regulations.
SIGNIFICANT EVENTS IN 1998, 1997, AND 1996
Merger with DQE
See Page 7 and also Note B to the financial statements for information about the proposed merger of Allegheny Energy with DQE.
Internal Restructuring
In 1994, the Allegheny Energy integrated electric utility system (the System), including the Company, initiated an internal restructuring process to consolidate and re-engineer their utility operations to meet the competitive challenges of the changing electric utility industry. As a result of this process, the System reduced employment by about 1,000 employees through a voluntary separation plan, attrition and layoffs, and changed processes to obtain efficiencies to reduce operating and maintenance (O&M) costs. This process resulted in internal restructuring charges in 1996 as described in Note C to the financial statements.
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Monongahela Power Company
REVIEW OF OPERATIONS
Earnings Summary
(Millions of Dollars) Earnings 1998 1997 1996
Operations.................................... $82.4 $80.5 $76.1
Expenses related to internal restructuring activities.................................. (14.6)
Net Income.................................... $82.4 $80.5 $61.5
The increase in 1998 earnings from operations resulted from increased kilowatt-hour (kWh) sales to commercial and industrial customers and from reduced power station O&M spending. The 1996 restructuring costs resulted from internal restructuring initiated in 1994 which is described in Note C to the financial statements and Internal Restructuring on page 1. The increase in 1997 earnings from operations resulted primarily from reductions in O&M expenses from the internal restructuring process and additional actions taken during the year to achieve further O&M reductions in response to significant decreases in residential kWh sales caused primarily by mild weather. Also contributing to the increase was additional revenues due to a change in allocation of affiliated transmission services, increased generating capacity sales to an affiliate, and an interest refund on a tax-related contract settlement by the Company's 27% owned subsidiary, Allegheny Generating Company (AGC), recorded in other income as increased equity in earnings of AGC.
Sales and Revenues
Percentage changes in revenues and kWh sales in 1998 and 1997 by major retail customer classes were:
1998 vs. 1997 1997 vs. 1996 Revenues kWh Revenues kWh
Residential................. 0.5% (0.3)% (3.0)% (1.8)% Commercial.................. 6.4 5.8 (2.3) (1.0) Industrial.................. 6.0 5.5 (2.1) 4.0 Total..................... 4.0% 4.0 % (2.5)% 1.3 %
The changes in residential kWh sales, which are more weather sensitive than the other classes, were due primarily to changes in customer usage because of weather conditions. The growth in the number of residential customers was .6% and .8% in 1998 and 1997, respectively. The weather in 1997 was mild in both the early and late winter and in the summer, causing the 1.8% decrease in residential kWh sales.
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Commercial kWh sales are also affected by weather, but to a lesser extent than residential. The 5.8% increase in 1998 reflects growth in the number of customers and increased usage. The increases in industrial kWh sales in 1998 and 1997 were primarily due to increased sales to one of the Company's customers who switched an additional portion of their load requirements to the Company in September 1997.
Changes in revenues from retail customers resulted from the following:
Changes from Prior Year (Millions of Dollars) 1998 vs. 1997 1997 vs. 1996
Fuel clauses............................... $11.8 $(10.2) All other.................................. 8.7 (3.0) Net change in retail revenues............ $20.5 $(13.2)
Revenues reflect not only changes in kWh sales and base rate changes, but also any changes in revenues from fuel and energy cost adjustment clauses (fuel clauses) which have little effect on net income because increases and decreases in fuel and purchased power costs and sales of transmission services and bulk power are passed on to customers by adjustment of customers' bills through fuel clauses.
All other is the net effect of kWh sales changes due to changes in customer usage (primarily weather for residential customers), growth in the number of customers, and changes in pricing other than changes in general tariff and fuel clause rates. The increase in 1998 all other retail revenues was primarily the result of increased customer usage and growth in the number of customers. The decrease in 1997 all other retail revenues is primarily the result of mild weather in 1997.
Wholesale and other revenues were as follows:
(Millions of Dollars) 1998 1997 1996
Wholesale customers...................... $ 5.2 $ 4.9 $ 5.0 Affiliated companies..................... 77.3 83.6 74.9 Street lighting and other................ 6.9 7.1 6.6 Total wholesale and other revenues..... $89.4 $95.6 $86.5
Wholesale customers are cooperatives and municipalities that own their own distribution systems and buy all or part of their bulk power needs from the Company under Federal Energy Regulatory Commission (FERC) regulation. Competition in the wholesale market for electricity was initiated by the National Energy Policy Act of 1992, 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. All of the Company's wholesale customers have signed contracts to remain as customers until December 1, 2000.
Revenues from affiliated companies represent sales of energy and intercompany allocations of generating capacity, generation spinning reserves, and
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Monongahela Power Company
transmission services pursuant to a power supply agreement among the Company and the other regulated utility subsidiaries of Allegheny Energy. The decrease in such revenues in 1998 resulted primarily from decreased generating capacity sales ($4.7 million). The increase in 1997 resulted primarily from an increase in the allocation of transmission services revenues and increased generating capacity sales ($6.5 million).
Bulk power transactions include sales of bulk power and transmission services to power marketers and other utilities. Bulk power and transmission services sales for 1998, 1997, and 1996 were as follows:
1998 1997 1996 KWh Transactions (in billions): Bulk power............................... .3 .3 .2 Transmission services to nonaffiliated companies................ 1.9 3.0 4.2 Total................................ 2.2 3.3 4.4
Revenues (in millions): Bulk power............................... $ 8.5 $ 7.3 $ 4.8 Transmission services to nonaffiliated companies................ 11.3 10.0 12.6 Total................................ $19.8 $17.3 $17.4
The 1998 increase in revenues from bulk power was due to increased sales that occurred primarily in the second quarter as a result of warm weather which increased the demand and price for energy. In 1998, revenues from transmission services were affected by a revenue refund resulting from a reduction in the Company's standard transmission rate and rates for ancillary services which were recently approved by the FERC. A provision of $1.7 million for these rate reductions was recorded in 1998, with the revenues to be refunded to customers in the first quarter of 1999.
Revenues from transmission services to nonaffiliated companies in 1998 increased, despite decreased transmission services activity. The increase in revenues was due in part to transmission services' reservation charges paid to the Company by others for the right to transmit energy. Transmission services activity was affected as a result of some of the reservations to transmit energy not being used. Revenues from transmission services to nonaffiliated companies in 1997 decreased due to reduced demand, primarily because of mild weather.
In June and July 1998, certain events combined to produce significant volatility in the spot prices for electricity at the wholesale level. These events included extremely hot weather, Midwest generation unit outages, and transmission constraints. Wholesale prices for electricity rose from a normal range of from $25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per mWh. The costs of purchased power and revenues from sales to power marketers and other utilities, including transmission services, are currently recovered from or credited to customers under fuel and energy cost recovery procedures. The impact to the fuel and energy cost recovery clauses, either positively or negatively, depends on whether the Company is a net
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Monongahela Power Company
buyer or seller of electricity during such periods. The impact of such price volatility in June and the third quarter of 1998 was insignificant to the Company because changes are passed through to customers through operation of fuel clauses.
Operating Expenses
Fuel expenses increased 1.9% in 1998 due primarily to an increase in kWhs generated. The 4.1% increase in 1997 was caused by a 2.4% increase in kWh's generated, a 1.4% increase in average fuel prices, and a .3% increase in the average heat rate of the generating stations. The increases in kWh's generated in 1998 and 1997 were primarily the result of increased retail sales and bulk power sales to power marketers and other utilities.
Purchased power and exchanges, net, represents power purchases from and exchanges with other companies and purchases from qualified facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA), capacity charges paid to AGC, and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and consists of the following items:
(Millions of Dollars) 1998 1997 1996
Nonaffiliated transactions: Purchased power: From PURPA generation*................ $65.5 $69.8 $ 69.1 Other................................. 11.6 9.6 11.3 Power exchanges, net.................... (.2) .1 .9 Affiliated transactions: AGC capacity charges.................... 18.4 18.5 20.2 Energy and spinning reserve charges..... .3 .3 .1 Purchased power and exchanges, net.... $95.6 $98.3 $101.6
*PURPA cost (cents per kWh) 5.1 5.3 5.3
The decrease in purchased power from PURPA generation in 1998 was due primarily to reduced generation at hydroelectric plants due to river flow. The increase in other purchased power in 1998 resulted primarily from increased purchases for sales. An increase in price caused by volatility in the spot prices for electricity at the wholesale level in the second and third quarters of 1998 also contributed to the increase. The decrease in other purchased power in 1997 was a result of decreased demand due to decreased sales related to mild 1997 weather.
None of the Company's purchased power contracts are capitalized since there are no minimum payment requirements absent associated kWh generation and under a regulated environment recovery of the costs are reasonably assured.
The increase in other operation expenses in 1998 resulted primarily from increases in salaries and wages and employee benefits, increased property insurance expense due in part to a prior period adjustment, and an increase in expense related to Year 2000 readiness. Other operation expenses in 1997
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Monongahela Power Company
include $1.7 million for increased allowances for uncollectible accounts. Nevertheless, other operation expense decreased in 1997 because of a reduction in embedded expenses achieved through the 1996 internal restructuring process.
The decrease in maintenance expenses in 1998 was due primarily to a management program to postpone such expenses for the year in response to limited sales growth in the first quarter due to the warm winter weather. The Company is postponing these expenses primarily by extending the time between maintenance outages. The 1997 decrease in maintenance expenses resulted from reduced expenses achieved through internal restructuring efforts and other cost controls. 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.
Internal restructuring charges in 1996 resulted from internal restructuring activities, which have been completed.
Depreciation expense in 1998 and 1997 increased $2.0 million and $1.1 million, respectively, due to increased investment.
Taxes other than income taxes increased $6.0 million in 1998 due primarily to West Virginia Business and Occupation Taxes resulting from an adjustment for a prior period and increased property taxes. The decrease in 1997 taxes other than income taxes was because of a decrease in gross receipts taxes due to lower retail revenues and lower FICA taxes due to the Company's prior year internal restructuring.
The increases in federal and state income taxes were primarily due to increased income before income taxes. Note D to the financial statements provides a further analysis of income tax expenses.
The decrease in other income, net, of $2.4 million in 1998 and the increase in 1997 of $1.7 million was primarily due to a 1997 interest refund on a tax-related contract settlement ($2.2 million, net of taxes) received by the Company's subsidiary, AGC.
The decrease in interest on long-term debt in 1998 of $3.7 million resulted from reduced long-term debt and lower interest rates. Other interest expense reflects changes in the levels of short-term debt maintained by the Company throughout the year, as well as the associated interest rates.
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Monongahela Power Company
FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES
Liquidity and Capital Requirements
To meet cash needs 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 financings depend upon the financial health of the companies seeking those funds and market conditions.
Construction expenditures in 1998 were $73 million and, for 1999 and 2000, are estimated at $76 million and $79 million, respectively. The 1999 and 2000 estimated expenditures include $13 million and $20 million, respectively, for construction of environmental control technology. It is the Company's goal to constrain future construction spending 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 Flow
Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $108 million in 1998, compared with $65 million in 1997. Reduced 1997 cash flow was primarily the result of the payment of internal restructuring and other liabilities. Current rate levels and reduced levels of construction expenditures permitted the Company to finance all of its construction expenditures in 1998 and nearly all in 1997 with internal cash flow. As described under Environmental Issues starting on page 9, the Company could potentially face significant mandated increases in construction expenditures and operating costs related to environmental issues. Whether the Company can continue to meet the majority of its construction needs with internally generated cash is largely dependent upon the outcome of these issues.
Financing
Short-term debt is used to meet temporary cash needs. Short-term debt, including notes payable to affiliates under the money pool, decreased $9.3 million to $49.0 million in 1998. At December 31, 1998, the Company had Securities and Exchange Commission (SEC) authorization to issue up to $106 million of short-term debt. The Company and its regulated affiliates use an Allegheny Energy 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 meeting its 1999 cash needs through internal cash generation, cash on hand, and short-term borrowings as necessary.
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Monongahela Power Company
SIGNIFICANT CONTINUING ISSUES
Proposed Merger with DQE
Allegheny Energy believes that DQE's basis for seeking to terminate the merger (described in Note B to the financial statements) is without merit. Accordingly, Allegheny Energy continues to seek the remaining regulatory approvals from the Department of Justice and the SEC. It is not likely either agency will act on the request unless Allegheny Energy obtains judicial relief requiring DQE to move forward.
Electric Energy Competition
The electricity supply segment of the electric utility industry in the United States is in the midst of becoming a competitive marketplace. The Energy Policy Act of 1992 began the process of deregulating the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. Since 1992, the wholesale electricity market has become increasingly competitive as companies began to engage in nationwide power trading. In addition, some states have taken active steps toward allowing retail customers the right to choose their electricity supplier. All of the states served by the utility subsidiaries of Allegheny Energy have investigated or implemented retail access to alternate electricity suppliers. The Company has been an advocate of federal legislation to create competition in the retail electricity markets to avoid regional dislocations and ensure level playing fields. In the absence of federal legislation, state-by-state implementation has begun.
The Company has franchised regulated customers in West Virginia and Ohio.
In West Virginia, the Public Service Commission of West Virginia (W.Va. PSC) issued an Order in December 1996 initiating a general investigation regarding the restructuring of the regulated electric utility industry. A task force was established to further investigate restructuring issues. Legislation passed in March 1998 directed the W.Va. PSC to meet with all interested parties to develop a restructuring plan, which meets the dictates and goals of the legislation, and to then submit that plan to the Legislature for review and possible approval. The W.Va. PSC has since issued an Order setting a schedule for a series of hearings this summer on major issues such as transition costs, codes of conduct, and customer protections.
In Ohio, the Public Utilities Commission of Ohio has continued informal roundtable discussions on issues concerning competition in the electric utility industry. The Governor established a legislative committee from members of both the Senate and House to further review issues regarding deregulation. Several bills on restructuring and deregulation have been introduced in the Ohio Legislature and are subject to continuing hearings and negotiations at the committee level.
The status of electric energy competition in Maryland, Virginia, and Pennsylvania in which affiliates of the Company serve are as follows.
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Monongahela Power Company
In Maryland, the Maryland Public Service Commission (Maryland PSC) in December 1997 issued an Order to implement retail competition in that state. The Maryland PSC's Order and its revised second Order, call for a deregulation process, including a three-year phase-in beginning July 1, 2000, with recovery of prudent transition costs after mitigation. The Maryland PSC subsequently issued a third Order which clarified certain issues and questions involved with the earlier Orders. A court-approved settlement of appeals of these Orders provides that the Maryland PSC Orders are not final. The Company's Maryland affiliate, The Potomac Edison Company (Potomac Edison), is subject to these orders and appeals.
In Virginia, a Subcommittee of the Virginia General Assembly studied electric utility restructuring and made recommendations to the General Assembly throughout 1998. The process led to the introduction of detailed restructuring legislation in both the House and Senate in the 1999 session. The legislation would implement a transition to choice beginning in 2002. The Senate passed the bill and referred it to the House. It is expected that the bill will be signed into law this year. The Company's affiliate, Potomac Edison, is subject to this action.
In Pennsylvania, the Electricity Generation Customer Choice and Competition Act has created retail access to a competitive electric energy market. The Company's Pennsylvania affiliate, West Penn Power Company (West Penn), is subject to this Act. Beginning in January 1999, two-thirds of West Penn's customers were permitted to choose an alternate electricity supplier. Remaining West Penn customers can do so in January 2000. As a result of a Pennsylvania Public Utility Commission (Pennsylvania PUC) Order and settlement agreement, West Penn determined that under the provisions of Statement of Financial Accounting Standards No. 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71," in 1998 an extraordinary charge of $466.9 million ($275.4 million after taxes) was required to reflect a write-off of certain disallowances. In addition, charges of $40.3 million ($23.7 million after taxes) related to West Penn's revenue refund and energy program payments were also recorded.
Fully meeting challenges in the emerging competitive environment will be challenging for the Company unless certain outmoded and anti-competitive laws, specifically the Public Utility Holding Company Act of 1935 (PUHCA) and Section 210 of PURPA, are repealed or significantly revised. Allegheny Energy continues to advocate the repeal or reform of PUHCA and PURPA on the grounds that they are obsolete and anti-competitive, and that PURPA, in particular, results in utility customers paying above-market prices for power.
Business Strategy
Generation will continue to be a core part of Allegheny Energy's business. Allegheny Energy's goal is to grow generation through building and buying generating facilities. The energy delivery or wires business will also continue to be a core part of Allegheny Energy's business. Allegheny Energy plans to expand the energy delivery business primarily through acquisitions of other electric distribution properties.
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Monongahela Power Company
The settlement agreement for the Company's affiliate, West Penn, in Pennsylvania permitted the transfer of its 3,722 MW of generating capacity to a new, unregulated company that is expected to be a wholly owned subsidiary of West Penn. West Penn plans to transfer these generating assets at book value. The unregulated generation will be sold in both the wholesale and retail competitive marketplace, allowing greater earnings growth potential, subject to market risk, while allowing Allegheny Energy to capitalize on its strengths in the generation business.
Allegheny Energy continues to study ways to meet existing and future increases in regulated customer demand, including new and efficient electric technologies, construction of various types and sizes of generating units, increasing the efficiency and availability of Company generating facilities, reducing internal electrical use and transmission and distribution losses, and acquisition of energy and capacity from third-party suppliers.
Environmental Issues
In the normal course of business, the Company is subject to various contingencies and uncertainties relating to its operations and construction programs, including legal actions and regulations and uncertainties related to environmental matters. The significant costs of complying with Title IV (acid rain) provisions of Phase I of the Clean Air Act Amendments of 1990 (CAAA) have been incurred and are being recovered currently from customers in rates. The Company estimates that its banked emission allowances will allow it to comply with Phase II sulfur dioxide (SO2) limits through 2005. Studies to evaluate cost- effective options to comply with Phase II limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.
Title I of the CAAA established an Ozone Transport Commission to ascertain additional nitrogen oxides (NOx) reductions to allow the Ozone Transport Region (OTR) to meet the ozone National Ambient Air Quality Standards (NAAQS). Under terms of a Memorandum of Understanding (MOU) among the OTR states, the Company's generating station located in Pennsylvania was 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 under Phase III of the MOU. However, this reduction will most likely be suspended by the proposed NOx State Implementation Plan (SIP) call rule discussed below. While the SIP call is being litigated, the Company is making preliminary plans to comply by applying NOx reduction facilities to existing units at various power stations. If reductions of 75% are required, installation of post-combustion control technologies would be very expensive. Pennsylvania promulgated regulations to implement Phase II of the MOU in November 1997.
The Ozone Transport Assessment Group issued its final report in June 1997 that recommended the Environmental Protection Agency (EPA) consider a range of NOx controls between existing CAAA Title IV controls and the less stringent of 85% reduction from the 1990 emission rate or 0.15 lb/mmBtu. The EPA initiated the regulatory process to adopt the recommendations and issued its final NOx SIP call rule on September 24, 1998. The EPA's SIP call rule finds that 22 eastern states (including Maryland, Pennsylvania, and West Virginia) and the District of Columbia are all contributing significantly to ozone
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Monongahela Power Company
nonattainment in downwind states. The final rule declares that this downwind nonattainment will be eliminated (or sufficiently mitigated) if the upwind states reduce their NOx emissions by an amount that is precisely set by the EPA on a state-by-state basis. The final SIP call rule requires that all state-adopted Nox reduction measures must be incorporated into SIPs by September 24, 1999, and must be implemented by May 1, 2003. The Company's compliance with these requirements would require the installation of post-combustion control technologies on most, if not all, of its power stations. The Company continues to work with other coal-burning utilities and other affected constituencies in coal-producing states to challenge this EPA action.
In August 1997, eight northeastern states filed Section 126 petitions with the EPA requesting the immediate imposition of up to an 85% NOx reduction from utilities located in the Midwest and Southeast (West Virginia included). The petitions claim NOx emissions from these upwind sources are preventing their attainment with the ozone standard. In December 1997, the petitioning states and the EPA signed a Memorandum of Agreement to address these petitions in conjunction with the related SIP call mentioned above. In October 1998, the EPA proposed approval of the petitions. However, the EPA believes implementation of the NOx SIP call will alleviate the need to grant the petitions. The EPA intends to issue a final rule by April 1999.
The EPA is required by law to regularly review the NAAQS for criteria pollutants. Recent court orders in litigation by the American Lung Association have expedited these reviews. The EPA in 1996 decided not to revise the SO2 and NOx standards. Revisions to particulate matter and ozone standards were proposed by the EPA in 1996 and finalized in July 1997. State attainment plans to meet the revised standards will not be developed for several years. Also, in July 1997, the EPA proposed regional haze regulations to improve visibility in Class I federal areas (national parks and wilderness areas). If finalized, subsequent state regulations could require additional reduction of SO2 and/or NOx emissions from Company facilities. The effect on the Company of revision to any of these standards or regulations is unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase III of the MOU, SIP calls, and Section 126 petitions cannot be determined at this time. All are being challenged by rulemaking, petition, and/or the litigation process. Implementation dates are also uncertain at this time, but could be as early as 2003, which would require substantial capital expenditures in the 1999- 2000 period. The Company's construction forecast includes the expenditure of $96 million of capital costs during the 1999-2003 period to comply with the SIP call.
Climate change is alleged to be the result of the atmospheric accumulation of certain gases collectively referred to as greenhouse gases (GHG), the most significant of which is carbon dioxide (CO2). Human activities, particularly combustion of fossil fuels, are alleged to be responsible for this accumulation of GHG. The Clinton Administration has signed an international treaty called the Kyoto Protocol, which will require the United States to reduce emissions of GHG by 7% from 1990 levels in the 2008-2012 time period. The United States Senate must ratify the Kyoto Protocol before it enters into force. The Senate passed a resolution in 1997 that placed two conditions on
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Monongahela Power Company
entering into any international climate change treaty. First, any treaty must include all nations, and, second, any treaty must not cause serious harm to the Unites States' economy. The Kyoto Protocol does not appear to satisfy either of these conditions, and, therefore, the Clinton Administration has withheld it from consideration by the Senate. Because coal combustion in power plants produces about 33% of the Unites States' CO2 emissions, implementation of the Kyoto Protocol would raise considerable uncertainty about the future viability of coal as a fuel source for new and existing power plants.
The Company previously reported that the EPA had identified the Company and its regulated affiliates as potentially responsible parties, along with approximately 175 others, 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 and its regulated affiliates have also been named as defendants along with multiple other defendants in pending asbestos cases involving one or more plaintiffs. The Company believes that provisions for liability and insurance recoveries are such that final resolution of these claims will not have a material effect on its financial position.
Independent Transmission System Operator
Allegheny Energy conditionally executed a membership agreement with the Midwest Independent System Operator expressly contingent upon consummation of a proposed merger with DQE. The membership agreement was entered into on April 9, 1998, and filed with the FERC on April 13, 1998. Allegheny Energy's membership status remains conditional upon the outcome of the merger. Many industry participants, including customers and regulatory authorities, believe that an entity independent of the utilities which own the transmission systems is needed to operate the systems to ensure nondiscriminatory access to the transmission systems by all users. Should these beliefs result in a mandate, Allegheny Energy may either voluntarily or involuntarily sustain membership or achieve new membership in some form of Independent System Operator.
Year 2000 Readiness Disclosure
As the Year 2000 (Y2K) approaches, most organizations, including the Company, could experience serious problems related to software and various equipment with embedded chips which may not properly recognize calendar dates. To minimize such problems, the Company and its affiliates in the System are proceeding with a comprehensive effort to continue operations without significant problems in 2000 and beyond. An Executive Task Force is coordinating the efforts of 24 separate Y2K Teams, representing all business and support units in the System.
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Monongahela Power Company
In May 1998, the North American Electric Reliability Council (NERC), of which the System is a member, accepted a request from the United States Department of Energy to coordinate the industry's Y2K efforts. The electric utility industry and the System have segmented the Y2K problem into the following components:
- - Computer hardware and software;
- - Embedded chips in various equipment; and
- - Vendors and other organizations on which the System relies for critical materials and services.
The industry's and the System's efforts for each of these three components include assessment of the problem areas and remediation, testing, and contingency plans for critical functions for which remediation and testing are not possible or which do not provide reasonable assurance.
The NERC has established a goal of having the industry achieve a state of Y2K readiness for critical systems by June 30, 1999, and, to monitor progress, requires each utility to prepare and submit a monthly report showing progress and dated plans. By Order dated July 9, 1998, the Pennsylvania PUC initiated a proceeding requiring each utility that cannot meet a Y2K readiness date of March 31, 1999, for mission critical systems to file contingency plans by that date. The System's Y2K plans are designed to achieve the NERC and Pennsylvania PUC goals.
Integrated electric utilities are uniquely reliant on each other to avoid, in a worst case situation, cascading failure of the entire electrical system. The System is working with the Edison Electric Institute, the Electric Power Research Institute, the NERC, and the East Central Area Reliability Agreement group to capitalize on industry-wide experiences and to participate in industry-wide testing and contingency planning. The NERC, on January 11, 1999, issued a press release stating, based on the individual NERC reports it had received from 98% of the electrical industry, that "although there is clearly much more work to be done, we have found that North America's electric power supply and delivery systems are well on their way to being Y2K ready."
The SEC requires that each company disclose its estimate of the "most reasonably likely worst case scenario" of a negative Y2K event. Since the Company and the industry are working diligently to avoid any disruption of electric service, the Company does not believe it or its customers will experience any significant long- term disruptions of electric service. It is the Company's opinion that the "most reasonably likely worst case scenario" is that there could be isolated problems at various Company facilities or at the facilities of neighboring utilities that may have somehow escaped discovery in the identification, remediation, and testing process, and that these problems may cause isolated disruptions of service. All utilities, including the Company, have experience in the implementation of existing emergency plans and are currently expanding their emergency plans to include contingency plans to respond quickly to any such events.
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Monongahela Power Company
The Company is aware of the importance of electricity to its customers and is using its best efforts to avoid any serious Y2K problems. Despite the Company's best efforts, including working with internal resources, external vendors, and industry associations, the Company cannot guarantee that it will be able to conduct all of its operations without Y2K interruptions. To the extent that any Y2K problem may be encountered, the Company is committed to resolution as expeditiously as possible to minimize the effect of any such event.
Expenditures for Y2K readiness are not expected to have a material effect on the Company's results of operations or financial position primarily because of the significant time and money expended over the past several years on upgrading and replacing its large mainframe computer systems and software. While the remaining Y2K work is significant, it primarily represents a labor-intensive effort of remediation, component testing, multiple systems testing, documentation, and contingency planning. While outside contractors and equipment vendors will be employed for some of the work, the Company believes it must rely on System employees for most of the effort because of their experience with the Company's systems and equipment. The Company currently estimates that its total incremental expenditures for the Y2K effort since it began identification of Y2K costs will be within a range of $4 to $5 million. Of that amount, about $2 million has been incurred through 1998.
The descriptions herein of the Company's Y2K effort are made pursuant to the Year 2000 Information and Readiness Disclosure Act. Forward-looking statements herein are made pursuant to the Private Securities Litigation Reform Act of 1995. Of necessity, the Company's Y2K effort is based on estimates of assessment, remediation, testing, and contingency planning activities. There can be no assurance that actual results will not materially differ from expectations.
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The Potomac Edison Company
1998 Financial Statements
The Potomac Edison Company
Part of Allegheny Energy
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The Potomac Edison Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FACTORS THAT MAY AFFECT FUTURE RESULTS
This management's discussion and analysis of financial condition and results of operations contains forecast information items that are "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. These include statements with respect to deregulation activities and movements toward competition in states served by The Potomac Edison Company (the Company), the proposed merger of Allegheny Energy, Inc. (Allegheny Energy) with DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., and results of operations. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially include, among other matters, electric utility restructuring, including the ongoing state and federal activities; potential Year 2000 operation problems; developments in the legislative, regulatory, and competitive environments in which the Company operates, including regulatory proceedings affecting rates charged by the Company; environmental, legislative, and regulatory changes; future economic conditions; developments relating to the proposed merger of Allegheny Energy with DQE, including expenses that may be incurred in litigation; and other circumstances that could affect anticipated revenues and costs such as significant volatility in the market price of wholesale power, unscheduled maintenance or repair requirements, weather, and compliance with laws and regulations.
SIGNIFICANT EVENTS IN 1998, 1997, AND 1996
Merger with DQE
See Page 8 and also Note B to the financial statements for information about the proposed merger of Allegheny Energy with DQE.
Maryland Settlement and Deregulation
The Company reached a settlement agreement with various parties on the Office of People's Counsel's petition for a reduction in the Company's Maryland rates. Further information on the settlement agreement is provided under Sales and Revenues starting on page 2.
On July 1, 1998, the Company filed testimony in Maryland's investigation into transition costs, price protection, and unbundled rates. See Electric Energy Competition on page 8 for more information regarding the restructuring in Maryland.
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The Potomac Edison Company
Internal Restructuring
In 1994, the Allegheny Energy integrated electric utility system (the System), including the Company, initiated an internal restructuring process to consolidate and re-engineer their utility operations to meet the competitive challenges of the changing electric utility industry. As a result of this process, the System reduced employment by about 1,000 employees through a voluntary separation plan, attrition and layoffs, and changed processes to obtain efficiencies to reduce operating and maintenance (O&M) costs. This process resulted in internal restructuring charges in 1996 as described in Note C to the financial statements.
REVIEW OF OPERATIONS
Earnings Summary
Earnings (Millions of Dollars) 1998 1997 1996
Operations................................... $101.5 $95.8 $94.7
Expenses related to internal restructuring activities................... 16.5
Net Income................................... $101.5 $95.8 $78.2
The increase in 1998 earnings from operations resulted from increased kilowatt-hour (kWh) sales to retail customers and from reduced power station O&M spending. The 1996 restructuring costs resulted from internal restructuring initiated in 1994 which is described in Note C to the financial statements and Internal Restructuring on page 1. The increase in 1997 earnings from operations resulted primarily from reductions in O&M expenses from the internal restructuring process and additional actions taken during the year to achieve further O&M reductions in response to significant decreases in kWh sales to residential customers caused primarily by mild weather. Also contributing to the increase was additional revenues due to a change in allocation of affiliated transmission services and an interest refund on a tax-related contract settlement by the Company's 28% owned subsidiary, Allegheny Generating Company (AGC), recorded in other income as increased equity in earnings of AGC.
Sales and Revenues
Percentage changes in revenues and kWh sales in 1998 and 1997 by major retail customer classes were: 1998 vs. 1997 1997 vs. 1996 Revenues kWh Revenues kWh
Residential................... 3.1% 2.6% (7.5)% (6.7)% Commercial.................... 5.9 7.2 1.3 1.9 Industrial.................... 4.3 5.9 .7 .5 Total....................... 4.1% 5.0% (3.2)% (1.9)%
The changes in residential kWh sales, which are more weather sensitive than the other classes, were due primarily to changes in customer usage because of
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The Potomac Edison Company
weather conditions. The growth in the number of residential customers was 1.9% and 1.8% in 1998 and 1997, respectively. The weather in 1997 was mild in both the early and late winter and in the summer, causing the 6.7% decrease in residential kWh sales.
Commercial kWh sales are also affected by weather, but to a lesser extent than residential. The 7.2% increase in 1998 reflects increased usage due to weather and commercial activity as well as growth in the number of customers. The 1.9% increase in 1997 reflects growth in the number of customers.
The increases in industrial kWh sales in 1998 and 1997 reflect a trend of continued economic growth in the service territory. The increase in 1998 also reflects increased sales to paper and printing customers and to the Eastalco aluminum reduction plant.
On August 7, 1998, the Virginia State Corporation Commission (Virginia SCC) approved an agreement reached between the Company and the Staff of the Virginia SCC which reduced base rates for Virginia customers beginning September 1, 1998, by about $2.5 million annually. The review of rates was required by an annual information filing in Virginia.
In 1999, revenues will reflect a reduction for a settlement agreement with various parties on the Maryland Office of People's Counsel's petition for a reduction in the Company's Maryland rates. The agreement, which includes recognition of costs to be incurred from the Applied Energy Services (AES) Warrior Run cogeneration project being developed under the Public Utility Regulatory Policies Act of 1978 (PURPA), was approved by the Maryland Public Service Commission (Maryland PSC) on October 27, 1998. Under the terms of that agreement, the Company will increase its rates about 4% ($13 million) in each of the years 1999, 2000, and 2001 (a $39 million annual effect in 2001). The increases are designed to recover additional costs of about $131 million over the period 1999-2001 for capacity purchases from the AES Warrior Run cogeneration project, net of alleged over- earnings of $52 million for the same period. The net effect of these changes over the 1999-2001 time frame results in a pre-tax income reduction of $12 million in 1999, $18 million in 2000, and $22 million in 2001. In addition, the settlement requires that the Company share, on a 50% customer, 50% shareholder basis, earnings above a return on equity of 11.4% for 1999-2001. This sharing will occur through an annual true-up. Changes in revenues from retail customers resulted from the following:
Changes from Prior Year (Millions of Dollars) 1998 vs. 1997 1997 vs. 1996
Fuel clauses............................. $10.9 $ (9.6) All other................................ 15.4 (11.4) Net change in retail revenues.......... $26.3 $(21.0)
Revenues reflect not only changes in kWh sales and base rate changes, but also any changes in revenues from fuel and energy cost adjustment clauses (fuel clauses) which have little effect on net income because increases and decreases in fuel and purchased power costs and sales of transmission services and bulk power are passed on to customers by adjustment of customers' bills through fuel clauses.
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The Potomac Edison Company
All other is the net effect of kWh sales changes due to changes in customer usage (primarily weather for residential customers), growth in the number of customers, and changes in pricing other than changes in general tariff and fuel clause rates. The increase in 1998 all other retail revenues was primarily the result of increased customer usage and growth in the number of customers. The decrease in 1997 all other retail revenues is primarily the result of mild weather in 1997.
Wholesale and other revenues were as follows:
(Millions of Dollars) 1998 1997 1996
Wholesale customers....................... $23.5 $26.6 $29.1 Affiliated companies...................... 9.4 9.7 2.5 Street lighting and other................. 5.5 2.6 3.3 Total wholesale and other revenues...... $38.4 $38.9 $34.9
Wholesale customers are cooperatives and municipalities that own their own distribution systems and buy all or part of their bulk power needs from the Company under Federal Energy Regulatory Commission (FERC) regulation. Competition in the wholesale market for electricity was initiated by the National Energy Policy Act of 1992, 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. Five-year contracts have been signed (one in 1997 with an expiration date in 2002 with estimated annual revenues of $3 million, and four in 1998 with expiration dates in 2003 with estimated annual revenues of $19 million) with the Company's wholesale customers allowing the Company to continue as their wholesale supplier. The decrease in wholesale revenues in 1998 was primarily due to the mild 1998 winter weather. The decrease in wholesale revenues in 1997 was primarily due to the reduced electricity requirements of one wholesale customer caused by the shut-down in early 1997 of a large fiber plant on the wholesale customer's system.
Revenues from affiliated companies represent sales of energy and intercompany allocations of generating capacity, generation spinning reserves, and transmission services pursuant to a power supply agreement among the Company and the other regulated utility subsidiaries of Allegheny Energy. The increase in such revenues in 1997 resulted primarily from an increase in the allocation of transmission services revenues ($5.3 million) to the Company.
The increases in street lighting and other revenues in 1998 were primarily due to the recording in 1998 of pole attachment revenues for 1998 and 1997.
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The Potomac Edison Company
Bulk power transactions include sales of bulk power and transmission services to power marketers and other utilities. Bulk power and transmission services sales for 1998, 1997, and 1996 were as follows:
1998 1997 1996 KWh Transactions (in billions): Bulk power................................ .4 .4 .3 Transmission services to nonaffiliated companies................. 2.5 4.0 5.6 Total................................. 2.9 4.4 5.9
Revenues (in millions): Bulk power................................ $11.7 $10.0 $ 7.6 Transmission services to nonaffiliated companies................. 14.7 13.6 16.9 Total................................. $26.4 $23.6 $24.5
The 1998 increase in revenues from bulk power was due to increased sales that occurred primarily in the second quarter as a result of warm weather which increased the demand and price for energy. In 1998, revenues from transmission services were affected by a revenue refund resulting from a reduction in the Company's standard transmission rate and rates for ancillary services which were recently approved by the FERC. A provision of $2.2 million for these rate reductions was recorded in 1998, with the revenues to be refunded to customers in the first quarter of 1999.
Revenues from transmission services to nonaffiliated companies in 1998 increased, despite decreased transmission services activity. The increase in revenues was due in part to transmission services' reservation charges paid to the Company by others for the right to transmit energy. Transmission services activity was affected as a result of some of the reservations to transmit energy not being used. Revenues from transmission services to nonaffiliated companies in 1997 decreased due to reduced demand, primarily because of mild weather.
In June and July 1998, certain events combined to produce significant volatility in the spot prices for electricity at the wholesale level. These events included extremely hot weather, Midwest generation unit outages, and transmission constraints. Wholesale prices for electricity rose from a normal range of from $25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per mWh. The costs of purchased power and revenues from sales to power marketers and other utilities, including transmission services, are currently recovered from or credited to customers under fuel and energy cost recovery procedures. The impact to the fuel and energy cost recovery clauses, either positively or negatively, depends on whether the Company is a net buyer or seller of electricity during such periods. The impact of such price volatility in June and the third quarter of 1998 was insignificant to the Company because changes are passed through to customers through operation of fuel clauses.
Operating Expenses
Fuel expenses increased 2.1% in each of the years 1998 and 1997 due to increases in kWhs generated. The increases in kWhs generated were primarily the result of increased bulk power sales to power marketers and other utilities and in 1998 also due to increased sales to retail customers.
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The Potomac Edison Company
Purchased power and exchanges, net, represents power purchases from and exchanges with other companies, capacity charges paid to AGC, and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and consists of the following items:
(Millions of Dollars) 1998 1997 1996
Nonaffiliated transactions: Purchased power.......................... $ 15.2 $ 13.2 $ 14.8 Power exchanges, net..................... (.1) 1.7 Affiliated transactions: AGC capacity charges..................... 23.8 25.5 26.9 Other affiliated capacity charges........ 42.9 50.8 47.7 Energy and spinning reserve charges...... 56.5 50.7 49.9 Purchased power and exchanges, net..... $138.3 $140.2 $141.0
The increase in purchased power in 1998 resulted primarily from increased purchases for sales. An increase in price caused by volatility in the spot prices for electricity at the wholesale level in the second and third quarters of 1998 also contributed to the increase. Purchased power in 1997 decreased because of decreased demand due to decreased sales to retail customers related to mild 1997 weather. The increase in affiliated energy and spinning reserve charges was due to an increase in retail kWh sales.
The AES Warrior Run PURPA cogeneration project in the Company's Maryland service territory, scheduled to commence generation in October 1999, will increase the cost of power purchases $60 million or more annually. The settlement, described under Sales and Revenues starting on page 2, is designed to recover all such costs through 2001.
The increase in other operation expenses in 1998 resulted primarily from increased expenses related to competition in Maryland ($1.6 million), an increase in expense related to Year 2000 Readiness, and increases in salaries and wages and employee benefits. These expenses were partially offset by a reduction in expenses related to provisions for uninsured claims. Other operation expenses in 1997 include $1.2 million for increased allowances for uncollectible accounts. Nevertheless, other operation expense decreased in 1997 because of a reduction in embedded expenses achieved through the 1996 internal restructuring process.
The decrease in maintenance expenses in 1998 was due primarily to a management program to postpone such expenses for the year in response to limited sales growth in the first quarter due to the warm winter weather. The Company is postponing these expenses primarily by extending the time between maintenance outages. The 1997 decrease in maintenance expenses resulted from reduced expenses achieved through internal restructuring efforts and other cost controls. 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
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The Potomac Edison Company
in service without a major overhaul and the amount of work found necessary when the equipment is dismantled.
Internal restructuring charges in 1996 resulted from internal restructuring activities, which have been completed.
Depreciation expense increases resulted from increased investment.
The increase in taxes other than income taxes of $2 million in 1998 was primarily due to an increase in gross receipts taxes resulting from greater revenues from retail customers and increased property taxes. The increase in taxes other than income taxes of $1.8 million in 1997 was due to increased property taxes and capital stock and franchise taxes related to an increase in the assessment of property in Maryland.
The 1998 and 1997 increases in federal and state income taxes were primarily due to increased income before taxes. Note D to the financial statements provides a further analysis of income tax expenses.
The decrease in allowance for other than borrowed funds used during construction of $1.1 million in 1998 resulted primarily from adjustments of prior periods.
The decrease in other income, net, of $4.7 million in 1998 and the increase in 1997 of $2.2 million was primarily due to a 1997 interest refund on a tax-related contract settlement ($2.5 million, net of taxes) received by the Company's subsidiary, AGC.
The decrease in interest on long-term debt in 1998 of $1.6 million resulted from reduced long-term debt and lower interest rates. 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.
FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES
Liquidity and Capital Requirements
To meet cash needs 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 financings depend upon the financial health of the companies seeking those funds and market conditions.
Construction expenditures in 1998 were $61 million and, for 1999 and 2000, are estimated at $86 million and $98 million, respectively. The 1999 and 2000 estimated expenditures include $17 million and $22 million, respectively, for construction of environmental control technology. It is the Company's goal to constrain future construction spending 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).
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The Potomac Edison Company
Internal Cash Flow
Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $187 million in 1998, compared with $87 million in 1997. The increase in 1998 cash flows resulted primarily from a reduction in the level of common stock dividends payable to its Parent, Allegheny Energy, Inc. Reduced 1997 cash flow was primarily the result of payment of internal restructuring liabilities. Current rate levels and reduced levels of construction expenditures permitted the Company to finance all of its construction expenditures in 1998 and 1997 with internal cash flow. As described under Environmental Issues starting on page 10, the Company could potentially face significant mandated increases in construction expenditures and operating costs related to environmental issues. Whether the Company can continue to meet the majority of its construction needs with internally generated cash is largely dependent upon the outcome of these issues.
Financing
Short-term debt is used to meet temporary cash needs. The Company had no short-term debt outstanding at December 31, 1998 or December 31, 1997. At December 31, 1998, the Company had Securities and Exchange Commission (SEC) authorization to issue up to $130 million of short-term debt. The Company and its regulated affiliates use an Allegheny Energy 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 meeting its 1999 cash needs through internal cash generation, cash on hand, and short-term borrowings as necessary.
SIGNIFICANT CONTINUING ISSUES
Proposed Merger with DQE
Allegheny Energy believes that DQE's basis for seeking to terminate the merger (described in Note B to the financial statements) is without merit. Accordingly, Allegheny Energy continues to seek the remaining regulatory approvals from the Department of Justice and the SEC. It is not likely either agency will act on the request unless Allegheny Energy obtains judicial relief requiring DQE to move forward.
Electric Energy Competition
The electricity supply segment of the electric utility industry in the United States is in the midst of becoming a competitive marketplace. The Energy Policy Act of 1992 began the process of deregulating the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. Since 1992, the wholesale electricity market has become increasingly competitive as companies began to engage in nationwide power trading. In addition, some states have taken active steps toward allowing retail customers the right to choose their electricity supplier. All of the states served by the utility subsidiaries of Allegheny Energy have investigated or implemented retail access to alternate electricity suppliers. The Company has been an advocate of federal legislation to create competition in the retail electricity markets to avoid regional dislocations and ensure level playing fields. In the absence of federal legislation, state-by-state implementation has begun.
M-44
The Potomac Edison Company
The Company has franchised regulated customers in Maryland, Virginia, and West Virginia.
In Maryland, the Maryland PSC in December 1997 issued an Order to implement retail competition in that state. The Maryland PSC's Order and its revised second Order call for a deregulation process, including a three-year phase-in beginning July 1, 2000, with recovery of prudent transition costs after mitigation. On September 10, 1998, the Maryland PSC issued a third Order which clarified certain issues and questions involved with the earlier Orders. A court-approved settlement of appeals of these orders provides that the Maryland PSC orders are not final. Roundtable discussions created by the Orders have been held since April 1998. The roundtable's final report to the Maryland PSC is due May 1, 1999, and the Maryland PSC's final Order in connection with the work of the roundtable is due August 1, 1999. As required by the Maryland PSC, the Company, on July 1, 1998, filed testimony in Maryland's investigation into transition costs, price protection, and unbundled rates. The filing requested recovery of transition costs and a surcharge to recover the cost of the AES Warrior Run cogeneration project which is scheduled to commence production on October 1, 1999. Hearings are scheduled to begin in April 1999. Several electricity competition bills have been introduced in the 1999 legislative session, and we continue to support bringing customer choice to Maryland customers.
In Virginia, a Subcommittee of the Virginia General Assembly studied electric utility restructuring and made recommendations to the General Assembly throughout 1998. The process led to the introduction of detailed restructuring legislation in both the House and Senate in the 1999 session. The legislation would implement a transition to choice beginning in 2002. The Senate passed the bill and referred it to the House. We expect the bill to be signed into law this year.
In West Virginia, the Public Service Commission of West Virginia (W.Va. PSC) issued an Order in December 1996 initiating a general investigation regarding the restructuring of the regulated electric utility industry. A task force was established to further investigate restructuring issues. Legislation passed in March 1998 directed the W.Va. PSC to meet with all interested parties to develop a restructuring plan, which meets the dictates and goals of the legislation, and to then submit that plan to the Legislature for review and possible approval. The W.Va. PSC has since issued an Order setting a schedule for a series of hearings this summer on major issues such as transition costs, codes of conduct, and customer protections.
The status of electric energy competition in Ohio and Pennsylvania in which affiliates of the Company serve are as follows:
In Ohio, the Public Utilities Commission of Ohio has continued informal roundtable discussions on issues concerning competition in the electric utility industry. The Governor established a legislative committee from members of both the Senate and House to further review issues regarding deregulation. Several bills on restructuring and deregulation have been introduced in the Ohio Legislature and are subject to continuing hearings and negotiations at the committee level. The Company's affiliate, Monongahela Power Company, is subject to these discussions and hearings.
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The Potomac Edison Company
In Pennsylvania, the Electricity Generation Customer Choice and Competition Act has created retail access to a competitive electric energy market. The Company's Pennsylvania affiliate, West Penn Power Company (West Penn), is subject to this Act. Beginning in January 1999, two-thirds of West Penn's customers were permitted to choose an alternate electricity supplier. Remaining West Penn customers can do so in January 2000. As a result of a Pennsylvania Public Utility Commission (Pennsylvania PUC) Order and settlement agreement, West Penn determined that under the provisions of Statement of Financial Accounting Standards No. 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71," in 1998 an extraordinary charge of $466.9 million ($275.4 million after taxes) was required to reflect a write-off of certain disallowances. In addition, charges of $40.3 million ($23.7 million after taxes) related to West Penn's revenue refund and energy program payments were also recorded.
Fully meeting challenges in the emerging competitive environment will be challenging for the Company unless certain outmoded and anti-competitive laws, specifically the Public Utility Holding Company Act of 1935 (PUHCA) and Section 210 of PURPA, are repealed or significantly revised. Allegheny Energy continues to advocate the repeal or reform of PUHCA and PURPA on the grounds that they are obsolete and anti-competitive, and that PURPA, in particular, results in utility customers paying above-market prices for power.
Business Strategy
Generation will continue to be a core part of Allegheny Energy's business. Allegheny Energy's goal is to grow generation through building and buying generating facilities. The energy delivery or wires business will also continue to be a core part of Allegheny Energy's business. Allegheny Energy plans to expand the energy delivery business primarily through acquisitions of other electric distribution properties.
The settlement agreement for the Company's affiliate, West Penn, in Pennsylvania permitted the transfer of its 3,722 MW of generating capacity to a new, unregulated company that is expected to be a wholly owned subsidiary of West Penn. West Penn plans to transfer these generating assets at book value. The unregulated generation will be sold in both the wholesale and retail competitive marketplace, allowing greater earnings growth potential, subject to market risk, while allowing Allegheny Energy to capitalize on its strengths in the generation business.
Allegheny Energy continues to study ways to meet existing and future increases in regulated customer demand, including new and efficient electric technologies, construction of various types and sizes of generating units, increasing the efficiency and availability of Company generating facilities, reducing internal electrical use and transmission and distribution losses, and acquisition of energy and capacity from third-party suppliers.
Environmental Issues
In the normal course of business, the Company is subject to various contingencies and uncertainties relating to its operations and construction programs, including legal actions and regulations and uncertainties related to environmental matters.
M-46
The Potomac Edison Company
The significant costs of complying with Title IV (acid rain) provisions of Phase I of the Clean Air Act Amendments of 1990 (CAAA) have been incurred and are being recovered currently from customers in rates. The Company estimates that its banked emission allowances will allow it to comply with Phase II sulfur dioxide (SO2) limits through 2005. Studies to evaluate cost- effective options to comply with Phase II limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.
Title I of the CAAA established an Ozone Transport Commission to ascertain additional nitrogen oxides (NOx) reductions to allow the Ozone Transport Region (OTR) to meet the ozone National Ambient Air Quality Standards (NAAQS). Under terms of a Memorandum of Understanding (MOU) among the OTR states, the Company's generating stations located in Maryland and Pennsylvania were 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 under Phase III of the MOU. However, this reduction will most likely be suspended by the proposed NOx State Implementation Plan (SIP) call rule discussed below. While the SIP call is being litigated, the Company is making preliminary plans to comply by applying NOx reduction facilities to existing units at various power stations. If reductions of 75% are required, installation of post- combustion control technologies would be very expensive. Pennsylvania and Maryland promulgated regulations to implement Phase II of the MOU in November 1997 and May 1998, respectively.
The Ozone Transport Assessment Group issued its final report in June 1997 that recommended the Environmental Protection Agency (EPA) consider a range of NOx controls between existing CAAA Title IV controls and the less stringent of 85% reduction from the 1990 emission rate or 0.15 lb/mmBtu. The EPA initiated the regulatory process to adopt the recommendations and issued its final NOx SIP call rule on September 24, 1998. The EPA's SIP call rule finds that 22 eastern states (including Maryland, Pennsylvania, and West Virginia) and the District of Columbia are all contributing significantly to ozone nonattainment in downwind states. The final rule declares that this downwind nonattainment will be eliminated (or sufficiently mitigated) if the upwind states reduce their NOx emissions by an amount that is precisely set by the EPA on a state-by-state basis. The final SIP call rule requires that all state-adopted NOx reduction measures must be incorporated into SIPs by September 24, 1999, and must be implemented by May 1, 2003. The Company's compliance with these requirements would require the installation of post-combustion control technologies on most, if not all, of its power stations. The Company continues to work with other coal-burning utilities and other affected constituencies in coal-producing states to challenge this EPA action.
In August 1997, eight northeastern states filed Section 126 petitions with the EPA requesting the immediate imposition of up to an 85% NOx reduction from utilities located in the Midwest and Southeast (West Virginia included). The petitions claim NOx emissions from these upwind sources are preventing their attainment with the ozone standard. In December 1997, the petitioning states and the EPA signed a Memorandum of Agreement to address these petitions in conjunction with the related SIP call mentioned above. In October 1998, the EPA proposed approval of the petitions. However, the EPA believes implementation of the NOx SIP call will alleviate the need to grant the petitions. The EPA intends to issue a final rule by April 1999.
M-47
The Potomac Edison Company
The EPA is required by law to regularly review the NAAQS for criteria pollutants. Recent court orders in litigation by the American Lung Association have expedited these reviews. The EPA in 1996 decided not to revise the SO2 and NOx standards. Revisions to particulate matter and ozone standards were proposed by the EPA in 1996 and finalized in July 1997. State attainment plans to meet the revised standards will not be developed for several years. Also, in July 1997, the EPA proposed regional haze regulations to improve visibility in Class I federal areas (national parks and wilderness areas). If finalized, subsequent state regulations could require additional reduction of SO2 and/or NOx emissions from Company facilities. The effect on the Company of revision to any of these standards or regulations is unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase III of the MOU, SIP calls, and Section 126 petitions cannot be determined at this time. All are being challenged by rulemaking, petition, and/or the litigation process. Implementation dates are also uncertain at this time, but could be as early as 2003, which would require substantial capital expenditures in the 1999- 2000 period. The Company's construction forecast includes the expenditure of $103 million of capital costs during the 1999-2003 period to comply with the SIP call.
Climate change is alleged to be the result of the atmospheric accumulation of certain gases collectively referred to as greenhouse gases (GHG), the most significant of which is carbon dioxide (CO2). Human activities, particularly combustion of fossil fuels, are alleged to be responsible for this accumulation of GHG. The Clinton Administration has signed an international treaty called the Kyoto Protocol, which will require the United States to reduce emissions of GHG by 7% from 1990 levels in the 2008-2012 time period. The United States Senate must ratify the Kyoto Protocol before it enters into force. The Senate passed a resolution in 1997 that placed two conditions on entering into any international climate change treaty. First, any treaty must include all nations, and, second, any treaty must not cause serious harm to the Unites States' economy. The Kyoto Protocol does not appear to satisfy either of these conditions, and, therefore, the Clinton Administration has withheld it from consideration by the Senate. Because coal combustion in power plants produces about 33% of the Unites States' CO2 emissions, implementation of the Kyoto Protocol would raise considerable uncertainty about the future viability of coal as a fuel source for new and existing power plants.
The Company previously reported that the EPA had identified the Company and its regulated affiliates as potentially responsible parties, along with approximately 175 others, 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 and its regulated affiliates have also been named as defendants along with multiple other defendants in pending asbestos cases involving one or more plaintiffs. The Company believes that provisions for liability and insurance recoveries are such that final resolution of these claims will not have a material effect on its financial position.
Independent Transmission System Operator
Allegheny Energy conditionally executed a membership agreement with the Midwest Independent System Operator expressly contingent upon consummation of
M-48
The Potomac Edison Company
a proposed merger with DQE. The membership agreement was entered into on April 9, 1998, and filed with the FERC on April 13, 1998. Allegheny Energy's membership status remains conditional upon the outcome of the merger. Many industry participants, including customers and regulatory authorities, believe that an entity independent of the utilities which own the transmission systems is needed to operate the systems to ensure nondiscriminatory access to the transmission systems by all users. Should these beliefs result in a mandate, Allegheny Energy may either voluntarily or involuntarily sustain or achieve new membership in some form of Independent System Operator.
Year 2000 Readiness Disclosure
As the Year 2000 (Y2K) approaches, most organizations, including the Company, could experience serious problems related to software and various equipment with embedded chips which may not properly recognize calendar dates. To minimize such problems, the Company and its affiliates in the System are proceeding with a comprehensive effort to continue operations without significant problems in 2000 and beyond. An Executive Task Force is coordinating the efforts of 24 separate Y2K Teams, representing all business and support units in the System.
In May 1998, the North American Electric Reliability Council (NERC), of which the System is a member, accepted a request from the United States Department of Energy to coordinate the industry's Y2K efforts. The electric utility industry and the System have segmented the Y2K problem into the following components:
Computer hardware and software;
Embedded chips in various equipment; and
Vendors and other organizations on which the System relies for critical materials and services.
The industry's and the System's efforts for each of these three components include assessment of the problem areas and remediation, testing, and contingency plans for critical functions for which remediation and testing are not possible or which do not provide reasonable assurance.
The NERC has established a goal of having the industry achieve a state of Y2K readiness for critical systems by June 30, 1999, and, to monitor progress, requires each utility to prepare and submit a monthly report showing progress and dated plans. By Order dated July 9, 1998, the Pennsylvania PUC initiated a proceeding requiring each utility that cannot meet a Y2K readiness date of March 31, 1999, for mission critical systems to file contingency plans by that date. The System's Y2K plans are designed to achieve the NERC and Pennsylvania PUC goals.
Integrated electric utilities are uniquely reliant on each other to avoid, in a worst case situation, cascading failure of the entire electrical system. The System is working with the Edison Electric Institute, the Electric Power Research Institute, the NERC, and the East Central Area Reliability Agreement group to capitalize on industry-wide experiences and to participate in industry-wide testing and contingency planning. The NERC, on January 11, 1999, issued a press release stating, based on the individual NERC reports it had received from 98% of the electrical industry, that "although there is
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The Potomac Edison Company
clearly much more work to be done, we have found that North America's electric power supply and delivery systems are well on their way to being Y2K ready."
The SEC requires that each company disclose its estimate of the "most reasonably likely worst case scenario" of a negative Y2K event. Since the Company and the industry are working diligently to avoid any disruption of electric service, the Company does not believe it or its customers will experience any significant long- term disruptions of electric service. It is the Company's opinion that the "most reasonably likely worst case scenario" is that there could be isolated problems at various Company facilities or at the facilities of neighboring utilities that may have somehow escaped discovery in the identification, remediation, and testing process, and that these problems may cause isolated disruptions of service. All utilities, including the Company, have experience in the implementation of existing emergency plans and are currently expanding their emergency plans to include contingency plans to respond quickly to any such events.
The Company is aware of the importance of electricity to its customers and is using its best efforts to avoid any serious Y2K problems. Despite the Company's best efforts, including working with internal resources, external vendors, and industry associations, the Company cannot guarantee that it will be able to conduct all of its operations without Y2K interruptions. To the extent that any Y2K problem may be encountered, the Company is committed to resolution as expeditiously as possible to minimize the effect of any such event.
Expenditures for Y2K readiness are not expected to have a material effect on the Company's results of operations or financial position primarily because of the significant time and money expended over the past several years on upgrading and replacing its large mainframe computer systems and software. While the remaining Y2K work is significant, it primarily represents a labor-intensive effort of remediation, component testing, multiple systems testing, documentation, and contingency planning. While outside contractors and equipment vendors will be employed for some of the work, the Company believes it must rely on System employees for most of the effort because of their experience with the Company's systems and equipment. The Company currently estimates that its total incremental expenditures for the Y2K effort since it began identification of Y2K costs will be within a range of $4 to $5 million. Of that amount, about $2 million has been incurred through 1998.
The descriptions herein of the Company's Y2K effort are made pursuant to the Year 2000 Information and Readiness Disclosure Act. Forward-looking statements herein are made pursuant to the Private Securities Litigation Reform Act of 1995. Of necessity, the Company's Y2K effort is based on estimates of assessment, remediation, testing, and contingency planning activities. There can be no assurance that actual results will not materially differ from expectations.
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West Penn Power Company and Subsidiaries
1998 Financial Statements
West Penn Power Company
Part of Allegheny Energy
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West Penn Power Company and Subsidiaries
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FACTORS THAT MAY AFFECT FUTURE RESULTS
This management's discussion and analysis of financial condition and results of operations contains forecast information items that are "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. These include statements with respect to deregulation activities and movements toward competition in Pennsylvania, the proposed merger of Allegheny Energy, Inc. (Allegheny Energy) with DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., and results of operations. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially include, among other matters, electric utility restructuring, including the ongoing state and federal activities; potential Year 2000 operation problems; developments in the legislative, regulatory, and competitive environments in which West Penn Power Company (the Company) operates, including regulatory proceedings affecting rates charged by the Company; environmental, legislative, and regulatory changes; future economic conditions; developments relating to the proposed merger of Allegheny Energy with DQE, including expenses that may be incurred in litigation; and other circumstances that could affect anticipated revenues and costs such as significant volatility in the market price of wholesale power, unscheduled maintenance or repair requirements, weather, and compliance with laws and regulations.
SIGNIFICANT EVENTS IN 1998, 1997, AND 1996
Pennsylvania Deregulation
On November 19, 1998, the Pennsylvania Public Utility Commission (Pennsylvania PUC) approved a settlement agreement between the Company and intervenors in the Company's restructuring proceedings related to legislation in Pennsylvania to provide customer choice of electric suppliers and deregulate electricity generation.
As a result of the May 29, 1998, Pennsylvania PUC Order and as revised by the November 19, 1998, settlement agreement, the Company determined that under the provisions of Statement of Financial Accounting Standards No. 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71," an extraordinary charge of $466.9 million ($275.4 million after taxes) was required to reflect a write-off of certain disallowances. In addition, charges of $40.3 million ($23.7 million after taxes) related to the Company's revenue refund and energy program payments were also recorded.
Under the terms of the settlement agreement, two-thirds of the Company's customers were permitted to choose an alternate generation supplier beginning in January 1999. All of the Company's customers can do so beginning in January 2000. They can also choose to remain as a customer at the Company's capped generation rates or to alternate back and forth. Under the law, all electric utilities, including the Company, retain the responsibility of electricity provider of last resort to all customers in their respective
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West Penn Power Company and Subsidiaries
franchise territories who do not choose an alternate supplier. See Notes B and C to the consolidated financial statements for details of the settlement agreement and other information about the deregulation process.
Merger with DQE
See page 9 and also Note D to the consolidated financial statements for information about the proposed merger of Allegheny Energy with DQE.
PURPA Power Project Terminations
On August 26, 1997, and December 3, 1997, the Company announced that it had negotiated agreements to buy out and settle disputes with developers of proposed power plants (the Milesburg and Washington Power projects) for $15 million and $48 million, respectively, reducing costs over the proposed 30- and 33-year lives of the projects by an estimated $1.4 billion. The disputed projects were being developed under the Public Utility Regulatory Policies Act of 1978 (PURPA) and would have required the Company to buy 43 megawatts (MW) and 80 MW of capacity and energy, respectively, over the lives of the projects at prices well above current market price estimates. In 1996, the Company and the developers of a proposed Shannopin PURPA project reached an agreement to terminate that project at a buyout price of $31 million. The Shannopin buyout will reduce the Company's costs approximately $665 million over 30 years by eliminating the need to buy the uneconomic power.
Internal Restructuring
In 1994, the Allegheny Energy integrated electric utility system (the System), including the Company, initiated an internal restructuring process to consolidate and re-engineer their utility operations to meet the competitive challenges of the changing electric utility industry. As a result of this process, the System reduced employment by about 1,000 employees through a voluntary separation plan, attrition and layoffs, and changed processes to obtain efficiencies to reduce operating and maintenance (O&M) costs. This process resulted in internal restructuring charges and an asset write-off in 1996 as described in Note E to the consolidated financial statements.
REVIEW OF OPERATIONS
Earnings Summary
Earnings (Millions of Dollars) 1998 1997 1996
Consolidated income before restructuring activities................... $ 136.3 $134.7 $119.9
Costs related to restructuring activities, net of taxes*.................. (23.7) (31.4) Extraordinary charge, net of taxes (Notes B and C to consolidated financial statements)................................ (275.4) Consolidated Net (Loss) Income............... $(162.8) $134.7 $ 88.5
*Pennsylvania deregulation settlement costs in 1998 and internal restructuring costs in 1996.
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West Penn Power Company and Subsidiaries
The increase in 1998 consolidated income before costs related to Pennsylvania restructuring and settlement activities, resulted primarily from increased bulk power transactions and from reduced power station O&M spending. The 1998 costs from restructuring activities and the extraordinary charge are related to Pennsylvania deregulation and the Pennsylvania restructuring Order. These costs are described in Notes B and C to the consolidated financial statements. The 1996 restructuring costs resulted from internal restructuring initiated in 1994 which is described in Note E to the consolidated financial statements and Internal Restructuring on page 2. The increase in 1997 consolidated income before restructuring activities resulted primarily from reductions in O&M expenses from the internal restructuring process and additional actions taken during the year to achieve further O&M reductions in response to significant decreases in residential kilowatt-hour (kWh) sales caused primarily by mild weather. The reductions from the internal restructuring process were offset in part by a change in allocation of affiliated transmission services which resulted in higher charges to the Company. Also contributing to the 1997 increase was a $3.6 million (after tax) interest refund on a tax- related contract settlement by the Company's 45% owned subsidiary, Allegheny Generating Company (AGC), recorded in other income as increased equity in earnings of AGC, a gain on a sale of land by a subsidiary of $2.8 million (after tax), and decreased depreciation expense.
Sales and Revenues
Total operating revenues for 1998, 1997, and 1996 were as follows:
(Millions of Dollars) 1998 1997 1996
Operating revenues: Bundled retail sales.................... $ 920.1 $ 973.6 $ 988.9 Unbundled retail sales.................. 14.0 2.5 Wholesale and other*.................... 75.7 65.5 67.3 Bulk power and transmission services sales........................ 68.9 40.6 32.9 Total operating revenues............ $1,078.7 $1,082.2 $1,089.1
*Excludes street lighting sales which are included in bundled retail sales. $7.3 $7.0 $7.0
Bundled retail sales revenues (full service sales to retail customers) include a $25.1 million rate refund from 1998 revenues, pursuant to the terms of the Pennsylvania restructuring settlement agreement. This refund to customers will be made in 1999. Excluding this rate decrease, bundled retail sales revenues decreased $28.4 million in 1998 primarily due to previously fully bundled customers participating in the Pennsylvania pilot by buying energy from another supplier of their choice. As a result of the Company's nonutility affiliate, Allegheny Energy Solutions, being permitted to sell to all Pennsylvania customers participating in the pilot, Allegheny Energy was able to recover some of the Company's generation sales lost as a result of customers participating in the Pennsylvania pilot program. Retail sales include sales to residential, commercial, industrial, and street lighting customers. Bundled retail sales revenues were affected by the Electricity Generation Customer Choice and Competition Act (Customer Choice Act) in Pennsylvania. As part of the Customer Choice Act, all utilities in Pennsylvania were required to administer retail access pilot programs under
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which customers, representing 5% of the load of each rate class, would choose a generation supplier other than their own local franchise utility. As a result, 5% of previously fully bundled customers participated in the Pennsylvania pilot program and were required to buy energy from another supplier of their choice. The pilot program began on November 1, 1997, and continued through December 31, 1998. Unbundled retail sales revenues represent transmission and distribution revenues from Pennsylvania pilot customers who chose another supplier to provide their energy needs.
To assure participation in the pilot program, pilot participants received an energy credit from their local utility and a price for energy pursuant to an agreement with an alternate supplier. The credit established by the Pennsylvania PUC was artificially high to encourage customer shopping, with the result that the Company incurred a revenue loss of $6.5 million for the pilot. The Pennsylvania PUC has approved the Company's pilot compliance filing and thus has indicated its intent to treat the revenue loss as a regulatory asset. Wholesale and other revenues include an accrual of such revenue losses, as well as sales to wholesale customers (cooperatives and municipalities that own their own distribution systems and buy all or part of their bulk power needs from the Company under Federal Energy Regulatory Commission (FERC) regulation) and non-kWh revenues. All of the Company's wholesale customers have signed contracts to remain as customers through at least November 2001.
Effective May 1, 1997, as a result of the Customer Choice Act, the Company obtained Pennsylvania PUC authorization to set its fuel clause to zero and to roll its then-applicable fuel clause rates into base rates. Thereafter, the Company assumed the risks and benefits of changes in fuel and purchased power costs and sales of transmission services and bulk power. The decrease in 1997 bundled retail revenues resulted primarily from a decrease in the fuel component of revenues and a decrease in residential kWh sales due to mild weather in 1997.
The increase in wholesale and other revenues in 1998 was due primarily to deferred net revenue losses. The Company recorded a regulatory asset of $6.4 million in 1998 and $.1 million in 1997 to offset revenue losses suffered as a result of the pilot program.
Bulk power transactions includes sales of bulk power and transmission services to power marketers and other utilities. Bulk power and transmission services sales for 1998, 1997, and 1996 were as follows:
1998 1997 1996 KWh Transactions (in billions): Bulk power............................... 2.3 1.0 0.4 Transmission services to nonaffiliated companies................ 3.0 5.4 7.6 Total................................ 5.3 6.4 8.0
Revenues (in millions): Bulk power............................... 49.6 22.2 10.0 Transmission services to nonaffiliated companies................ 19.3 18.4 22.9 Total................................ 68.9 40.6 32.9
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The 1998 increase in revenues from bulk power was due to increased sales that occurred primarily in the second quarter as a result of warm weather which increased the demand and price for energy. In 1998, revenues from transmission services were affected by a revenue refund resulting from a reduction in the Company's standard transmission rate and rates for ancillary services which were recently approved by the FERC. A provision of $2.9 million for these rate reductions was recorded in 1998, with the revenues to be refunded to customers in the first quarter of 1999.
Revenues from transmission services to nonaffiliated companies in 1998 increased, despite decreased transmission services activity. The increase in revenues was due in part to transmission services' reservation charges paid to the Company by others for the right to transmit energy. Transmission services activity was affected as a result of some of the reservations to transmit energy not being used. Revenues from transmission services to nonaffiliated companies in 1997 decreased due to reduced demand, primarily because of mild weather.
In June and July 1998, certain events combined to produce significant volatility in the spot prices for electricity at the wholesale level. These events included extremely hot weather, Midwest generation unit outages, and transmission constraints. Wholesale prices for electricity rose from a normal range of from $25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per mWh. The potential exists for such volatility to significantly affect the Company's operating results. The effect may be either positive or negative, depending on whether the Company is a net buyer or seller of electricity during such periods, and the open commitments which exist at such times.
Operating Expenses
Fuel expenses in 1998 and 1997 increased 1.6% and 6.2%, respectively, due primarily to increases in kWhs generated. The increases in kWhs generated were primarily the result of increased bulk power sales to power marketers and other utilities.
Purchased power and exchanges, net, represents power purchases from and exchanges with other companies and purchases from qualified facilities under PURPA, capacity charges paid to AGC, and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and consists of the following items:
(Millions of Dollars) 1998 1997 1996
Nonaffiliated transactions: Purchased power: From PURPA generation*................ $ 63.5 $ 65.1 $ 63.6 Other................................. 23.2 18.4 22.3 Power exchanges, net.................... (.3) .2 .7 Affiliated transactions: AGC capacity charges.................... 31.5 32.4 36.3 Energy and spinning reserve charges..... 3.4 3.9 4.0 Purchased power and exchanges, net.... $121.3 $120.0 $126.9
*PURPA cost (cents per kWh) 5.8 6.0 5.8
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The increase in other purchased power in 1998 resulted primarily from increased purchases for sales. An increase in price caused by volatility in the spot prices for electricity at the wholesale level in the second and third quarters of 1998 also contributed to the increase. The decrease in other purchased power in 1997 was a result of decreased demand due to decreased sales to retail customers related to mild 1997 weather.
None of the Company's purchased power contracts are capitalized since there are no minimum payment requirements absent associated kWh generation.
PURPA purchased power costs will be reduced $197 million during the period 1999-2016 related to the Applied Energy Services Corporation's Beaver Valley nonutility generation contract as a result of the 1998 extraordinary charge. See Notes B and C to the consolidated financial statements for further information.
The increase in other operation expenses in 1998 was due primarily to increased expenses related to competition and the Pennsylvania restructuring Order. See Note B to the consolidated financial statements for additional information related to Pennsylvania restructuring. The increase in other operation expenses in 1997 was primarily due to increased transmission services cost allocations from affiliated companies under the power supply agreement ($10.1 million) and Pennsylvania pilot- related expenses. Other operation expense for 1997 also includes $4.4 million of legal expenses incurred by the Company to defend itself against an antitrust lawsuit filed by the developers of the proposed Washington Power PURPA project. The dispute was settled in December 1997. These expenses more than offset the reduction in embedded expenses achieved through the 1996 internal restructuring process.
The decrease in maintenance expenses in 1998 was due primarily to a management program to postpone such expenses for the year in response to limited sales growth in the first quarter due to the warm winter weather. The Company is postponing these expenses primarily by extending the time between maintenance outages. The 1997 decrease in maintenance expenses resulted from reduced expenses achieved through internal restructuring efforts and other cost controls. 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.
Internal restructuring charges and an asset write-off in 1996 resulted from internal restructuring activities, which have been completed, and the write-off of previously accumulated costs related to a proposed transmission line.
Higher depreciation expense in 1998 resulted from increased investment. The decrease in depreciation expense in 1997 was the result of a change in the retirement dates for the Mitchell power station and the Pleasants power station scrubbers.
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The decrease in federal and state income taxes in 1998 resulted primarily from a decrease in income before taxes, primarily because of costs related to restructuring activities recorded in 1998. The 1997 increase in federal and state income taxes was primarily due to increased income in 1997 compared with 1996. Note F to the consolidated financial statements provides a further analysis of income tax expenses.
The decrease in allowance for other than borrowed funds used during construction of $1.5 million in 1998 reflects lower-cost short-term debt financing. The allowance for borrowed funds used during construction component of the formula receives greater weighting when short-term debt increases. The decrease also reflects adjustments of prior periods. Starting in July 1998, as a result of the Pennsylvania restructuring, the Company stopped accruing allowance for funds used during construction and began accruing capitalized interest for generation construction projects. Capitalized interest is reported within allowance for borrowed funds used during construction.
The decrease in other income, net, of $6.2 million in 1998 and the increase in 1997 of $4.1 million was primarily due to 1997 increases for an interest refund on a tax-related contract settlement ($3.6 million, net of taxes) received by the Company's subsidiary, AGC, and income on the sale of land ($2.8 million, net of taxes) by the Company's subsidiary, West Virginia Power and Transmission Company.
The decrease in interest on long-term debt in 1998 of $3.3 million resulted from reduced long-term debt and lower interest rates.
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 decrease in other interest expense in 1997 resulted primarily from decreased interest due to reduced overcollections of the fuel cost portion of customer billings.
The extraordinary charge of $466.9 million ($275.4 million after taxes) was required to reflect a write-off of certain disallowances in the Pennsylvania PUC's May and November 1998 Orders as described in Notes B and C to the consolidated financial statements.
FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES
Liquidity and Capital Requirements
To meet cash needs 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 financings depend upon the financial health of the companies seeking those funds and market conditions.
Construction expenditures in 1998 were $96 million and, for 1999 and 2000, are estimated at $119 million and $106 million, respectively. The 1999 and 2000 estimated expenditures include $33 million and $43 million, respectively, for construction of environmental control technology. It is
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the Company's goal to constrain future utility construction spending to the approximate level of depreciation currently in rates. The Company also has additional capital requirements for debt maturities (see Note L to the consolidated financial statements).
Internal Cash Flow
Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $151 million in 1998, compared with $103 million in 1997. Reduced 1997 cash flow was the result of the $48 million buyout of the Washington Power PURPA project and payment of internal restructuring liabilities. Current rate levels and reduced levels of construction expenditures permitted the Company to finance all of its construction expenditures in 1998 and nearly all in 1997 with internal cash flow. As described under Environmental Issues starting on page 11, the Company could potentially face significant mandated increases in construction expenditures and operating costs related to environmental issues. Whether the Company can continue to meet the majority of its construction needs with internally generated cash is largely dependent upon the outcome of these issues.
Financing
Short-term debt is used to meet temporary cash needs. Short-term debt, including notes payable to affiliates under the money pool, increased $13 million to $65 million in 1998. At December 31, 1998, the Company had Securities and Exchange Commission (SEC) authorization to issue up to $182 million of short-term debt. The Company and its regulated affiliates use an Allegheny Energy 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 meeting its 1999 cash needs through internal cash generation, cash on hand, and short-term borrowings as necessary. However, the Company is expected to issue up to $670 million of bonds to "securitize" transition costs related to its restructuring settlement described in Note B to the consolidated financial statements.
SIGNIFICANT CONTINUING ISSUES
Proposed Merger with DQE
Allegheny Energy believes that DQE's basis for seeking to terminate the merger (described in Note D to the consolidated financial statements) is without merit. Accordingly, Allegheny Energy continues to seek the remaining regulatory approvals from the Department of Justice and the SEC. It is not likely either agency will act on the requests unless Allegheny Energy obtains judicial relief requiring DQE to move forward.
Electric Energy Competition
The electricity supply segment of the electric utility industry in the United States is in the midst of becoming a competitive marketplace. The Energy Policy Act of 1992 began the process of deregulating the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. Since 1992, the wholesale electricity market has become increasingly competitive as companies began to
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engage in nationwide power trading. In addition, some states have taken active steps toward allowing retail customers the right to choose their electricity supplier. All of the states served by the utility subsidiaries of Allegheny Energy have investigated or implemented retail access to alternate electricity suppliers. Allegheny Energy has been an advocate of federal legislation to create competition in the retail electricity markets to avoid regional dislocations and ensure level playing fields. In the absence of federal legislation, state-by-state implementation has begun.
The Customer Choice Act in Pennsylvania has created retail access to a competitive electric energy market. Pursuant to the Customer Choice Act, all electric utilities in Pennsylvania were required in 1998 to establish and administer retail access pilot programs to 5% of the load of each class of their customers. Beginning in January 1999, two-thirds of the Company's customers were permitted to choose an alternate electricity supplier. Remaining Company customers can do so in January 2000. See Note B to the consolidated financial statements for additional information on the settlement agreement reached with the Pennsylvania PUC, which included transition costs and the ability to transfer generating assets to an affiliate at net book value.
One result of the Customer Choice Act is the bifurcation of electricity supply and electricity delivery into two separate businesses. The transmission and distribution (wires) business remains under the traditional regulated ratemaking, while the electricity supply business in Pennsylvania is deregulated, and its pricing will be determined by the marketplace. The wires business will have responsibility as the electricity provider of last resort and will generally obtain its electricity supply from the market, primarily by competitive bidding. Provider of last resort service will continue to be regulated and provided at capped rates. The electricity supply business will be free to sell the Company's generation capacity and energy in the open wholesale and retail market, subject to codes of conduct and the restriction that it may not sell at retail, except under certain conditions, in the Company's service territory through 2003. Because of these new regulations, the Company reorganized for 1999 into a Delivery Business (wires) and a Supply Business (marketing capacity and energy). The Company's Delivery Business will continue to provide transmission and distribution service and will bill a Competitive Transition Charge to native load customers exercising choice.
The status of electric energy competition in Maryland, Virginia, West Virginia, and Ohio in which affiliates of the Company serve are as follows.
In Maryland, the Maryland Public Service Commission (Maryland PSC) in December 1997 issued an Order to implement retail competition in that state. The Maryland PSC's Order and its revised second Order, call for a deregulation process, including a three-year phase-in beginning July 1, 2000, with recovery of prudent transition costs after mitigation. The Maryland PSC subsequently issued a third Order which clarified certain issues and questions involved with the earlier Orders. A court-approved settlement of appeals of these Orders provides that the Maryland PSC Orders are not final. The Company's Maryland affiliate, The Potomac Edison Company, is subject to these orders and appeals.
In Virginia, a Subcommittee of the Virginia General Assembly studied electric utility restructuring and made recommendations to the General Assembly throughout 1998. The process led to the introduction of detailed
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restructuring legislation in both the House and Senate in the 1999 session. The legislation would implement a transition to choice beginning in 2002. The Senate passed the bill and referred it to the House. It is expected that the bill will be signed into law this year. The Company's affiliate, The Potomac Edison Company, is subject to this action.
In West Virginia, the Public Service Commission of West Virginia (W.Va. PSC) issued an Order in December 1996 initiating a general investigation regarding the restructuring of the regulated electric utility industry. A task force was established to further investigate restructuring issues. Legislation passed in March 1998 directed the W.Va. PSC to meet with all interested parties to develop a restructuring plan, which meets the dictates and goals of the legislation, and to then submit that plan to the Legislature for review and possible approval. The W.Va. PSC has since issued an Order setting a schedule for a series of hearings this summer on major issues such as transition costs, codes of conduct, and customer protections. The Company's affiliates, Monongahela Power Company and The Potomac Edison Company, are subject to this restructuring plan.
In Ohio, the Public Utilities Commission of Ohio has continued informal roundtable discussions on issues concerning competition in the electric utility industry. The Governor established a legislative committee from members of both the Senate and House to further review issues regarding deregulation. Several bills on restructuring and deregulation have been introduced in the Ohio Legislature and are subject to continuing hearings and negotiations at the committee level. The Company's affiliate, Monongahela Power Company, is subject to these discussions and hearings.
Fully meeting challenges in the emerging competitive environment will be challenging for Allegheny Energy unless certain outmoded and anti-competitive laws, specifically the Public Utility Holding Company Act of 1935 (PUHCA) and Section 210 of PURPA, are repealed or significantly revised. Allegheny Energy continues to advocate the repeal or reform of PUHCA and PURPA on the grounds that they are obsolete and anti-competitive, and that PURPA, in particular, results in utility customers paying above-market prices for power.
Business Strategy
Generation will continue to be a core part of Allegheny Energy's business. Allegheny Energy's goal is to grow generation through building and buying generating facilities. The energy delivery or wires business will also continue to be a core part of Allegheny Energy's business. Allegheny Energy plans to expand the energy delivery business primarily through acquisitions of other electric distribution properties.
The Company's settlement agreement in Pennsylvania permitted the transfer of the Company's 3,722 MW of generating capacity to a new, unregulated, company that is expected to be a wholly owned subsidiary. The Company plans to transfer these generating assets at book value. The unregulated generation will be sold in both the wholesale and retail competitive marketplace, allowing greater earnings growth potential, subject to market risk, while allowing Allegheny Energy to capitalize on its strengths in the generation business.
Allegheny Energy continues to study ways to meet existing and future increases in regulated customer demand, including new and efficient electric
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technologies, construction of various types and sizes of generating units, increasing the efficiency and availability of Company generating facilities, reducing internal electrical use and transmission and distribution losses, and acquisition of energy and capacity from third-party suppliers.
Environmental Issues
In the normal course of business, the Company is subject to various contingencies and uncertainties relating to its operations and construction programs, including legal actions and regulations and uncertainties related to environmental matters.
The significant costs of complying with Title IV (acid rain) provisions of Phase I of the Clean Air Act Amendments of 1990 (CAAA) have been incurred and are being recovered currently from customers in rates. The Company estimates that its banked emission allowances will allow it to comply with Phase II sulfur dioxide (SO2) limits through 2005. Studies to evaluate cost- effective options to comply with Phase II limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.
Title I of the CAAA established an Ozone Transport Commission to ascertain additional nitrogen oxides (NOx) reductions to allow the Ozone Transport Region (OTR) to meet the ozone National Ambient Air Quality Standards (NAAQS). Under terms of a Memorandum of Understanding (MOU) among the OTR states, the Company's generating station located in Pennsylvania was 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 under Phase III of the MOU. However, this reduction will most likely be suspended by the proposed NOx State Implementation Plan (SIP) call rule discussed below. While the SIP call is being litigated, the Company is making preliminary plans to comply by applying NOx reduction facilities to existing units at various power stations. If reductions of 75% are required, installation of post-combustion control technologies would be very expensive. Pennsylvania promulgated regulations to implement Phase II of the MOU in November 1997.
The Ozone Transport Assessment Group issued its final report in June 1997 that recommended the Environmental Protection Agency (EPA) consider a range of NOx controls between existing CAAA Title IV controls and the less stringent of 85% reduction from the 1990 emission rate or 0.15 lb/mmBtu. The EPA initiated the regulatory process to adopt the recommendations and issued its final NOx SIP call rule on September 24, 1998. The EPA's SIP call rule finds that 22 eastern states (including Maryland, Pennsylvania, and West Virginia) and the District of Columbia are all contributing significantly to ozone nonattainment in downwind states. The final rule declares that this downwind nonattainment will be eliminated (or sufficiently mitigated) if the upwind states reduce their NOx emissions by an amount that is precisely set by the EPA on a state-by-state basis. The final SIP call rule requires that all state-adopted Nox reduction measures must be incorporated into SIPs by September 24, 1999, and must be implemented by May 1, 2003. The Company's compliance with these requirements would require the installation of post-combustion control technologies on most, if not all, of its power stations. The Company continues to work with other coal-burning utilities and other affected constituencies in coal-producing states to challenge this EPA action.
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In August 1997, eight northeastern states filed Section 126 petitions with the EPA requesting the immediate imposition of up to an 85% NOx reduction from utilities located in the Midwest and Southeast (West Virginia included). The petitions claim NOx emissions from these upwind sources are preventing their attainment with the ozone standard. In December 1997, the petitioning states and the EPA signed a Memorandum of Agreement to address these petitions in conjunction with the related SIP call mentioned above. In October 1998, the EPA proposed approval of the petitions. However, the EPA believes implementation of the NOx SIP call will alleviate the need to grant the petitions. The EPA intends to issue a final rule by April 1999.
The EPA is required by law to regularly review the NAAQS for criteria pollutants. Recent court orders in litigation by the American Lung Association have expedited these reviews. The EPA in 1996 decided not to revise the SO2 and NOx standards. Revisions to particulate matter and ozone standards were proposed by the EPA in 1996 and finalized in July 1997. State attainment plans to meet the revised standards will not be developed for several years. Also, in July 1997, the EPA proposed regional haze regulations to improve visibility in Class I federal areas (national parks and wilderness areas). If finalized, subsequent state regulations could require additional reduction of SO2 and/or NOx emissions from Company facilities. The effect on the Company of revision to any of these standards or regulations is unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase III of the MOU, SIP calls, and Section 126 petitions cannot be determined at this time. All are being challenged by rulemaking, petition, and/or the litigation process. Implementation dates are also uncertain at this time, but could be as early as 2003, which would require substantial capital expenditures in the 1999- 2000 period. The Company's construction forecast includes the expenditure of $147 million of capital costs during the 1999-2003 period to comply with the SIP call.
Climate change is alleged to be the result of the atmospheric accumulation of certain gases collectively referred to as greenhouse gases (GHG), the most significant of which is carbon dioxide (CO2). Human activities, particularly combustion of fossil fuels, are alleged to be responsible for this accumulation of GHG. The Clinton Administration has signed an international treaty called the Kyoto Protocol, which will require the United States to reduce emissions of GHG by 7% from 1990 levels in the 2008-2012 time period. The United States Senate must ratify the Kyoto Protocol before it enters into force. The Senate passed a resolution in 1997 that placed two conditions on entering into any international climate change treaty. First, any treaty must include all nations, and, second, any treaty must not cause serious harm to the Unites States' economy. The Kyoto Protocol does not appear to satisfy either of these conditions, and, therefore, the Clinton Administration has withheld it from consideration by the Senate. Because coal combustion in power plants produces about 33% of the Unites States' CO2 emissions, implementation of the Kyoto Protocol would raise considerable uncertainty about the future viability of coal as a fuel source for new and existing power plants.
The Company previously reported that the EPA had identified the Company and its regulated affiliates as potentially responsible parties, along with approximately 175 others, 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 and its
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regulated affiliates have also been named as defendants along with multiple other defendants in pending asbestos cases involving one or more plaintiffs. The Company believes that provisions for liability and insurance recoveries are such that final resolution of these claims will not have a material effect on its financial position.
Independent Transmission System Operator
Allegheny Energy conditionally executed a membership agreement with the Midwest Independent System Operator expressly contingent upon consummation of a proposed merger with DQE. The membership agreement was entered into on April 9, 1998, and filed with the FERC on April 13, 1998. Allegheny Energy's membership status remains conditional upon the outcome of the merger. Many industry participants, including customers and regulatory authorities, believe that an entity independent of the utilities which own the transmission systems is needed to operate the systems to ensure nondiscriminatory access to the transmission systems by all users. Should these beliefs result in a mandate, Allegheny Energy may either voluntarily or involuntarily sustain membership or achieve new membership in some form of Independent System Operator.
Year 2000 Readiness Disclosure
As the Year 2000 (Y2K) approaches, most organizations, including the Company, could experience serious problems related to software and various equipment with embedded chips which may not properly recognize calendar dates. To minimize such problems, the Company and its affiliates in the System are proceeding with a comprehensive effort to continue operations without significant problems in 2000 and beyond. An Executive Task Force is coordinating the efforts of 24 separate Y2K Teams, representing all business and support units in the System.
In May 1998, the North American Electric Reliability Council (NERC), of which the System is a member, accepted a request from the United States Department of Energy to coordinate the industry's Y2K efforts. The electric utility industry and the System have segmented the Y2K problem into the following components:
Computer hardware and software;
Embedded chips in various equipment; and
Vendors and other organizations on which the System relies for critical materials and services.
The industry's and the System's efforts for each of these three components include assessment of the problem areas and remediation, testing, and contingency plans for critical functions for which remediation and testing are not possible or which do not provide reasonable assurance.
The NERC has established a goal of having the industry achieve a state of Y2K readiness for critical systems by June 30, 1999, and, to monitor progress, requires each utility to prepare and submit a monthly report showing progress and dated plans. By Order dated July 9, 1998, the Pennsylvania PUC initiated a proceeding requiring each utility that cannot meet a Y2K readiness date of March 31, 1999, for mission critical systems to file contingency plans by
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that date. The System's Y2K plans are designed to achieve the NERC and Pennsylvania PUC goals.
Integrated electric utilities are uniquely reliant on each other to avoid, in a worst case situation, cascading failure of the entire electrical system. The System is working with the Edison Electric Institute, the Electric Power Research Institute, the NERC, and the East Central Area Reliability Agreement group to capitalize on industry-wide experiences and to participate in industry-wide testing and contingency planning. The NERC, on January 11, 1999, issued a press release stating, based on the individual NERC reports it had received from 98% of the electrical industry, that "although there is clearly much more work to be done, we have found that North America's electric power supply and delivery systems are well on their way to being Y2K ready."
The SEC requires that each company disclose its estimate of the "most reasonably likely worst case scenario" of a negative Y2K event. Since the Company and the industry are working diligently to avoid any disruption of electric service, the Company does not believe it or its customers will experience any significant long- term disruptions of electric service. It is the Company's opinion that the "most reasonably likely worst case scenario" is that there could be isolated problems at various Company facilities or at the facilities of neighboring utilities that may have somehow escaped discovery in the identification, remediation, and testing process, and that these problems may cause isolated disruptions of service. All utilities, including the Company, have experience in the implementation of existing emergency plans and are currently expanding their emergency plans to include contingency plans to respond quickly to any such events.
The Company is aware of the importance of electricity to its customers and is using its best efforts to avoid any serious Y2K problems. Despite the Company's best efforts, including working with internal resources, external vendors, and industry associations, the Company cannot guarantee that it will be able to conduct all of its operations without Y2K interruptions. To the extent that any Y2K problem may be encountered, the Company is committed to resolution as expeditiously as possible to minimize the effect of any such event.
Expenditures for Y2K readiness are not expected to have a material effect on the Company's results of operations or financial position primarily because of the significant time and money expended over the past several years on upgrading and replacing its large mainframe computer systems and software. While the remaining Y2K work is significant, it primarily represents a labor-intensive effort of remediation, component testing, multiple systems testing, documentation, and contingency planning. While outside contractors and equipment vendors will be employed for some of the work, the Company believes it must rely on System employees for most of the effort because of their experience with the Company's systems and equipment. The Company currently estimates that its total incremental expenditures for the Y2K effort since it began identification of Y2K costs will be within a range of $7 to $10 million. Of that amount, about $4 million has been incurred through 1998.
The descriptions herein of the Company's Y2K effort are made pursuant to the Year 2000 Information and Readiness Disclosure Act. Forward-looking statements herein are made pursuant to the Private Securities Litigation Reform Act of 1995. Of necessity, the Company's Y2K effort is based on estimates of assessment, remediation, testing, and contingency planning
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activities. There can be no assurance that actual results will not materially differ from expectations.
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1998 Financial Statements
Allegheny Generating Company
Part of Allegheny Energy
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FACTORS THAT MAY AFFECT FUTURE RESULTS
This management's discussion and analysis of financial condition and results of operations contains forecast information items that are "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. All such forward- looking information is necessarily only estimated. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially include, among other matters, electric utility restructuring, including the ongoing state and federal activities; potential Year 2000 operation problems; developments in the legislative, regulatory, and competitive environments in which Allegheny Generating Company (the Company) operates, including regulatory proceedings affecting rates charged by the Company; environmental, legislative, and regulatory changes; future economic conditions; developments relating to the proposed merger of Allegheny Energy, Inc. (Allegheny Energy) with DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa.; and other circumstances that could affect anticipated revenues and costs such as unscheduled maintenance or repair requirements and compliance with laws and regulations.
SIGNIFICANT EVENTS IN 1998, 1997, AND 1996
See page 3 and also Note B to the financial statements for information about the proposed merger of Allegheny Energy with DQE.
REVIEW OF OPERATIONS
As described under Liquidity and Capital Requirements, revenues are determined under a cost-of-service formula rate schedule. 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 1998 and 1997 decreased due to a reduction in net investment and reduced operating expenses.
The decrease in operating expenses in 1998 and 1997 resulted from a decrease in federal income taxes due to a decrease in operating income before taxes, exclusive of other income which is reported net of taxes combined with a decrease in operation and maintenance expense.
Effective June 1, 1995, the Federal Energy Regulatory Commission (FERC) gave approval for the Company to add a prior tax payment of approximately $12 million to rate base. In September 1997, the Company received a tax-related contract settlement of $8.8 million of taxes related to the $12 million added to rate base
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Allegheny Generating Company
in 1995. The 1997 settlement amount was recorded as a reduction to plant and was removed from rate base.
The increase in other income, net in 1997 was due to interest on the refund on the tax-related contract settlement (see above).
The decrease in interest on long-term debt in 1998 and 1997 was primarily the result of a decrease in the average amount of long- term debt outstanding.
The increase in other interest expense in 1998 was due to an increased level of short-term debt maintained by the Company upon retirement of medium-term debt.
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, Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company (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. On December 29, 1998, the FERC issued an Order accepting a proposed amendment to the Parent's Power Supply Agreement for the Company effective January 1, 1999. This amendment sets the generation demand for each Parent proportional to its ownership in the Company. Previously, demand for each Parent fluctuated due to customer usage.
The Company'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 with and approved by the FERC, the Company's ROE is set at 11% and will continue at that rate unless any affected party seeks a change.
As previously reported, the Company has received authority from the Securities and Exchange Commission (SEC) 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 out of other paid-in capital and the reduction of retained earnings to zero. The Company's goal is to retire debt and pay dividends in amounts necessary to maintain a common equity position of about 45%, including short-term debt. 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.
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Allegheny Generating Company
An Allegheny Energy internal money pool accommodates intercompany short-term borrowing needs to the Company to the extent that Allegheny Energy and the Company's Parents have funds available. To the extent funds are not available from the money pool, the Company borrows from external sources.
SIGNIFICANT CONTINUING ISSUES
Proposed Merger with DQE
Allegheny Energy, Inc., (Allegheny Energy) parent of the Company's parents, believes that DQE's basis for seeking to terminate the merger (described in Note B to the financial statements) is without merit. Accordingly, Allegheny Energy continues to seek the remaining regulatory approvals from the Department of Justice and the SEC. It is not likely either agency will act on the requests unless Allegheny Energy obtains judicial relief requiring DQE to move forward.
Year 2000 Readiness Disclosure
The Company and its Parents have spent considerable time and effort over the past several years on the issue of the Year 2000 (Y2K) software compliance, and the effort is continuing. Certain software has already been made year 2000 compliant by upgrades and replacement, and analysis is continuing on others, in accordance with a schedule planned to permit the Company and its Parents to process information in the year 2000 and beyond without significant problems. Expenditures for year 2000 compliance are not expected to have a material effect on the Company's results of operations or financial position.
As described in the second paragraph under Liquidity and Capital Requirements above, the Company's results of operations are primarily related to recovery of fixed capital costs under contract with its Parents and therefore are not affected by the operation, or non-operation, of the Bath County station and related transmission facilities.
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ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements
Index
Monon- Potomac West AE gahela Edison Penn AGC
Report of Independent Accountants F- 1
Statement of Income for the three years ended December 31, 1998 F- 2 Statement of Retained Earnings for the three years ended December 31, 1998 -
Statement of Cash Flows for the three years ended December 31, 1998 F- 3
Balance Sheet at December 31, 1998 and 1997 F- 4
Statement of Capitalization at December 31, 1998 and 1997 F- 5
Statement of Common Equity for the three years ended December 31, 1998 F- 6 - - - -
Notes to financial statements F- 7
Financial Statement Schedules - Schedules for the three years ended December 31, 1998 49 49 49 49 49
II Valuation and qualifying accounts S-1 S-2 S-3 S-4 -
Allegheny Energy, Inc.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders of Allegheny Energy, 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 Energy, Inc. and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
Allegheny Energy, Inc.
Consolidated Statement of Income
See accompanyiong notes to consolidated financial statements.
Allegheny Energy, Inc.
Consolidated Statement of Cash Flows
See accompanying notes to consolidated financial statements.
Allegheny Energy, Inc.
Consolidated Balance Sheet
As of December 31 1998 1997 (Thousands of Dollars)
Assets Property, Plant, and Equipment: At original cost, including $166,330 and $229,785 under construction $ 8,629,733 $ 8,451,424 Accumulated depreciation (3,395,603) (3,155,210) 5,234,130 5,296,214 Investments and Other Assets: Subsidiaries consolidated-excess of cost over book equity at acquisition 15,077 15,077 Benefit plans' investments 87,468 79,474 Nonutility investments 9,361 4,992 Other 1,566 1,559 113,472 101,102 Current Assets: Cash and temporary cash investments 17,559 26,374 Accounts receivable: Electric service, net of $18,011 and $17,191 uncollectible allowance 276,866 296,082 Other, net 16,163 12,312 Materials and supplies-at average cost: Operating and construction 99,439 80,836 Fuel 57,610 63,361 Prepaid taxes 56,658 51,724 Other, including current portion of regulatory assets 30,788 24,005 555,083 554,694
Deferred Charges: Regulatory assets 704,506 586,125 Unamortized loss on reacquired debt 48,671 49,550 Other 91,931 66,406
845,108 702,081
Total $ 6,747,793 $ 6,654,091
Capitalization and Liabilities
Capitalization: Common stock, other paid-in capital, and retained earnings $ 2,033,889 $ 2,256,898 Preferred stock 170,086 170,086 Long-term debt and QUIDS 2,179,288 2,193,153 4,383,263 4,620,137 Current Liabilities: Short-term debt 258,837 206,401 Long-term debt due within one year 185,400 Accounts payable 153,107 129,989 Taxes accrued: Federal and state income 17,442 10,453 Other 62,751 55,428 Interest accrued 35,945 40,000 Deferred income taxes 18,718 Adverse power purchase commitments 47,173 Other 101,239 74,170 695,212 701,841 Deferred Credits and Other Liabilities: Unamortized investment credit 125,396 133,316 Deferred income taxes 842,193 1,031,236 Regulatory liabilities 80,354 91,178 Adverse power purchase commitments 538,745 Other 82,630 76,383 1,669,318 1,332,113 Commitments and Contingencies (Note N)
Total $ 6,747,793 $ 6,654,091
See accompanying notes to consolidated financial statements.
Allegheny Energy, Inc.
Consolidated Statement of Capitalization
See accompanying notes to consolidated financial statements.
Consolidated Statement of Common Equity
See accompanying notes to consolidated financial statements.
Allegheny Energy, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (These notes are an integral part of the consolidated financial statements.)
Note A: Summary of Significant Accounting Policies
Allegheny Energy, 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 (Monongahela Power), The Potomac Edison Company (Potomac Edison), and West Penn Power Company (West Penn). These subsidiaries jointly own Allegheny Generating Company (AGC), which owns and sells to its parents 840 megawatts (MW) of pumped-storage generating capacity. The markets for the subsidiaries' regulated electric retail sales are in the states of Pennsylvania, West Virginia, Maryland, Virginia, and Ohio. In 1998, revenues from the 50 largest electric utility customers provided approximately 17% of the consolidated retail revenues. The Company also has a wholly owned nonutility subsidiary, AYP Capital, Inc. (AYP Capital), formed in 1994, which, along with its subsidiaries, is involved primarily in energy-related services, development of nonutility power generation, wholesale and retail electricity sales to deregulated markets, telecommunications, and other energy-related businesses.
The Company and its subsidiaries are subject to regulation by the Securities and Exchange Commission, including the Public Utility Holding Company Act of 1935 (PUHCA). The regulated subsidiaries are subject to regulation by various state bodies having jurisdiction and by the Federal Energy Regulatory Commission (FERC). See Note B for significant changes in the Pennsylvania regulatory environment. 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.
Allegheny Energy, Inc.
Deferred Power Costs, Net
The costs of fuel, purchased power, and certain other costs, and revenues from sales to other utilities and power marketers, including transmission services, are deferred until they are either recovered from or credited to customers under fuel and energy cost-recovery procedures in West Virginia, Maryland, Virginia, and Ohio. West Penn discontinued this practice in Pennsylvania, effective May 1, 1997.
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. Costs include 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 indirect costs such as administration, maintenance, and depreciation of transportation and construction equipment, postretirement benefits, taxes, and other 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 1998, 1997, and 1996 averaged 7.78%, 8.59%, and 8.41%, respectively. AFUDC is not included in the cost of construction by the nonutility business or by the utility businesses when the cost of financing the construction is being recovered through rates.
As discussed in Note B, as a result of a Pennsylvania Order, West Penn has discontinued the application of the Financial Accounting Standards Board's (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," for electric generation operations and has adopted SFAS No. 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71." Starting in July 1998, West Penn stopped accruing AFUDC for generation construction projects and adopted SFAS No. 34, "Capitalizing Interest Costs," to capitalize interest during the period of construction of generation construction projects. Capitalized interest, recognized by West Penn as a cost of property, plant, and equipment with offsetting credits to interest charges, is reported in the statement of income as allowance for borrowed funds used
Allegheny Energy, Inc.
during construction. Since adoption in July 1998, rates used by West Penn for capitalizing interest on generation construction projects averaged 7.45%.
Depreciation and Maintenance
Provisions for depreciation are determined generally on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 3.3% of average depreciable property in each of the years 1998 and 1997, and 3.5% in 1996. 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 original 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 Assets and Liabilities
In accordance with SFAS No. 71, the Company's consolidated financial statements include certain assets and liabilities based on 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 using 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's 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 Company's subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up 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.
Capitalized Software Costs
The Company capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over a five-year period beginning upon a project's completion.
Comprehensive Income
SFAS No. 130, "Reporting Comprehensive Income," effective for 1998, established standards for reporting comprehensive income and its components (revenues, expenses, gains, and losses) in the financial statements. The Company does not have any elements of other comprehensive income to report in accordance with SFAS No. 130.
Note B: Industry Restructuring
In December 1996, Pennsylvania enacted the Electricity Generation Customer Choice and Competition Act (Customer Choice Act) to restructure the electric industry in Pennsylvania to create retail access to a competitive electric energy supply market. Approximately 45% of the Company's retail revenues are from its Pennsylvania subsidiary, West Penn. On August 1, 1997, West Penn filed with the Pennsylvania Public Utility Commission (Pennsylvania PUC) a comprehensive restructuring plan to implement full customer choice of electricity suppliers as required by the Customer Choice Act. The filing
Allegheny Energy, Inc.
included a plan for recovery of transition costs (sometimes referred to as stranded costs) through a Competitive Transition Charge (CTC).
Transition costs are costs incurred under a regulated environment, which may not be recoverable in a competitive market. The amount of transition costs has been a key issue in the restructuring proceedings. Since the installed costs of utility facilities are known, the key variable in transition cost determinations in Pennsylvania was the projection of market prices of electricity in future periods. West Penn's restructuring plan filing included its determination of its transition costs based on its projection of future market prices. West Penn's recoverable transition costs were limited to $1.2 billion by rate caps mandated by the Customer Choice Act.
On May 29, 1998, the Pennsylvania PUC issued an Order authorizing West Penn recovery of approximately $595 million (or $525 million in the event of the merger) in transition costs, with a return, based on alternative projections of future market prices. On June 26, 1998, the Pennsylvania PUC denied, except for minor corrections, a request by West Penn for reconsideration of the May 29 Order. On that same day, West Penn filed a formal appeal in state court and an action in federal court challenging the Pennsylvania PUC's restructuring Order.
As a result of the May 29, 1998, Order, West Penn determined that it was required to discontinue the application of SFAS No. 71 for electric generation operations and adopt SFAS No. 101. In doing so, West Penn also determined that, under the provisions of SFAS No. 101, an extraordinary charge of $450.6 million ($265.4 million after taxes) was required to reflect adverse power purchase commitments and deferred costs that are not recoverable from customers under the Pennsylvania PUC's Order.
While pursuing its litigation, West Penn participated in settlement discussions with interested parties regarding issues related to the restructuring Order. A negotiated settlement was achieved, and, on November 19, 1998, the Pennsylvania PUC granted final approval to West Penn's restructuring settlement agreement. The settlement agreement includes the following provisions:
- - Agreement by the parties to withdraw all litigation related to the Pennsylvania deregulation proceedings.
- - Establishment of an average shopping credit of 3.16 cents per kilowatt-hour in 1999 for West Penn customers who shop for the generation portion of electricity services.
- - Two-thirds of West Penn's customers have the option of selecting a generation supplier on January 2, 1999, with all customers able to shop on January 2, 2000.
- - Requires a rate refund from 1998 revenue (about $25 million) via a 2.5% rate decrease throughout 1999, accomplished by an equal percentage decrease for each rate class.
Allegheny Energy, Inc.
- - Provides that customers will have the option of buying electricity from West Penn at capped generation rates through 2008, and that transmission and distribution rates are capped through 2005, except that the capped rates are subject to certain increases as provided for in the Public Utility Code.
- - Prohibits complaints challenging West Penn's regulated transmission and distribution rates through 2005.
- - Provides about $15 million of West Penn funding for the development and use of renewable energy and clean energy technologies, energy conservation, energy efficiency, etc.
- - Permits recovery of $670 million in transition costs plus return over 10 years beginning in January 1999 for West Penn. In the event that the merger of Allegheny Energy, Inc. and DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., is consummated, the transition costs will be adjusted to $630 million plus return to provide a sharing of merger synergy savings with customers.
- - Allows for income recognition of transition cost recovery in the earlier years of the transition period to reflect the Pennsylvania PUC's projections that electricity market prices are lower in the earlier years.
- - Grants West Penn's application to issue bonds to securitize up to $670 million (or $630 million in the event of the merger) in transition costs and to provide 75% of the associated savings to customers with 25% to shareholders.
- - Authorizes the transfer of West Penn's generating assets to a nonutility affiliate at book value. Subject to certain time-limited exceptions, the nonutility business can compete in the unregulated energy market.
- - If West Penn is forced to divest some generating assets or chooses to divest all of its generation before 2002, the CTC will be adjusted, either up or down, based on the results of such divestiture.
As a result of the November 19, 1998, settlement agreement, the extraordinary charge was increased by $16.3 million ($10.0 million after taxes) to $466.9 million ($275.4 million after taxes), and additional charges of $40.3 million ($23.7 million after taxes) related to the West Penn revenue refund and energy program payments were also recorded. See Note C for additional details. Pursuant to Pennsylvania PUC Orders, starting in 1999, West Penn is unbundling its rates to reflect separate prices for the supply charge, the CTC, and transmission and distribution charges. While supply will be open to competition, West Penn will continue to provide regulated transmission and distribution services to customers in its service area at Pennsylvania PUC- and FERC-regulated rates and will be the electricity provider of last resort for those customers who decide not to choose another electricity supplier.
Allegheny Energy, Inc.
As stated above, West Penn made its filing concerning its transition cost requirements based on its early 1997 projection of market prices. The Pennsylvania PUC issued its May 29, 1998, Order to West Penn, as well as its 1998 orders to all other Pennsylvania electric utilities, based on alternative projections. Current prices, which the Company believes are being influenced, among other things, by price volatility in the summer of 1998, are equal to and in some cases higher than the projections adopted by the Pennsylvania PUC in its deregulation orders issued to West Penn and other utilities in the state. If the Pennsylvania PUC's projections are correct, West Penn believes that the transition costs provided will be sufficient to permit it to recover its embedded costs, with a return, during the transition from regulation to deregulation of electricity generation.
The West Penn settlement agreement authorizes West Penn to create a CTC regulatory asset for specified CTC revenues in 1999 through 2002 to be amortized in 2005 through 2008. The regulatory asset booking of CTC revenue acts to accelerate recognition of transition cost recovery. In addition, the settlement agreement specifies how CTC revenues will be allocated between return on and recovery of transition costs. Amortization of regulatory assets in 1999 through 2008 under the Pennsylvania PUC-approved settlement agreement results in smaller amortization expense in the early years of the transition period which favorably affects earnings in those years.
Also pursuant to the Customer Choice Act, all electric utilities in Pennsylvania were required to establish and administer retail access pilot programs under which customers representing 5% of the load of each rate class would choose an electricity supplier other than their own local franchise utility. The pilot programs began on November 1, 1997, and continued through December 31, 1998. As ordered by the Pennsylvania PUC, pilot participants received an energy credit to their bills from their local utility and paid an alternate supplier for energy. To assure participation in the pilot program, the credit established by the Pennsylvania PUC was artificially high (greater than West Penn's generation costs), with the result that West Penn suffered a loss of $6.5 million. West Penn attempted to mitigate the loss by competing for sales to pilot participants of other utilities as an alternate supplier. The Pennsylvania PUC approved West Penn's pilot compliance filing and thus has indicated its intent to treat the revenue losses as a regulatory asset subject to review and potential rate recovery. Because sales prices were low and margins were commensurately thin, West Penn was unable to completely offset its pilot losses with new revenues. Accordingly, West Penn deferred the net revenue losses as a regulatory asset.
Note C: Accounting for the Effects of Price Deregulation
In 1997, the FASB, through its Emerging Issues Task Force (EITF), issued EITF No. 97-4, "Deregulation of the Pricing of Electricity-Issues Related to the Application of FASB Statement Numbers 71 and 101." In EITF 97-4, the EITF agreed that when a rate order that contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated is issued, the entity should cease to apply SFAS No. 71 to that separable portion of its business. West Penn believes that the Pennsylvania PUC Order dated May 29, 1998, as described in Note B which begins on page 50, provides
Allegheny Energy, Inc.
sufficient details regarding the deregulation of West Penn's electric generation operations to require discontinuation of the application of SFAS No. 71 for its electric generation operations. Effective June 30, 1998, West Penn adopted the provisions of SFAS No. 101 for its electric generation operations. West Penn determined that under the provisions of SFAS No. 101, an extraordinary charge of $466.9 million ($275.4 million after taxes) was required to reflect a write-off of certain disallowances in the Pennsylvania PUC's May 29, 1998, Order, as revised by the Pennsylvania PUC-approved November 19, 1998, settlement agreement. The write-off reflects adverse power purchase commitments and deferred costs that are not recoverable from customers under the Pennsylvania PUC's Order and settlement agreement as follows:
(Millions of Dollars) Gross Net-of-Tax
AES Beaver Valley nonutility generation contract $197.5 $116.5 AGC pumped storage capacity contract 165.6 97.7 Other 103.8 61.2
Total extraordinary charge $466.9 $275.4
In 1985, West Penn entered into a contract with Applied Energy Services (AES) Corporation for the purchase of energy from AES's Beaver Valley generating plant in Pennsylvania pursuant to the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).
West Penn owns 45% of AGC, which owns an undivided 40% interest in the 2,100-MW pumped-storage hydroelectric station in Bath County, Va. West Penn buys AGC's capacity in the station priced under a cost of service formula wholesale rate schedule approved by the FERC.
Under both of these contracts, West Penn has purchase commitments at costs in excess of the market value of energy from the plants. Because of utility restructuring under the Customer Choice Act, these commitments have been determined to be adverse purchase commitments requiring accrual as loss contingencies pursuant to SFAS No. 5, "Accounting for Contingencies." The extraordinary charge before taxes for these contracts is the net result of such excess cost accruals (recorded as adverse power purchase commitments) less estimated revenue recoveries authorized in the Pennsylvania PUC Order (recorded as regulatory assets) as follows:
Various assumptions and estimates were made in determining the extraordinary charge to income discussed on page 52. The most significant relate to future electricity prices. To the extent that future electricity prices differ from the Company's estimates, adjustments to the reserve for adverse power purchase commitments may be required.
The other $103.8 million of extraordinary charges represents $55.0 million of deferred unrecovered expenditures for previous PURPA buyouts,
Allegheny Energy, Inc.
$13.5 million for an abandoned generating plant, and $35.3 million of other generation-related regulatory assets, primarily related to SFAS No. 109, "Accounting for Income Taxes."
The Consolidated Balance Sheet includes the amounts listed below for generation assets not subject to SFAS No. 71.
December December (Thousands of Dollars) 1998 1997
Property, plant, and equipment at original cost $1,969,636 $1,951,066 Amounts under construction included above 39,227 51,715 Accumulated depreciation (870,777) (793,166)
In addition to the extraordinary charge and as a result of the settlement agreement, a fourth quarter charge to earnings of $40.3 million ($23.7 million after taxes) resulted from the required West Penn refund throughout 1999 from 1998 revenues of about $25 million and a $15 million provision for energy programs.
The Company's other utility subsidiaries could be subjected to retail electric supply competition in four additional states- West Virginia, Maryland, Virginia, and Ohio. Additional charges of the sort incurred in connection with Pennsylvania deregulation could result from such proceedings.
Note D: Proposed Merger
On April 7, 1997, the Company and DQE, parent company of Duquesne Light Company in Pittsburgh, Pa., announced that they had agreed to merge in a tax-free, stock-for-stock transaction.
At separate meetings held on August 7, 1997, the shareholders of the Company and DQE approved the merger. The Company and DQE made all necessary regulatory filings. Since then, the Company and DQE received approval of the merger from the Nuclear Regulatory Commission, the Pennsylvania PUC, and the FERC. The Pennsylvania PUC and the FERC approvals were subject to conditions acceptable to the Company. In addition, while not required, the Maryland Public Service Commission and the Public Utilities Commission of Ohio have indicated their approval.
On October 5, 1998, DQE notified the Company that it had unilaterally decided to terminate the merger. The Company believes DQE's action was without basis and was a breach of the merger agreement. In response, the Company filed with the United States District Court for the Western District of Pennsylvania on October 5, 1998, a lawsuit for specific performance of the merger agreement or, alternatively, damages. The Company also filed motions for preliminary injunctive relief against DQE.
On October 28, 1998, the District Court denied the Company's motions for preliminary injunctive relief. The District Court did not rule on the merits of the lawsuit for specific performance or damages. On October 30, 1998, the Company appealed the District Court's Order to the United States Court of Appeals for the Third Circuit. The Company cannot predict the outcome of this litigation.
Allegheny Energy, Inc.
All of the Company's incremental costs of the merger process ($17.6 million through December 31, 1998) are being deferred. The accumulated merger costs will be written off by the combined company when the merger occurs or by the Company if it is determined that the merger will not occur.
Note E: Internal Restructuring Charges and Asset Write-Off
In 1996, the Company and its subsidiaries completed their internal restructuring activities initiated in 1994, simplifying the management structure and streamlining operations. During 1996, restructuring activities included consolidating operating divisions, customer services, and other functions.
In 1996, the subsidiaries recorded restructuring charges of $93.1 million ($56.2 million after tax) in operating expenses, including all restructuring charges associated with the reorganization. These charges reflected liabilities and payments for severance, employee termination costs, and other restructuring costs. The current portion of the restructuring liability, reflected in other current liabilities, excluding benefit plans curtailment adjustments to postretirement liabilities (which are primarily recorded in other deferred credits), consists of:
(Thousands of Dollars) 1998 1997
Restructuring liability: Balance at beginning of period $ 5,504 $ 56,101 Less payments and accrual reversals (5,504) (50,597)
Balance at end of period $ - $ 5,504
In 1996, the utility subsidiaries wrote off $10.8 million ($6.3 million after tax) of previously accumulated costs related to a proposed transmission line. In the industry's more competitive environment, it was no longer reasonable to assume future recovery of these costs in rates.
Note F: Income Taxes
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Income taxes-current: Federal $114,319 $ 87,394 $ 83,456 State 33,385 23,960 26,004
Total 147,704 111,354 109,460
Income taxes-deferred, net of amortization 28,920 74,565 29,129 Income taxes-deferred, extraordinary charge (191,480) Amortization of deferred investment credit (7,922) (8,203) (8,242)
Total income taxes (22,778) 177,716 130,347
Income taxes-charged to other income and deductions (306) (9,643) (2,355) Income taxes-credited to extraordinary charge 191,480
Income taxes-charged to operating income $168,396 $168,073 $127,992
Allegheny Energy, Inc.
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:
(Thousands of Dollars) 1998 1997 1996
Income before preferred dividends, income taxes, and extraordinary charge $440,655 $458,649 $347,319
Amount so produced $154,229 $160,527 $121,562 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower tax depreciation 6,700 14,200 12,600 Plant removal costs (2,400) (1,700) (1,900) State income tax, net of federal income tax benefit 20,200 11,700 14,100 Amortization of deferred investment credit (7,922) (8,203) (8,242) Other, net (2,411) (8,451) (10,128)
Total $168,396 $168,073 $127,992
The provision for income taxes for the extraordinary charge is different from the amount produced by applying the federal income statutory tax rate of 35% to the gross amount, as set forth below:
(Thousands of Dollars) 1998
Extraordinary charge before income taxes $466,905
Amount so produced $163,417 Increased for state income tax, net of federal income tax benefit 28,063
Total $191,480
Federal income tax returns through 1993 have been examined and substantially settled through 1991.
Allegheny Energy, Inc.
At December 31, the deferred tax assets and liabilities consisted of the following:
(Thousands of Dollars) 1998 1997 Deferred tax assets: CTC recovery $ 154,530 Unamortized investment tax credit 77,213 $ 83,818 Tax interest capitalized 35,375 35,954 Postretirement benefits other than pensions 31,047 21,986 Contributions in aid of construction 23,643 22,980 Unbilled revenue 13,380 13,657 Revenue refund 10,301 Deferred power costs, net 8,736 10,598 Other 47,782 38,578 402,007 227,571 Deferred tax liabilities: Book vs. tax plant basis differences, net 1,174,453 1,142,035 Other 88,465 104,415 1,262,918 1,246,450 Total net deferred tax liabilities 860,911 1,018,879 Portion above included in current (liabilities) assets (18,718) 12,357
Total long-term net deferred tax liabilities $ 842,193 $1,031,236
Note G: Dividend Restriction
Supplemental indentures relating to certain outstanding bonds of Monongahela Power and West Penn contain dividend restrictions under the most restrictive of which $121,015,000 of the Company's consolidated retained earnings at December 31, 1998, 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 H: Pension Benefits and Postretirement Benefits Other Than Pensions
Net periodic (credit) cost for pension and 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:
Allegheny Energy, Inc.
The discount rates and rates of compensation increases used in determining the benefit obligations at September 30, 1998, 1997, and 1996, and the expected long-term rate of return on assets in each of the years 1998, 1997, and 1996 were as follows:
1998 1997 1996 1998 1997 1996 Discount rate 7.00% 7.25% 7.50% 7.00% 7.25% 7.50% Expected return on plan assets 9.00% 9.00% 9.00% 8.25% 8.25% 8.25% Rate of compensation increase 4.00% 4.25% 4.50% 4.00% 4.25% 4.50%
For postretirement benefits other than pensions measurement purposes, a health care cost trend rate of 6% for 1999 and beyond and plan provisions which limit future medical and life insurance benefits were assumed. Because of the plan provisions which limit future benefits, the assumed health care cost trend rate has a limited effect on the amounts reported. A one-percentage-point change in the assumed health care cost trend rate would have the following effects:
The amounts (prepaid) accrued at December 31, using a measurement date of September 30, included the following components:
Allegheny Energy, Inc.
Note I: Regulatory Assets and Liabilities
The Company's utility operations are subject to the provisions of SFAS No. 71. 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:
(Thousands of Dollars) 1998 1997 Long-Term Assets (Liabilities), Net: Income taxes, net $305,415 $417,382 CTC recovery 292,718 PURPA project buyout 48,000 Demand-side management 8,157 14,204 Pennsylvania pilot deferred revenue 6,726 Postretirement benefits 6,229 7,053 Storm damage 2,101 3,537 Deferred power costs, net (reported in other deferred charges/credits) (2,455) 4,051 Other, net 2,806 4,771
Subtotal 621,697 498,998
Current Assets (Liabilities), Net: CTC recovery 17,372 Income taxes, net 1,847 1,847 Deferred power costs, net (reported in other current assets/liabilities) 7,211 2,198
Subtotal 26,430 4,045
Net Regulatory Assets $648,127 $503,043
Allegheny Energy, Inc.
Deregulation/competition proceedings in West Virginia, Virginia, Maryland, and Ohio may in the future result in less than full recovery of costs incurred to serve customers. This would then require additional charges of the type recorded in 1998 for West Penn as discussed in Notes B and C starting on pages 50 and 52, respectively, in connection with Pennsylvania's deregulation proceedings. Such charges, if any, are not estimable at this time.
Note J: 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 the life insurance contracts was estimated based on cash surrender value. 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 swap and option contract was estimated based on the present value of future cash flows associated with these instruments. The carrying amount of the swap represents a liability associated with the refinancing transaction which occurred in January 1998. The Company has no financial instruments held or issued for trading purposes.
Note K: 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's market auction preferred stock are entitled to dividends at a rate determined quarterly by an auction process.
Long-Term Debt and QUIDS
Maturities for long-term debt in thousands of dollars for the next five years are: 1999, none; 2000, $140,000; 2001, $160,000; 2002, $63,810; and 2003, $254,075. 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.
Allegheny Energy, Inc.
In October 1996, AYP Energy, Inc. (AYP Energy), a subsidiary of AYP Capital, borrowed $160 million for five years from a syndicate of eight banks priced at the London Interbank Offering Rate (LIBOR) plus a spread. AYP Energy also entered into a floating-to-fixed interest rate swap to hedge against fluctuations in interest rates. The swap plus the spread on the underlying financing fixed the interest rate to AYP Energy at 6.78%. In January 1998, the swap was refinanced in exchange for the counterparty's right to exercise an option to extend the swap until 2006. The new swap plus the spread on the underlying financing lowered the interest rate to AYP Energy to 6.18%. During 1998, the Company recorded a mark-to-market loss of $2.3 million related to this option.
Note L: 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, 1998, unused lines of credit with banks were $300 million. 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 1998 and 1997 consisted of:
(Thousands of Dollars) 1998 1997
Balance and interest rate at end of year: Commercial paper $208,837-5.40% $166,401-6.14% Notes payable to banks 50,000-5.40% 40,000-6.75%
Average amount outstanding and interest rate during the year: Commercial paper 171,393-5.60% 100,572-5.62% Notes payable to banks 44,789-5.62% 13,022-5.60%
Note M: Business Segments
In June 1997, the FASB issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," to establish standards for reporting information about operating segments in financial statements. The Company's principal business segments are utility and nonutility operations. The utility subsidiaries, doing business as Allegheny Power, include the generation, purchase, transmission, distribution, and sale of electric energy. Allegheny Power derives substantially all of its income from operations of its utility subsidiaries, Monongahela Power, Potomac Edison, and West Penn. Nonutility operations consists of AYP Capital, a wholly owned subsidiary, formed in an effort to meet the challenges of the new competitive environment in the electric industry. AYP Capital has three wholly owned subsidiaries, AYP Energy, Allegheny Communications Connect, Inc. (ACC), and Allegheny Energy Solutions, Inc. (Allegheny Energy Solutions). AYP Energy is a power marketer. ACC is an exempt telecommunications company under the PUHCA. Allegheny Energy Solutions was formed to market electric energy to retail customers in deregulated markets. Because of organizational
Allegheny Energy, Inc.
efficiencies available in an alternate corporate structure, Allegheny Energy Solutions no longer competes in deregulated markets. Rather, that role has been assumed by the Energy Supply Division of the Supply Business of West Penn, acting under the name Allegheny Energy Supply. AYP Capital, in its own name, also markets various services related to the electric industry and has investments in two limited energy partnerships.
Business segment information for 1998, 1997, and 1996 is summarized below. Transactions between affiliates are recognized at prices which approximate market value. Significant transactions between reportable segments are eliminated to reconcile the segment information to consolidated amounts. The identifiable assets information does not reflect the elimination of intercompany balances or transactions which are eliminated in the Company's consolidated financial statements.
The 1998 utility extraordinary charge, net, reflects a write- off of certain disallowances in the Pennsylvania PUC's May 29, 1998, restructuring Order and resulting November 19, 1998, settlement agreement with regard to West Penn as described in Notes B and C, starting on pages 50 and 52, respectively.
Allegheny Energy, Inc.
Note N: Commitments and Contingencies
Construction Program
The subsidiaries have entered into commitments for their construction programs, for which expenditures are estimated to be $315 million for 1999 and $294 million for 2000. Construction expenditure levels in 2001 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. The Company estimates that its banked emission allowances will allow it to comply with Phase II sulfur dioxide (SO2) limits through 2005. Studies to evaluate cost-effective options to comply with Phase II SO2 limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.
Market Risk
The Company's utility subsidiaries and AYP Energy, one of the Company's nonutility subsidiaries, supply power in the bulk power market. At December 31, 1998, the marketing books for such operations consisted primarily of fixed-priced, forward-purchase and/or sale contracts which require settlement by physical delivery of electricity. These transactions result in market risk, which occurs when the market price of a particular obligation or entitlement varies from the contract price.
The Company has a Corporate Energy Risk Control Policy adopted by the Board of Directors and monitored by an Exposure Management Committee of senior management. This policy requires continuous monitoring for conformity to policies which limit value at risk and market risk associated with the credit standing of trading counterparties. Such credit standing must be within the guidelines established by the Company's Risk Control Policy. The Company's exposure to volatility in the price of electricity and other energy commodities is maintained within approved policy limits, but has increased as a result of Pennsylvania restructuring, which created retail access to a deregulated electric supply market.
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 adversely affect the cost of future operations.
The Environmental Protection Agency (EPA) issued its final regional nitrogen oxides (NOx) State Implementation Plan (SIP) call rule on September 24, 1998. The EPA's SIP call rule found that 22 eastern states (including Maryland, Pennsylvania, and West Virginia) and the District of Columbia are all contributing significantly to ozone nonattainment in downwind states. The final rule declares that this downwind nonattainment will be eliminated (or sufficiently mitigated) if the upwind states reduce their NOx emissions by an
Allegheny Energy, Inc.
amount that is precisely set by the EPA on a state-by-state basis. The final SIP call rule requires that all state-adopted NOx reduction measures must be incorporated into SIPs by September 24, 1999, and must be implemented by May 1, 2003. The Company's compliance with these requirements would require the installation of post-combustion control technologies on most, if not all, of its power stations at a cost of approximately $360 million. The Company continues to work with other coal-burning utilities and other affected constituencies in coal-producing states to challenge this EPA action.
The utility subsidiaries previously reported that the EPA had identified them as potentially responsible parties, along with approximately 175 others, 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 regulated subsidiaries have also been named as defendants along with multiple other defendants in pending asbestos cases involving one or more plaintiffs. The utility 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 and the Shareholder of Monongahela Power Company
In our opinion, the accompanying balance sheet, 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 Energy, Inc.) at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
Monongahela Power Company
STATEMENT OF INCOME
See accompanying notes to financial statements.
Monongahela Power Company
STATEMENT OF CASH FLOWS
See accompanying notes to financial statements.
Monongahela Power Company BALANCE SHEET
(Thousands of Dollars) DECEMBER 31
1998 1997 ASSETS
Property, Plant, and Equipment: At original cost, including $43,657 and $55,588 under construction........... $2,007,876 $1,950,478 Accumulated depreciation............... (883,915) (840,525)
1,123,961 1,109,953 Investments: Allegheny Generating Company--common stock at equity....................... 44,624 53,888 Other.................................. 231 268
44,855 54,156 Current Assets: Cash................................... 1,835 1,686 Accounts receivable: Electric service, net of $2,516 and $2,176 uncollectible allowance...... 68,293 68,143 Affiliated and other................. 19,674 10,917 Materials and supplies--at average cost: Operating and construction........... 21,942 18,716 Fuel................................. 16,588 15,885 Prepaid taxes.......................... 19,627 17,287 Other, including current portion of regulatory assets.................. 9,652 3,559
157,611 136,193 Deferred Charges: Regulatory assets...................... 154,882 164,260 Unamortized loss on reacquired debt.... 17,826 14,338 Other.................................. 19,893 14,354
192,601 192,952 Total.................................... $1,519,028 $1,493,254
CAPITALIZATION AND LIABILITIES
Capitalization: Common stock, other paid-in capital, and retained earnings................. $ 570,188 $ 540,930 Preferred stock........................ 74,000 74,000 Long-term debt and QUIDS............... 453,917 455,088
1,098,105 1,070,018 Current Liabilities: Short-term debt........................ 49,000 56,829 Long-term debt due within one year..... 20,100 Notes payable to affiliates............ 1,450 Accounts payable....................... 13,080 5,910 Accounts payable to affiliates......... 13,958 5,804 Taxes accrued: Federal and state income............. 6,277 5,046 Other................................ 23,192 18,935 Interest accrued....................... 7,692 7,877 Other.................................. 13,362 13,470
126,561 135,421 Deferred Credits and Other Liabilities: Unamortized investment credit.......... 16,155 18,297 Deferred income taxes.................. 242,805 235,291 Regulatory liabilities................. 15,476 16,973 Other.................................. 19,926 17,254
294,362 287,815 Commitments and Contingencies (Note L) Total................................... $1,519,028 $1,493,254
See accompanying notes to financial statements
Monongahela Power Company STATEMENT OF CAPITALIZATION
Preferred Stock: Cumulative preferred stock--par value $100 per share, authorized 1,500,000 shares, outstanding as follows:
Long-Term Debt and QUIDS:
December 31, 1998 Interest Rate
See accompanying notes to financial statements.
Monongahela Power Company
NOTES TO FINANCIAL STATEMENTS (These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Monongahela Power Company (the Company) is a wholly owned subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a part of the Allegheny Energy integrated electric utility system (the System). The Company and its utility affiliates, The Potomac Edison Company and West Penn Power Company, do business as Allegheny Power.
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 utilities and power marketers, 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. Costs include 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 indirect costs such as administration, maintenance, and depreciation of transportation and construction equipment, postretirement benefits, taxes, and other 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
Monongahela Power Company
of property, plant, and equipment with offsetting credits to other income and interest charges. Rates used for computing AFUDC in 1998, 1997, and 1996 were 6.56%, 7.55%, and 7.90%, respectively. AFUDC is not included in the cost of 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% of average depreciable property in each of the years 1998, 1997, and 1996. 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 Assets and Liabilities 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 include certain assets and liabilities based on 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 using 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 of Allegheny Energy, Inc. 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.
Monongahela Power Company
The Company and its affiliates also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up 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.
Capitalized Software Costs The Company capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over a five-year period beginning upon a project's completion.
Comprehensive Income SFAS No. 130, "Reporting Comprehensive Income," effective for 1998, established standards for reporting comprehensive income and its components (revenues, expenses, gains, and losses) in financial statements. The Company does not have any elements of other comprehensive income to report in accordance with SFAS No. 130.
Business Segments SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," established standards for reporting information about operating segments in financial statements. The Company's principal business segment is utility operations which includes the generation, purchase, transmission, distribution, and sale of electricity.
NOTE B: PROPOSED MERGER
On April 7, 1997, the Company's parent, Allegheny Power System, Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., announced that they had agreed to merge in a tax-free, stock-for- stock transaction.
At separate meetings held on August 7, 1997, the shareholders of Allegheny Energy and DQE approved the merger. Allegheny Energy and DQE made all necessary regulatory filings. Since then, Allegheny Energy and DQE received approval of the merger from the Nuclear Regulatory Commission, the Pennsylvania Public Utility Commission (Pennsylvania PUC), and the FERC. The Pennsylvania PUC and the FERC approvals were subject to conditions acceptable to Allegheny Energy. In addition, while not required, the Maryland Public Service Commission and the Public Utilities Commission of Ohio have indicated their approval.
On October 5, 1998, DQE notified Allegheny Energy that it had unilaterally decided to terminate the merger. Allegheny Energy believes DQE's action was without basis and was a breach of the merger agreement. In response, Allegheny Energy filed with the United States District Court for the Western District of Pennsylvania on October 5, 1998, a lawsuit for specific performance of the merger agreement or, alternatively, damages. Allegheny Energy also filed motions for preliminary injunctive relief against DQE.
On October 28, 1998, the District Court denied Allegheny Energy's motions for preliminary injunctive relief. The District Court did not rule on the merits of the lawsuit for specific performance or damages. On October 30, 1998, Allegheny Energy appealed the District Court's Order to the United States
Monongahela Power Company
Court of Appeals for the Third Circuit. Allegheny Energy cannot predict the outcome of this litigation.
All of the Company's incremental costs of the merger process ($4.4 million through December 31, 1998) are being deferred. The accumulated merger costs will be written off by the Company when the merger occurs or if it is determined that the merger will not occur.
NOTE C: INTERNAL RESTRUCTURING CHARGES
In 1996, the System, including the Company, completed its internal restructuring activities initiated in 1994, simplifying the management structure and streamlining operations. During 1996, restructuring activities included consolidating operating divisions, customer services, and other functions.
In 1996, the Company recorded restructuring charges of $24.3 million ($14.6 million after tax) in operating expenses, including its share of all restructuring charges associated with the reorganization. These charges reflected liabilities and payments for severance, employee termination costs, and other restructuring costs. The current portion of the restructuring liability, reflected in other current liabilities, excluding benefit plans curtailment adjustments to postretirement liabilities (which are primarily recorded in other deferred credits), consists of:
(Thousands of Dollars) 1998 1997
Internal restructuring liability: Balance at beginning of period.................... $ 236 $13,997 Less payments and accrual reversals............... (236) (13,761) Balance at end of period............................ $ - $ 236
As part of the reorganization, the Company and its utility affiliates in 1996 expanded the intercompany use of each other's employees to optimize the use of their skills. In 1997 virtually all the employees in the System, including all of the Company's employees, were transferred to Allegheny Power Service Corporation (APSC) to facilitate the intercompany use of personnel. APSC was formed in 1963 pursuant to the Public Utility Holding Company Act of 1935 to perform certain functions common to all companies in the System. APSC bills each company at its cost (without profit) based on the work performed and services provided to each company.
Monongahela Power Company
NOTE D: INCOME TAXES
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Income taxes--current: Federal............................. $26,457 $21,812 $19,412 State............................... 8,135 7,455 7,317 Total............................. 34,592 29,267 26,729 Income taxes--deferred, net of amortization........................ 16,971 20,287 9,883 Amortization of deferred investment credit................... (2,144) (2,148) (2,145) Total income taxes................ 49,419 47,406 34,467 Income taxes--credited to other income and deductions............... 37 113 29 Income taxes--charged to operating income.............................. $49,456 $47,519 $34,496
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:
(Thousands of Dollars) 1998 1997 1996
Income before income taxes............ $131,881 $128,048 $ 95,948 Amount so produced.................... $ 46,158 $ 44,817 $ 33,582 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower tax depreciation.......... 1,800 5,000 4,300 Plant removal costs............. (2,600) (2,400) (2,200) State income tax, net of federal income tax benefit................ 4,400 3,600 4,000 Amortization of deferred investment credit................. (2,144) (2,148) (2,145) Equity in earnings of subsidiaries.. (2,100) (3,000) (2,500) Other, net.......................... 3,942 1,650 (541) Total............................. $ 49,456 $ 47,519 $ 34,496
Federal income tax returns through 1993 have been examined and substantially settled through 1991.
Monongahela Power Company
At December 31, the deferred tax assets and liabilities consisted of the following:
(Thousands of Dollars) 1998 1997
Deferred tax assets: Unamortized investment tax credit............... $ 10,779 $ 12,275 Tax interest capitalized........................ 4,269 4,500 Contributions in aid of construction............ 2,810 2,619 Advances for construction....................... 2,097 2,087 Internal restructuring.......................... 1,810 53 Deferred power costs, net....................... 1,266 Other........................................... 14,358 12,090 36,123 34,890 Deferred tax liabilities: Book vs. tax plant basis differences, net....... 244,432 236,962 Other........................................... 38,420 33,865 282,852 270,827 Total net deferred tax liabilities................ 246,729 235,937 Portion above included in current liabilities..... (3,924) (646) Total long-term net deferred tax liabilities.... $242,805 $235,291
NOTE E: 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 the Company's retained earnings at December 31, 1998, 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 F: 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 is reported by the Company in its financial statements using the equity method of accounting. 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). 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.
Monongahela Power Company
Following is a summary of financial information for AGC:
December 31 (Thousands of Dollars) 1998 1997
Balance sheet information: Property, plant, and equipment............... $618,608 $635,485 Current assets............................... 5,857 11,876 Deferred charges............................. 14,993 16,559 Total assets............................... $639,458 $663,920
Total capitalization......................... $314,105 $348,258 Current liabilities.......................... 75,849 70,540 Deferred credits............................. 249,504 245,122 Total capitalization and liabilities....... $639,458 $663,920
Year Ended December 31 (Thousands of Dollars) 1998 1997 1996
Income statement information: Electric operating revenues......... $73,816 $76,458 $83,402 Operation and maintenance expense... 4,592 4,877 5,165 Depreciation........................ 16,949 17,000 17,160 Taxes other than income taxes....... 4,662 4,835 4,801 Federal income taxes................ 10,959 11,213 13,297 Interest charges.................... 13,987 15,391 16,193 Other income, net................... (86) (9,126) (3) Net income........................ $22,753 $32,268 $26,789
The Company's share of the equity in earnings was $6.1 million, $8.7 million, and $7.2 million for 1998, 1997, and 1996, respectively, and is included in other income, net, on the Company's Statement of Income. Dividends received from AGC in 1998 approximated $15 million which reflects an effort to reduce AGC equity to about 45% of total capitalization and short-term debt.
NOTE G: POSTRETIREMENT BENEFITS
As described in Note A, the Company and its affiliates participate in a pension plan and medical and life insurance plans for eligible employees and dependents. The Company is responsible for its proportional share of the costs (credits) and the assets or liabilities of the plans. As described in Note C, in 1997 the Company transferred all of its employees to APSC. The Company's share of the costs (credits) of these plans, a portion of which (about 25% to 35%) was charged to plant construction, is as follows:
(Thousands of Dollars) 1998 1997 1996
Pension................................ $ (356) $(1,754) $ 78 Medical and life insurance............. $5,421 $ 3,706 $5,461
Monongahela Power Company
NOTE H: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS No. 71. 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:
(Thousands of Dollars) 1998 1997
Long-Term Assets (Liabilities), Net: Income taxes, net.............................. $130,878 $137,056 Postretirement benefits........................ 4,937 4,937 Storm damage................................... 1,047 2,211 Other, net..................................... 2,544 3,083 Subtotal..................................... 139,406 147,287 Current Assets (Liabilities), Net: Income taxes, net (reported in other current assets).............................. 1,847 1,847 Deferred power costs, net...................... 6,878 (484) Subtotal..................................... 8,725 1,363 Net Regulatory Assets...................... $148,131 $148,650
Deregulation/competition proceedings in West Virginia and Ohio may in the future result in less than full recovery of costs incurred to serve customers. Such deregulation and transition to a competitive environment could adversely affect the Company's results of operations, cash flows, and capitalization. Such charges, if any, are not estimable at this time.
NOTE I: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:
1998 1997 Carrying Fair Carrying Fair (Thousands of Dollars) Amount Value Amount Value
Liabilities: Short-term debt....... $ 49,000 $ 49,000 $ 58,279 $ 58,279 Long-term debt and QUIDS............... 457,685 483,695 479,710 528,155
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.
Monongahela Power Company
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.
Long-Term Debt and QUIDS Maturities for long-term debt in thousands of dollars for the next five years are: 1999, none; 2000, $65,000; 2001, none; 2002, $27,060; and 2003, $62,575. 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 $106 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 Allegheny Energy 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 1998 and 1997 consisted of:
(Thousands of Dollars) 1998 1997
Balance and interest rate at end of year: Commercial Paper................... $56,829-6.50% Notes Payable to Banks............. $49,000-5.40% Money Pool......................... 1,450-5.96% Average amount outstanding and interest rate during the year: Commercial Paper................... 12,900-5.66% 1,651-5.76% Notes Payable to Banks............. 21,793-5.60% 7,307-5.56% Money Pool......................... 3,764-5.46% 9,300-5.44%
NOTE L: COMMITMENTS AND CONTINGENCIES
Construction Program The Company has entered into commitments for its construction program, for which expenditures are estimated to be $76 million for 1999 and $79 million for 2000. Construction expenditure levels in 2001 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. The Company estimates that its banked emission allowances will allow it to comply with Phase II sulfur dioxide (SO2) limits through 2005. Studies to evaluate cost-effective options to comply with Phase II SO2 limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.
Monongahela Power Company
Market Risk The Company supplies power in the bulk power market. At December 31, 1998, the marketing books for such operations consisted primarily of fixed-priced, forward-purchase and/or sale contracts which require settlement by physical delivery of electricity.
Allegheny Energy has a Corporate Energy Risk Control Policy adopted by the Board of Directors and monitored by an Exposure Management Committee of senior management. This policy requires continuous monitoring for conformity to policies which limit value at risk and market risk associated with the credit standing of counterparties. Such credit standing must be within the guidelines established by Allegheny Energy's Risk Control Policy. The Company's exposure to volatility in the price of electricity and other energy commodities is maintained within approved policy limits.
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 adversely affect the cost of future operations.
The Environmental Protection Agency (EPA) issued its final regional nitrogen oxides (NOx) State Implementation Plan (SIP) call rule on September 24, 1998. The EPA's SIP call rule found that 22 eastern states (including Maryland, Pennsylvania, and West Virginia) and the District of Columbia are all contributing significantly to ozone nonattainment in downwind states. The final rule declares that this downwind nonattainment will be eliminated (or sufficiently mitigated) if the upwind states reduce their NOx emissions by an amount that is precisely set by the EPA on a state-by-state basis. The final SIP call rule requires that all state-adopted NOx reduction measures must be incorporated into SIPs by September 24, 1999, and must be implemented by May 1, 2003. The Company's compliance with these requirements would require the installation of post-combustion control technologies on most, if not all, of its power stations at a cost of approximately $96 million. The Company continues to work with other coal-burning utilities and other affected constituencies in coal-producing states to challenge this EPA action.
The Company previously reported that the EPA had identified it and its regulated affiliates as potentially responsible parties, along with approximately 175 others, 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 and its regulated affiliates have also been named as defendants 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 Potomac Edison Company
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders 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 Energy, Inc.) at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
The Potomac Edison Company
STATEMENT OF INCOME
See accompanying notes to financial statements.
The Potomac Edison Company STATEMENT OF CASH FLOWS
See accompanying notes to financial statements.
The Potomac Edison Company
BALANCE SHEET
(Thousands of Dollars)
DECEMBER 31 ASSETS 1998 1997
Property, Plant, and Equipment: At original cost, including $46,353 and $55,702 under construction........ $2,249,716 $2,196,262 Accumulated depreciation............... (926,840) (859,076)
1,322,876 1,337,186 Investments and Other Assets: Allegheny Generating Company--common stock at equity...................... 46,277 55,847 Other.................................. 473 529
46,750 56,376 Current Assets: Cash................................... 1,805 2,319 Accounts receivable: Electric service, net of $2,203 and $1,683 uncollectible allowance..... 77,170 83,431 Affiliated and other................. 7,091 5,302 Notes receivable from affiliate........ 9,300 1,450 Notes receivable from subsidiary....... 66,750 Materials and supplies--at average cost: Operating and construction........... 29,922 23,715 Fuel................................. 14,098 15,843 Prepaid taxes.......................... 15,727 15,052 Other.................................. 1,092 4,716
222,955 151,828
Deferred Charges: Regulatory assets...................... 66,792 80,651 Unamortized loss on reacquired debt.... 19,012 17,094 Other.................................. 23,742 17,512
109,546 115,257 Total.................................... $1,702,127 $1,660,647
CAPITALIZATION AND LIABILITIES
Capitalization: Common stock, other paid-in capital, and retained earnings................ $ 762,912 $ 689,781 Preferred stock........................ 16,378 16,378 Long-term debt and QUIDS............... 578,817 627,012
1,358,107 1,333,171 Current Liabilities: Long-term debt due within one year..... 1,800 Accounts payable....................... 35,572 29,125 Accounts payable to affiliates......... 31,011 19,929 Deferred income taxes.................. 11,311 Taxes accrued: Federal and state income............. 6,430 2,106 Other................................ 18,922 11,461 Interest accrued....................... 7,193 9,487 Payrolls accrued....................... 6,353 Other.................................. 8,770 10,553
119,209 90,814 Deferred Credits and Other Liabilities: Unamortized investment credit.......... 19,592 21,470 Deferred income taxes.................. 170,349 178,529 Regulatory liabilities................. 11,233 12,424 Other.................................. 23,637 24,239
224,811 236,662 Commitments and Contingencies (Note K) Total.................................... $1,702,127 $1,660,647
See accompanying notes to financial statements.
The Potomac Edison Company
STATEMENT OF CAPITALIZATION
Preferred Stock: Cumulative preferred stock--par value $100 per share, authorized 5,378,611 shares, outstanding as follows:
December 31, 1998
Long-Term Debt and QUIDS:
December 31, 1998 Interest Rate
See accompanying notes to financial statements.
The Potomac Edison Company
NOTES TO FINANCIAL STATEMENTS (These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Potomac Edison Company (the Company) is a wholly owned subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a part of the Allegheny Energy integrated electric utility system (the System). The Company and its utility affiliates, Monongahela Power Company and West Penn Power Company, do business as Allegheny Power.
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 $65 million from one industrial customer were 9% of total electric operating revenues in 1998.
Deferred Power Costs, Net The costs of fuel, purchased power, and certain other costs, and revenues from sales to other utilities and power marketers, 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. Costs include 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, postretirement benefits, taxes, and other benefits related to employees engaged in construction.
The cost of depreciable property units retired, plus removal costs less salvage, are charged to accumulated depreciation.
The Potomac Edison Company
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 1998, 1997, and 1996 were 9.83%, 9.75%, and 9.32%, respectively. AFUDC is not included in the cost of 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 3.5% of average depreciable property in each of the years 1998 and 1997, and 3.6% in 1996. 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 Assets and Liabilities 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 include certain assets and liabilities based on 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 using 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
The Potomac Edison Company
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 of Allegheny Energy, Inc. 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 and its affiliates also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up 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.
Capitalized Software Costs The Company capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over a five-year period beginning upon a project's completion.
Comprehensive Income SFAS No. 130, "Reporting Comprehensive Income," effective for 1998, established standards for reporting comprehensive income and its components (revenues, expenses, gains, and losses) in financial statements. The Company does not have any elements of other comprehensive income to report in accordance with SFAS No. 130.
Business Segments SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," established standards for reporting information about operating segments in financial statements. The Company's principal business segment is utility operations which includes the generation, purchase, transmission, distribution, and sale of electricity.
NOTE B: PROPOSED MERGER
On April 7, 1997, the Company's parent, Allegheny Power System, Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., announced that they had agreed to merge in a tax-free, stock-for- stock transaction.
At separate meetings held on August 7, 1997, the shareholders of Allegheny Energy and DQE approved the merger. Allegheny Energy and DQE made all necessary regulatory filings. Since then, Allegheny Energy and DQE received approval of the merger from the Nuclear Regulatory Commission, the Pennsylvania Public Utility Commission (Pennsylvania PUC), and the FERC. The Pennsylvania PUC and the FERC approvals were subject to conditions acceptable to Allegheny Energy. In addition, while not required, the Maryland Public
The Potomac Edison Company
Service Commission and the Public Utilities Commission of Ohio have indicated their approval.
On October 5, 1998, DQE notified Allegheny Energy that it had unilaterally decided to terminate the merger. Allegheny Energy believes DQE's action was without basis and was a breach of the merger agreement. In response, Allegheny Energy filed with the United States District Court for the Western District of Pennsylvania on October 5, 1998, a lawsuit for specific performance of the merger agreement or, alternatively, damages. Allegheny Energy also filed motions for preliminary injunctive relief against DQE.
On October 28, 1998, the District Court denied Allegheny Energy's motions for preliminary injunctive relief. The District Court did not rule on the merits of the lawsuit for specific performance or damages. On October 30, 1998, Allegheny Energy appealed the District Court's Order to the United States Court of Appeals for the Third Circuit. Allegheny Energy cannot predict the outcome of this litigation.
All of the Company's incremental costs of the merger process ($5.2 million through December 31, 1998) are being deferred. The accumulated merger costs will be written off by the Company when the merger occurs or if it is determined that the merger will not occur.
NOTE C: INTERNAL RESTRUCTURING CHARGES
In 1996, the System, including the Company, completed its internal restructuring activities initiated in 1994, simplifying the management structure and streamlining operations. During 1996, restructuring activities included consolidating operating divisions, customer services, and other functions.
In 1996, the Company recorded restructuring charges of $26.1 million ($16.5 million after tax) in operating expenses, including its share of all restructuring charges associated with the reorganization. These charges reflected liabilities and payments for severance, employee termination costs, and other restructuring costs. The current portion of the restructuring liability, reflected in other current liabilities, excluding benefit plans curtailment adjustments to postretirement liabilities (which are primarily recorded in other deferred credits) consists of:
(Thousands of Dollars) 1998 1997
Internal restructuring liability: Balance at beginning of period.................... $1,187 $14,970 Less payments and accrual reversals............... (1,187) (13,783) Balance at end of period............................ $ - $ 1,187
As part of the reorganization, the Company and its utility affiliates in 1996 expanded the intercompany use of each other's employees to optimize the use of their skills. In 1997 virtually all the employees in the System, including virtually all of the Company's employees, were transferred to Allegheny Power Service Corporation (APSC) to facilitate the intercompany use
The Potomac Edison Company
of personnel. APSC was formed in 1963 pursuant to the Public Utility Holding Company Act of 1935 to perform certain functions common to all companies in the System. APSC bills each company at its cost (without profit) based on the work performed and services provided to each company.
NOTE D: INCOME TAXES
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Income taxes--current: Federal.............................. $40,003 $36,126 $26,651 State................................ 5,569 5,264 4,833 Total.............................. 45,572 41,390 31,484 Income taxes--deferred, net of amortization......................... 10,559 8,136 7,351 Amortization of deferred investment credit............................... (1,877) (2,152) (2,194) Total income taxes................. 54,254 47,374 36,641 Income taxes--charged to other income and deductions................ (1,651) (2,878) (2,509) Income taxes--charged to operating income............................... $52,603 $44,496 $34,132
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:
(Thousands of Dollars) 1998 1997 1996
Income before income taxes............. $154,085 $140,251 $112,305 Amount so produced..................... $ 53,930 $ 49,088 $ 39,307 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower tax depreciation........... 2,800 2,900 4,300 Plant removal costs............. (800) (700) (1,800) State income tax, net of federal income tax benefit................. 5,100 4,400 1,300 Amortization of deferred investment credit............................. (1,878) (2,152) (2,194) Equity in earnings of subsidiaries... (2,200) (3,100) (2,600) Other, net........................... (4,349) (5,940) (4,181) Total.............................. $ 52,603 $ 44,496 $ 34,132
Federal income tax returns through 1993 have been examined and substantially settled through 1991.
The Potomac Edison Company
At December 31, the deferred tax assets and liabilities consisted of the following:
(Thousands of Dollars) 1998 1997
Deferred tax assets: Contributions in aid of construction............ $ 13,845 $ 13,841 Tax interest capitalized........................ 12,096 12,234 Unamortized investment tax credit............... 11,442 12,518 Postretirement benefits other than pensions..... 5,770 3,998 Unbilled revenue................................ 3,492 3,492 Internal restructuring.......................... 2,344 1,239 Advances for construction....................... 914 1,194 Other........................................... 3,685 3,436 53,588 51,952 Deferred tax liabilities: Book vs. tax plant basis differences, net....... 218,434 211,837 Other........................................... 16,814 17,600 235,248 229,437 Total net deferred tax liabilities................ 181,660 177,485 Portion above included in current (liabilities) assets.......................................... (11,311) 1,044 Total long-term net deferred tax liabilities.. $170,349 $178,529
NOTE E: ALLEGHENY GENERATING COMPANY
The Company owns 28% of the common stock of Allegheny Generating Company (AGC), and affiliates of the Company own the remainder. AGC is reported by the Company in its financial statements using the equity method of accounting. 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). 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.
The Potomac Edison Company
Following is a summary of financial information for AGC:
December 31 (Thousands of Dollars) 1998 1997
Balance sheet information: Property, plant, and equipment............... $618,608 $635,485 Current assets............................... 5,857 11,876 Deferred charges............................. 14,993 16,559 Total assets............................... $639,458 $663,920
Total capitalization......................... $314,105 $348,258 Current liabilities.......................... 75,849 70,540 Deferred credits............................. 249,504 245,122 Total capitalization and liabilities....... $639,458 $663,920
Year Ended December 31 (Thousands of Dollars) 1998 1997 1996
Income statement information: Electric operating revenues......... $73,816 $76,458 $83,402 Operation and maintenance expense... 4,592 4,877 5,165 Depreciation........................ 16,949 17,000 17,160 Taxes other than income taxes....... 4,662 4,835 4,801 Federal income taxes................ 10,959 11,213 13,297 Interest charges.................... 13,987 15,391 16,193 Other income, net................... (86) (9,126) (3) Net income........................ $22,753 $32,268 $26,789
The Company's share of the equity in earnings was $6.4 million, $9.0 million, and $7.5 million for 1998, 1997, and 1996, respectively, and is included in other income, net, on the Company's Statement of Income. Dividends received from AGC in 1998 approximated $16 million which reflects an effort to reduce AGC equity to about 45% of total capitalization and short-term debt.
At December 31, 1998 the Company had an outstanding short-term loan to AGC of $66.8 million at 4.80% through the Allegheny Energy money pool.
NOTE F: POSTRETIREMENT BENEFITS
As described in Note A, the Company and its affiliates participate in a pension plan and medical and life insurance plans for eligible employees and dependents. The Company is responsible for its proportional share of the costs (credits) and the assets or liabilities of the plans. As described in Note C, in 1997 the Company transferred virtually all of its employees to APSC. The Company's share of the costs (credits) of these plans, a portion of which (about 25% to 35%) was charged to plant construction, is as follows:
(Thousands of Dollars) 1998 1997 1996 Pension................................ $ (323) $(1,745) $ (201) Medical and life insurance............. $4,893 $ 4,007 $5,831
The Potomac Edison Company
NOTE G: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS No. 71. 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:
(Thousands of Dollars) 1998 1997
Long-Term Assets (Liabilities), Net: Income taxes, net............................. $45,847 $52,231 Demand-side management........................ 8,157 14,204 Postretirement benefits....................... 1,292 1,292 Deferred power costs (reported in other deferred credits)........................... (2,455) (2,949) Other, net.................................... 263 500 Subtotal.................................... 53,104 65,278 Current Assets (Liabilities), Net: Deferred power costs (reported in other current assets)....................... 333 2,682 Net Regulatory Assets..................... $53,437 $67,960
Deregulation/competition proceedings in Maryland, Virginia, and West Virginia may in the future result in less than full recovery of costs incurred to serve customers. Such deregulation and transition to a competitive environment could adversely affect the Company's results of operations, cash flows, and capitalization. Such charges, if any, are not estimable at this time.
NOTE H: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:
1998 1997 Carrying Fair Carrying Fair (Thousands of Dollars) Amount Value Amount Value
Liabilities: Long-term debt and QUIDS................ $585,357 $607,726 $636,157 $672,198
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.
The Potomac Edison Company
NOTE I: 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.
Long-Term Debt and QUIDS Maturities for long-term debt in thousands of dollars for the next five years are: 1999, none; 2000, $75,000; 2001, none; 2002, $3,200; and 2003, none. 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 $130 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 Allegheny Energy 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 1998 and 1997 consisted of:
(Thousands of Dollars) 1998 1997
Average amount outstanding and interest rate during the year: Commercial Paper..................... _ $137-5.63% Notes Payable to Banks............... _ $189-5.37%
NOTE K: COMMITMENTS AND CONTINGENCIES
Construction Program The Company has entered into commitments for its construction program, for which expenditures are estimated to be $86 million for 1999 and $98 million for 2000. Construction expenditure levels in 2001 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 (CAAA) and the extent to which environmental initiatives currently being considered become mandated. The Company estimates that its banked emission allowances will allow it to comply with Phase II sulfur dioxide (SO2) limits through 2005. Studies to evaluate cost-effective options to comply with Phase II SO2 limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.
Market Risk The Company supplies power in the bulk power market. At December 31, 1998, the marketing books for such operations consisted primarily of fixed-priced,
The Potomac Edison Company
forward-purchase and/or sale contracts which require settlement by physical delivery of electricity.
Allegheny Energy has a Corporate Energy Risk Control Policy adopted by the Board of Directors and monitored by an Exposure Management Committee of senior management. This policy requires continuous monitoring for conformity to policies which limit value at risk and market risk associated with the credit standing of counterparties. Such credit standing must be within the guidelines established by Allegheny Energy's Risk Control Policy. The Company's exposure to volatility in the price of electricity and other energy commodities is maintained within approved policy limits.
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 adversely affect the cost of future operations.
The Environmental Protection Agency (EPA) issued its final regional nitrogen oxides (NOx) State Implementation Plan (SIP) call rule on September 24, 1998. The EPA's SIP call rule found that 22 eastern states (including Maryland, Pennsylvania, and West Virginia) and the District of Columbia are all contributing significantly to ozone nonattainment in downwind states. The final rule declares that this downwind nonattainment will be eliminated (or sufficiently mitigated) if the upwind states reduce their NOx emissions by an amount that is precisely set by the EPA on a state-by-state basis. The final SIP call rule requires that all state-adopted NOx reduction measures must be incorporated into SIPs by September 24, 1999, and must be implemented by May 1, 2003. The Company's compliance with these requirements would require the installation of post-combustion control technologies on most, if not all, of its power stations at a cost of approximately $103 million. The Company continues to work with other coal-burning utilities and other affected constituencies in coal-producing states to challenge this EPA action.
The Company previously reported that the EPA had identified it and its regulated affiliates as potentially responsible parties, along with approximately 175 others, 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 and its regulated affiliates have also been named as defendants 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.
West Penn Power Company and Subsidiaries
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors and the Shareholder 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 Energy, Inc.) and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
West Penn Power Company and Subsidiaries
CONSOLIDATED STATEMENT OF INCOME
See accompanying notes to consolidated financial statements.
West Penn Power Company and Subsidiaries
CONSOLIDATED STATEMENT OF CASH FLOWS
See accompanying notes to consolidated financial statements.
West Penn Power Company and Subsidiaries
CONSOLIDATED BALANCE SHEET (Thousands of Dollars) DECEMBER 31 1998 1997 ASSETS Property, Plant, and Equipment: At original cost, including $75,725 and $117,588 under construction............................ $3,365,784 $3,293,039 Accumulated depreciation................ (1,362,413) (1,254,900)
2,003,371 2,038,139 Investments and Other Assets: Allegheny Generating Company--common stock at equity ..................... 74,374 89,783 Other.................................. 646 721
75,020 90,504 Current Assets: Cash and temporary cash investments.... 4,523 4,056 Accounts receivable: Electric service, net of $13,211 and $13,326 uncollectible allowance.......................... 119,175 128,348 Affiliated and other, net............ 24,832 21,525 Materials and supplies--at average cost: Operating and construction........... 43,167 34,212 Fuel................................. 24,363 29,467 Deferred income taxes.................. 11,959 Prepaid taxes.......................... 14,534 11,738 Regulatory assets...................... 17,372 Other.................................. 2,261 2,252
250,227 243,557 Deferred Charges: Regulatory assets...................... 475,776 333,235 Unamortized loss on reacquired debt.... 4,065 9,725 Other.................................. 34,610 31,999
514,451 374,959 Total.................................... $2,843,069 $2,747,159
CAPITALIZATION AND LIABILITIES Capitalization: Common stock, other paid-in capital, and retained earnings................ $ 732,161 $ 997,027 Preferred stock........................ 79,708 79,708 Long-term debt and QUIDS............... 837,725 802,319
1,649,594 1,879,054 Current Liabilities: Short-term debt........................ 55,766 52,046 Notes payable to affiliate............. 9,300 Long-term debt due within one year..... 103,500 Accounts payable....................... 77,815 73,584 Accounts payable to affiliates......... 33,859 16,137 Taxes accrued: Federal and state income............. 1,002 1,605 Other................................ 16,711 22,728 Interest accrued....................... 15,681 15,817 Refunds payable........................ 28,151 Adverse power purchase commitments..... 47,173 Other.................................. 15,393 28,457
300,851 313,874 Deferred Credits and Other Liabilities: Unamortized investment credit.......... 42,630 45,206 Deferred income taxes.................. 260,477 450,390 Regulatory liabilities................. 28,325 34,326 Adverse power purchase commitments..... 538,745 Other.................................. 22,447 24,309
892,624 554,231 Commitments and Contingencies (Note N) Total.................................... $2,843,069 $2,747,159
See accompanying notes to consolidated financial statements.
West Penn Power Company and Subsidiaries
CONSOLIDATED STATEMENT OF CAPITALIZATION
See accompanying notes to consolidated financial statements.
West Penn Power Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (These notes are an integral part of the consolidated financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
West Penn Power Company (the Company) is a wholly owned subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a part of the Allegheny Energy integrated electric utility system (the System). The Company and its utility affiliates, Monongahela Power Company and The Potomac Edison Company, do business as Allegheny Power.
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) 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 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 Prior to May 1, 1997, the costs of fuel, purchased power, and certain other costs, and revenues from sales to other companies and power marketers, including transmission services, were deferred until they were either recovered from or credited to customers under fuel and energy cost-recovery procedures. The Company discontinued this practice effective May 1, 1997.
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. Costs include direct labor and material; allowance for funds used during construction (AFUDC) on regulated utility property for which construction work in progress is not included in rate base; capitalized interest on generation projects; and indirect costs such as administration, maintenance, and depreciation of transportation and construction equipment, postretirement benefits, taxes, and other benefits related to employees engaged in construction.
The cost of depreciable property units retired, plus removal costs less salvage, are charged to accumulated depreciation.
West Penn Power Company and Subsidiaries
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 1998, 1997, and 1996 were 7.17%, 8.30%, and 7.83%, respectively. AFUDC is not included in the cost of construction when the cost of financing the construction is being recovered through rates.
As discussed in Note B, as a result of a Pennsylvania Order, the Company has discontinued the application of the Financial Accounting Standards Board's (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," for electric generation operations and has adopted SFAS No. 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71." Starting in July 1998, the Company stopped accruing AFUDC for generation construction projects and adopted SFAS No. 34, "Capitalizing Interest Costs," to capitalize interest during the period of construction of generation construction projects. Capitalized interest, recognized as a cost of property, plant, and equipment with offsetting credits to interest charges, is reported in the consolidated statement of income as allowance for borrowed funds used during construction. Since adoption in July 1998, rates used for capitalizing interest on generation construction projects averaged 7.45%.
Depreciation and Maintenance Provisions for depreciation are determined generally on a straight-line method based on estimated service lives of depreciable properties and amounted to approximately 3.6%, 3.7%, and 4.0%, of average depreciable property in 1998, 1997, and 1996, 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 Assets and Liabilities In accordance with SFAS No. 71, the Company's consolidated financial statements include certain assets and liabilities based on 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.
West Penn Power Company and Subsidiaries
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 using 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 of Allegheny Energy, Inc. 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 and its affiliates also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up 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.
Capitalized Software Costs The Company capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over a five-year period beginning upon a project's completion.
Comprehensive Income SFAS No. 130, "Reporting Comprehensive Income," effective for 1998, established standards for reporting comprehensive income and its components (revenues, expenses, gains, and losses) in financial statements. The Company does not have any elements of other comprehensive income to report in accordance with SFAS No. 130.
Business Segments SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," established standards for reporting information about operating segments in financial statements. The Company's principal business segment is utility operations which includes the generation, purchase, transmission, distribution, and sale of electricity.
West Penn Power Company and Subsidiaries
NOTE B: INDUSTRY RESTRUCTURING
In December 1996, Pennsylvania enacted the Electricity Generation Customer Choice and Competition Act (Customer Choice Act) to restructure the electric industry in Pennsylvania to create retail access to a competitive electric energy supply market. On August 1, 1997, the Company filed with the Pennsylvania Public Utility Commission (Pennsylvania PUC) a comprehensive restructuring plan to implement full customer choice of electricity suppliers as required by the Customer Choice Act. The filing included a plan for recovery of transition costs (sometimes referred to as stranded costs) through a Competitive Transition Charge (CTC).
Transition costs are costs incurred under a regulated environment, which may not be recoverable in a competitive market. The amount of transition costs has been a key issue in the restructuring proceedings. Since the installed costs of utility facilities are known, the key variable in transition cost determinations in Pennsylvania was the projection of market prices of electricity in future periods. The Company's restructuring plan filing included its determination of its transition costs based on its projection of future market prices. The Company's recoverable transition costs were limited to $1.2 billion by rate caps mandated by the Customer Choice Act.
On May 29, 1998, the Pennsylvania PUC issued an Order authorizing the Company recovery of approximately $595 million (or $525 million in the event of the merger) in transition costs, with a return, based on alternative projections of future market prices. On June 26, 1998, the Pennsylvania PUC denied, except for minor corrections, a request by the Company for reconsideration of the May 29 Order. On that same day, the Company filed a formal appeal in state court and an action in federal court challenging the Pennsylvania PUC's restructuring Order.
As a result of this May 29, 1998 Order, the Company determined that it was required to discontinue the application of SFAS No. 71 for electric generation operations and adopt SFAS No. 101. In doing so, the Company also determined that, under the provisions of SFAS No. 101, an extraordinary charge of $450.6 million ($265.4 million after taxes) was required to reflect adverse power purchase commitments and deferred costs that are not recoverable from customers under the Pennsylvania PUC's Order.
While pursuing its litigation, the Company participated in settlement discussions with interested parties regarding issues related to the restructuring Order. A negotiated settlement was achieved, and, on November 19, 1998, the Pennsylvania PUC granted final approval to the Company's restructuring settlement agreement. The settlement agreement includes the following provisions:
Agreement by the parties to withdraw all litigation related to the Pennsylvania deregulation proceedings.
Establishment of an average shopping credit of 3.16 cents per kilowatt-hour in 1999 for Company customers who shop for the generation portion of electricity services.
Two-thirds of the Company's customers have the option of selecting a generation supplier on January 2, 1999, with all customers able to shop on January 2, 2000.
West Penn Power Company and Subsidiaries
Requires a rate refund from 1998 revenues (about $25 million) via a 2.5% rate decrease throughout 1999, accomplished by an equal percentage decrease for each rate class.
Provides that customers will have the option of buying electricity from the Company at capped generation rates through 2008, and that transmission and distribution rates are capped through 2005, except that the capped rates are subject to certain increases as provided for in the Public Utility Code.
Prohibits complaints challenging the Company's regulated transmission and distribution rates through 2005.
Provides about $15 million of Company funding for the development and use of renewable energy and clean energy technologies, energy conservation, energy efficiency, etc.
Permits recovery of $670 million in transition costs plus return over 10 years beginning in January 1999 for the Company. In the event that the merger of Allegheny Energy, Inc. and DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., is consummated, the transition costs will be adjusted to $630 million plus return to provide a sharing of merger synergy savings with customers.
Allows for income recognition of transition cost recovery in the earlier years of the transition period to reflect the Pennsylvania PUC's projections that electricity market prices are lower in the earlier years.
Grants the Company's application to issue bonds to securitize up to $670 million (or $630 million in the event of the merger) in transition costs and to provide 75% of the associated savings to customers with 25% to shareholders.
Authorizes the transfer of the Company's generating assets to a nonutility affiliate at book value. Subject to certain time- limited exceptions, the nonutility business can compete in the unregulated energy market.
If the Company is forced to divest some generating assets or chooses to divest all of its generation before 2002, the CTC will be adjusted, either up or down, based on the results of such divestiture.
As a result of the November 19, 1998, settlement agreement, the extraordinary charge was increased by $16.3 million ($10.0 million after taxes) to $466.9 million ($275.4 million after taxes), and additional charges of $40.3 million ($23.7 million after taxes) related to the Company's revenue refund and energy program payments were also recorded. See Note C for additional details. Pursuant to Pennsylvania PUC orders, starting in 1999, the Company is unbundling its rates to reflect separate prices for the supply charge, the CTC, and transmission and distribution charges. While supply will be open to competition, the Company will continue to provide regulated transmission and distribution services to customers in its service area at Pennsylvania PUC- and FERC-regulated rates and will be the electricity provider of last resort for those customers who decide not to choose another electricity supplier.
West Penn Power Company and Subsidiaries
As stated above, the Company made its filing concerning its transition cost requirements based on its early 1997 projection of market prices. The Pennsylvania PUC issued its May 29, 1998 Order to the Company, as well as its 1998 orders to all other Pennsylvania electric utilities, based on alternative projections. Current prices, which the Company believes are being influenced, among other things, by price volatility in the summer of 1998, are equal to and in some cases higher than the projections adopted by the Pennsylvania PUC in its deregulation orders issued to the Company and other utilities in the state. If the Pennsylvania PUC's projections are correct, the Company believes that the transition costs provided will be sufficient to permit it to recover its embedded costs, with a return, during the transition from regulation to deregulation of electricity generation.
The settlement authorizes the Company to create a CTC regulatory asset for specified CTC revenues in 1999 through 2002 to be amortized in 2005 through 2008. The regulatory asset booking of CTC revenue acts to accelerate recognition of transition cost recovery. In addition, the settlement agreement specifies how CTC revenues will be allocated between return on and recovery of transition costs. Amortization of regulatory assets in 1999 through 2008 under the Pennsylvania PUC-approved settlement agreement results in smaller amortization expense in the early years of the transition period which favorably affects earnings in those years.
Also pursuant to the Customer Choice Act, all electric utilities in Pennsylvania were required to establish and administer retail access pilot programs under which customers representing 5% of the load of each rate class would choose an electricity supplier other than their own local franchise utility. The pilot programs began on November 1, 1997, and continued through December 31, 1998. As ordered by the Pennsylvania PUC, pilot participants received an energy credit to their bills from their local utility and paid an alternate supplier for energy. To assure participation in the pilot program, the credit established by the Pennsylvania PUC was artificially high (greater than the Company's generation costs), with the result that the Company suffered a loss of $6.5 million. The Company attempted to mitigate the loss by competing for sales to pilot participants of other utilities as an alternate supplier. The Pennsylvania PUC approved the Company's pilot compliance filing and thus has indicated its intent to treat the revenue losses as a regulatory asset subject to review and potential rate recovery. Because sales prices were low and margins were commensurately thin, the Company was unable to completely offset its pilot losses with new revenues. Accordingly, the Company deferred the net revenue losses as a regulatory asset.
NOTE C: ACCOUNTING FOR THE EFFECTS OF PRICE DEREGULATION
In 1997, the FASB, through its Emerging Issues Task Force (EITF), issued EITF No. 97-4, "Deregulation of the Pricing of Electricity - - Issues Related to the Application of FASB Statement Numbers 71 and 101." In EITF 97-4, the EITF agreed that when a rate order that contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated is issued, the entity should cease to apply SFAS No. 71 to that separable portion of its business. The Company believes that the Pennsylvania PUC Order dated May 29, 1998, as described in Note B, provides sufficient details regarding the deregulation of the Company's electric generation operations to require discontinuation of the application of SFAS No. 71 for its electric generation
West Penn Power Company and Subsidiaries
operations. Effective June 30, 1998, the Company adopted the provisions of SFAS No. 101 for its electric generation operations. The Company determined that under the provisions of SFAS No. 101, an extraordinary charge of $466.9 million ($275.4 million after taxes) was required to reflect a write-off of certain disallowances in the Pennsylvania PUC's May 29, 1998 Order, as revised by the Pennsylvania PUC-approved November 19, 1998 settlement agreement. The write-off reflects adverse power purchase commitments and deferred costs that are not recoverable from customers under the Pennsylvania PUC's Order and settlement agreement as follows:
(Millions of Dollars) Gross Net-of-Tax
AES Beaver Valley nonutility generation contract..... $197.5 $116.5 AGC pumped storage capacity contract................. 165.6 97.7 Other................................................ 103.8 61.2 Total extraordinary charge......................... $466.9 $275.4
In 1985, the Company entered into a contract with Applied Energy Services (AES) Corporation for the purchase of energy from AES's Beaver Valley generating plant in Pennsylvania pursuant to the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Company owns 45% of AGC, which owns an undivided 40% interest in the 2,100-MW pumped-storage hydroelectric station in Bath County, Va. The Company buys AGC's capacity in the station priced under a cost of service formula wholesale rate schedule approved by the FERC.
Under both of these contracts, the Company has purchase commitments at costs in excess of the market value of energy from the plants. Because of utility restructuring under the Customer Choice Act, these commitments have been determined to be adverse purchase commitments requiring accrual as loss contingencies pursuant to SFAS No. 5, "Accounting for Contingencies." The extraordinary charge before taxes for these contracts is the net result of such excess cost accruals (recorded as adverse power purchase commitments) less estimated revenue recoveries authorized in the Pennsylvania PUC Order (recorded as regulatory assets) as follows:
AES AGC (Millions of Dollars) Beaver Valley Pumped Storage
Projected costs in excess of market value of energy............................. $351.5 $234.5 Estimated recovery via a CTC (regulatory asset)...................................... 154.0 68.9 Net unrecoverable extraordinary charge.... $197.5 $165.6
Various assumptions and estimates were made in determining the extraordinary charge to income discussed above. The most significant relate to future electricity prices. To the extent that future electricity prices differ from the Company's estimates, adjustments to the reserve for adverse power purchase commitments may be required.
West Penn Power Company and Subsidiaries
The other $103.8 million of extraordinary charges represents $55.0 million of deferred unrecovered expenditures for previous PURPA buyouts, $13.5 million for an abandoned generating plant, and $35.3 million of other generation-related regulatory assets, primarily related to SFAS No. 109, "Accounting for Income Taxes."
The consolidated balance sheet includes the amounts listed below for generation assets not subject to SFAS No. 71: December December (Thousands of Dollars) 1998 1997
Property, plant, and equipment at original cost.... $1,969,636 $1,951,066 Amounts under construction included above.......... 39,227 51,715 Accumulated depreciation........................... (870,777) (793,166)
In addition to the extraordinary charge and as a result of the settlement agreement, a fourth quarter charge to earnings of $40.3 million ($23.7 million after taxes) resulted from the required refund throughout 1999 from 1998 revenues of about $25 million and a $15 million provision for energy programs.
NOTE D: PROPOSED MERGER
On April 7, 1997, the Company's parent, Allegheny Power System, Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., announced that they had agreed to merge in a tax-free, stock-for- stock transaction.
At separate meetings held on August 7, 1997, the shareholders of Allegheny Energy and DQE approved the merger. Allegheny Energy and DQE made all necessary regulatory filings. Since then, Allegheny Energy and DQE received approval of the merger from the Nuclear Regulatory Commission, the Pennsylvania PUC, and the FERC. The Pennsylvania PUC and the FERC approvals were subject to conditions acceptable to Allegheny Energy. In addition, while not required, the Maryland Public Service Commission and the Public Utilities Commission of Ohio have indicated their approval.
On October 5, 1998, DQE notified Allegheny Energy that it had unilaterally decided to terminate the merger. Allegheny Energy believes DQE's action was without basis and was a breach of the merger agreement. In response, Allegheny Energy filed with the United States District Court for the Western District of Pennsylvania on October 5, 1998, a lawsuit for specific performance of the merger agreement or, alternatively, damages. Allegheny Energy also filed motions for preliminary injunctive relief against DQE.
On October 28, 1998, the District Court denied Allegheny Energy's motions for preliminary injunctive relief. The District Court did not rule on the merits of the lawsuit for specific performance or damages. On October 30, 1998, Allegheny Energy appealed the District Court's Order to the United States Court of Appeals for the Third Circuit. Allegheny Energy cannot predict the outcome of this litigation.
All of the Company's incremental costs of the merger process ($7.9 million through December 31, 1998) are being deferred. The accumulated merger costs will be written off by the Company when the merger occurs or by the Company if it is determined that the merger will not occur.
West Penn Power Company and Subsidiaries
NOTE E: INTERNAL RESTRUCTURING CHARGES AND ASSET WRITE-OFF
In 1996, the System, including the Company, completed its internal restructuring activities initiated in 1994, simplifying the management structure and streamlining operations. During 1996, restructuring activities included consolidating operating divisions, customer services, and other functions.
In 1996, the Company recorded restructuring charges of $42.6 million ($25.1 million after tax) in operating expenses, including its share of all restructuring charges associated with the reorganization. These charges reflected liabilities and payments for severance, employee termination costs, and other restructuring costs. The current portion of the restructuring liability, reflected in other current liabilities, excluding benefit plans curtailment adjustments to postretirement liabilities (which are primarily recorded in other deferred credits), consists of:
(Thousands of Dollars) 1998 1997
Internal restructuring liability: Balance at beginning of period................. $ 4,082 $ 27,134 Less payments and accrual reversals............ (4,082) (23,052) Balance at end of period......................... $ - $ 4,082
In 1996, the Company wrote off $10.8 million ($6.3 million after tax) of previously accumulated costs related to a proposed transmission line. In the industry's more competitive environment, it was no longer reasonable to assume future recovery of these costs in rates.
As part of the reorganization, the Company and its utility affiliates in 1996 expanded the intercompany use of each other's employees to optimize the use of their skills. In 1997 virtually all the employees in the System, including all of the Company's employees, were transferred to Allegheny Power Service Corporation (APSC) to facilitate the intercompany use of personnel. APSC was formed in 1963 pursuant to the Public Utility Holding Company Act of 1935 to perform certain functions common to all companies in the System. APSC bills each company at its cost (without profit) based on the work performed and services provided to each company.
West Penn Power Company and Subsidiaries
NOTE F: INCOME TAXES
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Income taxes--current: Federal.............................. $ 47,605 $29,426 $32,778 State................................ 18,415 12,357 12,975 Total.............................. 66,020 41,783 45,753 Income taxes--deferred, net of amortization......................... 1,069 33,961 4,602 Income taxes--deferred, extraordinary charge............................... (191,480) Amortization of deferred investment credit............................... (2,580) (2,580) (2,580) Total income taxes................. (126,971) 73,164 47,775 Income taxes--credited (charged) to other income and deductions....... 17 115 (320) Income taxes--credited to extraordinary charge................. 191,480 Income taxes--charged to operating income............................... $ 64,526 $73,279 $47,455
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:
(Thousands of Dollars) 1998 1997 1996
Income before income taxes and extraordinary charge............. $177,146 $207,944 $135,900 Amount so produced..................... $ 62,001 $ 72,780 $ 47,565 Increased (decreased) for: Tax deductions for which deferred tax was not provided: Lower tax depreciation........... 1,500 5,700 3,300 Plant removal costs.............. 1,000 1,400 2,100 State income tax, net of federal income tax benefit................. 10,000 4,900 8,900 Amortization of deferred investment credit.................. (2,580) (2,580) (2,580) Equity in earnings of subsidiaries... (3,900) (6,300) (4,600) Other, net........................... (3,495) (2,621) (7,230) Total.............................. $ 64,526 $ 73,279 $ 47,455
West Penn Power Company and Subsidiaries
The provision for income taxes for the extraordinary charge is different from the amount produced by applying the federal income statutory tax rate of 35% to the gross amount, as set forth below:
(Thousands of Dollars) 1998
Extraordinary charge before income taxes............... $466,905 Amount so produced..................................... $163,417 Increased for state income tax, net of federal income tax benefit................................... 28,063 Total.............................................. $191,480
Federal income tax returns through 1993 have been examined and substantially settled through 1991.
At December 31, the deferred tax assets and liabilities consisted of the following:
(Thousands of Dollars) 1998 1997
Deferred tax assets: CTC recovery.................................... $154,530 Unamortized investment tax credit............... 29,674 $ 31,570 Tax interest capitalized........................ 19,010 19,220 Postretirement benefits other than pensions..... 15,610 12,857 Revenue refund.................................. 10,301 Unbilled revenue................................ 9,068 9,226 Contributions in aid of construction............ 6,988 6,520 Internal restructuring.......................... 2,954 2,709 Other........................................... 24,724 25,777 272,859 107,879 Deferred tax liabilities: Book vs. tax plant basis differences, net....... 503,605 493,361 Other........................................... 33,214 52,949 536,819 546,310 Total net deferred tax liabilities................ 263,960 438,431 Portion above included in current (liabilities) assets.......................................... (3,483) 11,959 Total long-term net deferred tax liabilities.. $260,477 $450,390
NOTE G: 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, 1998, 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.
West Penn Power Company and Subsidiaries
NOTE H: 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 is reported by the Company in its financial statements using the equity method of accouting. 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). 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.
Following is a summary of financial information for AGC:
December 31 (Thousands of Dollars) 1998 1997
Balance sheet information: Property, plant, and equipment................. $618,608 $635,485 Current assets................................. 5,857 11,876 Deferred charges............................... 14,993 16,559 Total assets................................. $639,458 $663,920
Total capitalization........................... $314,105 $348,258 Current liabilities............................ 75,849 70,540 Deferred credits............................... 249,504 245,122 Total capitalization and liabilities......... $639,458 $663,920
Year Ended December 31 (Thousands of Dollars) 1998 1997 1996
Income statement information: Electric operating revenues.......... $73,816 $76,458 $83,402 Operation and maintenance expense.... 4,592 4,877 5,165 Depreciation......................... 16,949 17,000 17,160 Taxes other than income taxes........ 4,662 4,835 4,801 Federal income taxes................. 10,959 11,213 13,297 Interest charges..................... 13,987 15,391 16,193 Other income, net.................... (86) (9,126) (3) Net income......................... $22,753 $32,268 $26,789
The Company's share of the equity in earnings was $10.2 million, $14.5 million, and $12.1 million for 1998, 1997, and 1996, respectively, and is included in other income, net, on the Company's Consolidated Statement of Income. Dividends received from AGC in 1998 approximated $25 million which reflects an effort to reduce AGC equity to about 45% of total capitalization and short-term debt.
West Penn Power Company and Subsidiaries
NOTE I: POSTRETIREMENT BENEFITS
As described in Note A, the Company and its affiliates participate in a pension plan and medical and life insurance plans for eligible employees and dependents. The Company is responsible for its proportional share of the costs (credits) and the assets or liabilities of the plans. As described in Note E, in 1997 the Company transferred all of its employees to APSC. The Company's share of the costs (credits) of these plans, a portion of which (about 25% to 35%) was charged to plant construction, is as follows:
(Thousands of Dollars) 1998 1997 1996
Pension................................ $ 919 $(3,037) $ 564 Medical and life insurance............. $6,708 $ 4,551 $9,039
NOTE J: REGULATORY ASSETS AND LIABILITIES
The Company's operations, other than electric generation, are subject to the provisions of SFAS No. 71. As discussed in Note B, as a result of a Pennsylvania Order, the Company has discontinued the application of SFAS No. 71 and has adopted SFAS No. 101 for electric generation operations. 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:
(Thousands of Dollars) 1998 1997
Long-Term Assets (Liabilities), Net: Income taxes, net............................ $146,952 $247,574 CTC recovery................................. 292,718 PURPA project buyout......................... 48,000 Pennsylvania pilot deferred revenue.......... 6,727 84 Deferred power costs, (reported in other deferred charges).......................... 7,000 Storm damage................................. 1,054 1,326 Postretirement benefits...................... 823 Other, net................................... 1,102 Subtotal................................... 447,451 305,909 Current Asset: CTC recovery................................. 17,372 Net Regulatory Assets...................... $464,823 $305,909
West Penn Power Company and Subsidiaries
NOTE K: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:
1998 1997 Carrying Fair Carrying Fair (Thousands of Dollars) Amount Value Amount Value
Assets: Temporary cash investments......... $ 882 $ 882 $ 573 $ 573 Liabilities: Short-term debt....... 65,066 65,066 52,046 52,046 Long-term debt and QUIDS........... 845,535 902,037 913,985 953,700
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 L: 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 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 in thousands of dollars for the next five years are: 1999-2001, none; 2002, $33,550; and 2003, $141,500. 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 M: 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 $182 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 Allegheny Energy internal money pool accommodates intercompany short-term borrowing needs, to the extent that certain of the regulated companies have funds available.
West Penn Power Company and Subsidiaries
Short-term debt outstanding for 1998 and 1997 consisted of:
(Thousands of Dollars) 1998 1997
Balance and interest rate at end of year: Commercial Paper.................. $55,766-5.45% $12,046-6.50% Notes Payable to Banks............ 40,000-6.75% Money Pool........................ 9,300-4.80% Average amount outstanding and interest rate during the year: Commercial Paper.................. $32,824-5.60% $ 3,376-5.73% Notes Payable to Banks............ 16,885-5.60% 5,526-5.67% Money Pool........................ 10,942-5.38% 17,628-5.48%
NOTE N: COMMITMENTS AND CONTINGENCIES
Construction Program The Company has entered into commitments for its construction program, for which expenditures are estimated to be $119 million for 1999 and $106 million for 2000. Construction expenditure levels in 2001 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. The Company estimates that its banked emission allowances will allow it to comply with Phase II sulfur dioxide (SO2) limits through 2005. Studies to evaluate cost-effective options to comply with Phase II SO2 limits beyond 2005, including those available in connection with the emission allowance trading market, are continuing.
Market Risk The Company supplies power in the bulk power market. At December 31, 1998, the marketing books for such operations consisted primarily of fixed-priced, forward-purchase and/or sale contracts which require settlement by physical delivery of electricity.
Allegheny Energy has a Corporate Energy Risk Control Policy adopted by the Board of Directors and monitored by an Exposure Management Committee of senior management. This policy requires continuous monitoring for conformity to policies which limit value at risk and market risk associated with the credit standing of counterparties. Such credit standing must be within the guidelines established by Allegheny Energy's Risk Control Policy. The Company's exposure to volatility in the price of electricity and other energy commodities is maintained within approved policy limits, but has increased as a result of Pennsylvania restructuring, which created retail access to a deregulated electric supply market.
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 adversely affect the cost of future operations.
West Penn Power Company and Subsidiaries
The Environmental Protection Agency (EPA) issued its final regional nitrogen oxides (NOx) State Implementation Plan (SIP) call rule on September 24, 1998. The EPA's SIP call rule found that 22 eastern states (including Maryland, Pennsylvania, and West Virginia) and the District of Columbia are all contributing significantly to ozone nonattainment in downwind states. The final rule declares that this downwind nonattainment will be eliminated (or sufficiently mitigated) if the upwind states reduce their NOx emissions by an amount that is precisely set by the EPA on a state-by-state basis. The final SIP call rule requires that all state-adopted NOx reduction measures must be incorporated into SIPs by September 24, 1999, and must be implemented by May 1, 2003. The Company's compliance with these requirements would require the installation of post-combustion control technologies on most, if not all, of its power stations at a cost of approximately $147 million. The Company continues to work with other coal-burning utilities and other affected constituencies in coal-producing states to challenge this EPA action.
The Company previously reported that the EPA had identified it and its regulated affiliates as potentially responsible parties, along with approximately 175 others, 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 and its regulated affiliates have also been named as defendants 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.
Allegheny Generating Company
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors and the Shareholders 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 (a subsidiary of Allegheny Energy, Inc.) at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
Allegheny Generating Company
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31 (Thousands of Dollars) 1998 1997 1996
Electric Operating Revenues.......................................$73,816 $76,458 $83,402
Operating Expenses: Operation and maintenance expense............ 4,592 4,877 5,165 Depreciation................................. 16,949 17,000 17,160 Taxes other than income taxes................ 4,662 4,835 4,801 Federal income taxes......................... 10,959 11,213 13,297 Total Operating Expenses................... 37,162 37,925 40,423 Operating Income........................... 36,654 38,533 42,979
Other Income, net............................... 86 9,126 3 Income Before Interest Charges................36,740 47,659 42,982
Interest Charges: Interest on long-term debt....................10,848 14,431 15,235 Other interest................................ 3,139 960 958 Total Interest Charges......................13,987 15,391 16,193
Net Income.....................................$22,753 $32,268 $26,789
STATEMENT OF RETAINED EARNINGS
Balance at January 1...........................$ 0 $ 0 $ 4,153 Add: Net income................................... 22,753 32,268 26,789
22,753 32,268 30,942 Deduct: Dividends on common stock.................... 22,753* 32,268* 30,942*
Balance at December 31.........................$ 0 $ 0 $ 0
*Excludes cash dividends paid from other paid-in capital.
See accompanying notes to financial statements.
Allegheny Generating Company
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31 (Thousands of Dollars) 1998 1997 1996
Cash Flows from Operations: Net income...............................$22,753 $32,268 $26,789 Depreciation............................. 16,949 17,000 17,160 Tax-related contract settlement.......... 8,835 Deferred investment credit and income taxes, net............................. 5,305 6,329 10,898 Changes in certain current assets and liabilities: Accounts receivable.................... 6 1,331 3,937 Materials and supplies................. (261) 260 (43) Accounts payable....................... (340) 5,913 206 Other, net............................... 578 28 (3,739)
44,990 71,964 55,208
Cash Flows from Investing: Construction expenditures................ (69) (444) (178)
Cash Flows from Financing: Retirement of long-term debt.............(60,000) (30,592) (16,943) Notes payable to parents................. 66,750 Cash dividends on common stock...........(57,000) (35,700) (37,987)
(50,250) (66,292) (54,930)
Net Change in Cash and Temporary Cash Investments......................... (5,329) 5,228 100 Cash and Temporary Cash Investments at January 1................................ 5,359 131 31 Cash and Temporary Cash Investments at December 31..............................$ 30 $ 5,359 $ 131
Supplemental Cash Flow Information Cash paid during the year for: Interest...............................$14,490 $14,770 $15,703 Income taxes........................... 4,828 10,313 6,256
See accompanying notes to financial statements.
Allegheny Generating Company
BALANCE SHEET
DECEMBER 31 (Thousands of Dollars) 1998 1997
ASSETS
Property, Plant, and Equipment: At original cost, including $595 and $906 under construction...................... $828,806 $828,658 Accumulated depreciation.................. (210,198) (193,173)
618,608 635,485
Current Assets: Cash and temporary cash investments....... 30 5,359 Accounts receivable from Parents.......... 6 Materials and supplies--at average cost... 2,093 1,832 Prepaid taxes............................. 3,569 4,442 Other..................................... 165 237
5,857 11,876
Deferred Charges: Regulatory assets......................... 7,056 7,979 Unamortized loss on reacquired debt....... 7,768 8,393 Other..................................... 169 187
14,993 16,559 Total....................................... $639,458 $663,920
CAPITALIZATION AND LIABILITIES
Capitalization: Common stock - $1.00 par value per share, authorized 5,000 shares, outstanding 1,000 shares. .......................... $ 1 $ 1 Other paid-in capital..................... 165,275 199,522
165,276 199,523 Long-term debt............................ 148,829 148,735
314,105 348,258
Current Liabilities: Notes payable to parents.................. 66,750 Long-term debt due within one year........ 60,000 Accounts payable to affiliates............ 5,795 6,135 Interest accrued.......................... 3,229 4,404 Other..................................... 75 1
75,849 70,540
Deferred Credits: Unamortized investment credit............. 47,020 48,342 Deferred income taxes..................... 177,166 169,325 Regulatory liabilities.................... 25,318 27,455
249,504 245,122
Total....................................... $639,458 $663,920
See accompanying notes to financial statements.
Allegheny Generating Company
NOTES TO FINANCIAL STATEMENTS (These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Allegheny Generating Company (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 Energy, Inc. (Allegheny Energy) and are a part of the Allegheny Energy 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.
Revenues Revenues are determined under a cost-of-service formula rate schedule approved by the FERC. Under this arrangement, the Company recovers in revenues all of its operation and maintenance expense, depreciation, taxes, and a return on its investment. All sales are made to the Company's Parents.
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 1998, 1997, and 1996. The cost of maintenance and of certain replacements of property, plant, and equipment is charged 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 Assets and Liabilities 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 include certain assets and liabilities based on cost-based ratemaking regulation.
Allegheny Generating Company
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 using 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.
Comprehensive Income SFAS No. 130, "Reporting Comprehensive Income," effective for 1998, established standards for reporting comprehensive income and its components (revenues, expenses, gains, and losses) in the financial statements. The Company does not have any elements of other comprehensive income to report in accordance with SFAS No. 130.
Business Segments SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," established standards for reporting information about operating segments in financial statements. The Company operates as a single business segment selling its entire capacity to its Parents priced under a cost-of-service wholesale rate schedule.
NOTE B: PROPOSED MERGER
On April 7, 1997, Allegheny Power System, Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE), parent company of Duquesne Light Company in Pittsburgh, Pa., announced that they had agreed to merge in a tax-free, stock-for-stock transaction.
At separate meetings held on August 7, 1997, the shareholders of Allegheny Energy and DQE approved the merger. Allegheny Energy and DQE made all necessary regulatory filings. Since then, Allegheny Energy and DQE received approval of the merger from the Nuclear Regulatory Commission, the Pennsylvania Public Utility Commission (Pennsylvania PUC), and the FERC. The Pennsylvania PUC and the FERC approvals were subject to conditions acceptable to Allegheny Energy. In addition, while not required, the Maryland Public Service Commission and the Public Utilities Commission of Ohio have indicated their approval.
Allegheny Generating Company
On October 5, 1998, DQE notified Allegheny Energy that it had unilaterally decided to terminate the merger. Allegheny Energy believes DQE's action was without basis and was a breach of the merger agreement. In response, Allegheny Energy filed with the United States District Court for the Western District of Pennsylvania on October 5, 1998, a lawsuit for specific performance of the merger agreement or, alternatively, damages. Allegheny Energy also filed motions for preliminary injunctive relief against DQE.
On October 28, 1998, the District Court denied Allegheny Energy's motions for preliminary injunctive relief. The District Court did not rule on the merits of the lawsuit for specific performance or damages. On October 30, 1998, Allegheny Energy appealed the District Court's Order to the United States Court of Appeals for the Third Circuit. The Company cannot predict the outcome of this litigation.
NOTE C: INCOME TAXES
Details of federal income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Current income taxes payable.......... $ 5,700 $ 9,799 $ 2,401 Deferred income taxes-- accelerated depreciation............ 6,628 7,652 12,220 Amortization of deferred investment credit................... (1,323) (1,323) (1,322) Total income taxes................ 11,005 16,128 13,299 Income taxes--charged to other income.............................. (46) (4,915) (2) Income taxes--charged to operating income.............................. $10,959 $11,213 $13,297
In 1998, the total provision for income taxes ($10,959) was less than the amount produced ($11,799) by applying the federal income tax statutory rate of 35% to financial accounting income before income taxes ($33,712), primarily due to amortization of deferred investment credit ($1,323).
Federal income tax returns through 1993 have been examined and substantially settled through 1991.
At December 31, the deferred tax liabilities, net consisted of the following:
(Thousands of Dollars) 1998 1997
Deferred tax liabilities, net: Unamortized investment tax credit............... $(25,318) $(27,455) Book vs. tax plant basis differences, net....... 202,484 196,780 Total long-term net deferred tax liabilities.. $177,166 $169,325
Allegheny Generating Company
NOTE D: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS No. 71. 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 liabilities, net of regulatory assets, in thousands of dollars of $18,262 in 1998 and $19,476 in 1997 relate to income taxes.
NOTE E: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial instruments at December 31 were as follows:
1998 1997 Carrying Fair Carrying Fair (Thousands of Dollars) Amount Value Amount Value
Liabilities: Short-term debt........ $ 66,750 $ 66,750 Long-term debt: Debentures........... 150,000 155,658 $150,000 $144,410 Medium-term notes.... 60,000 60,000
The carrying amount of short-term debt approximates the fair value because of the short maturity of those instruments. The fair value of debentures and medium-term notes 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 F: CAPITALIZATION
The Company systematically reduces capitalization each year as its asset depreciates, resulting in the payment of dividends in excess of current earnings. The SEC has approved the Company's request to pay common dividends out of capital. Common dividends were paid from retained earnings, reducing the account balance to zero, and from other paid-in capital as follows:
(Thousands of Dollars) 1998 1997 1996
Retained earnings.................. $22,753 $32,268 $30,942 Other paid-in capital.............. 34,247 3,432 7,045 Total............................ $57,000 $35,700 $37,987
Allegheny Generating Company
NOTE G: LONG-TERM DEBT
The Company had long-term debt outstanding as follows:
12-31-98 Interest December 31 (Thousands of Dollars) Rate 1998 1997
Debentures due: September 1, 2003................. 5.625% $ 50,000 $ 50,000 September 1, 2023................. 6.875% 100,000 100,000 Medium-term notes due 1998.......... 60,000 Unamortized debt discount........... (1,171) (1,265) Total........................... 148,829 208,735 Less current maturities............. 60,000 Total........................... $148,829 $148,735
Maturities for long-term debt for the next five years are $50,000 in 2003.
NOTE H: SHORT-TERM DEBT
To provide interim financing and support for outstanding commercial paper, the Allegheny Energy 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 Allegheny Energy internal money pool accommodates intercompany short-term borrowing needs to the Company, to the extent that Allegheny Energy and the Company's Parents have funds available. At December 31, 1998, the Company had borrowings from the Allegheny Energy money pool of $66.8 million which were funded by The Potomac Edison Company. Short-term debt outstanding for 1998 consisted of:
(Thousands of Dollars) 1998
Balance and interest rate at end of year: Money pool.............................. $66,750-4.80% Average amount outstanding and interest rate during the year: Commercial paper.................................. 1,725-5.46% Notes payable to banks............................ 406-5.63% Money pool........................................ 43,415-5.23%
S-1 SCHEDULE II
ALLEGHENY ENERGY, INC. AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts For Years Ended December 31, 1998, 1997, and 1996
(A) Recoveries. (B) Uncollectible accounts charged off.
S-2 SCHEDULE II
MONONGAHELA POWER COMPANY
Valuation and Qualifying Accounts For Years Ended December 31, 1998, 1997, and 1996
(A) Recoveries. (B) Uncollectible accounts charged off.
S-3 SCHEDULE II
POTOMAC EDISON COMPANY
Valuation and Qualifying Accounts For Years Ended December 31, 1998, 1997, and 1996
(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, 1998, 1997, and 1996
(A) Recoveries. (B) Uncollectible accounts charged off.
Supplementary Data Quarterly Financial Data (Unaudited) (Dollar Amounts in Thousands Except for Per Share Data) Electric Operating Operating Net Earnings Revenues Income Income* Per Share* Quarter ended
AE March 1998 $645 472 $124,707 $ 78 237 $ .64 June 1998 627 650 100 065 53 891 .44 September 1998 726 607 128 604 82 736 .68 December 1998 576 707 86 131 48 144 .39
March 1997 614 980 124 094 77 591 .64 June 1997 542 750 95 473 51 683 .42 September 1997 595 125 110 635 74 808 .61 December 1997 616 636 122 035 77 214 .63
Monongahela March 1998 158 272 27 358 19 427 June 1998 153 774 24 087 16 611 September 1998 177 364 31 887 25 244 December 1998 155 712 28 154 21 143
March 1997 162 803 30 480 22 556 June 1997 144 078 23 701 16 174 September 1997 158 240 28 493 23 457 December 1997 163 190 26 701 18 342
Potomac Edison March 1998 191 698 37 622 27 922 June 1998 177 519 30 036 20 504 September 1998 190 533 36 680 27 299 December 1998 177 744 34 458 25 757
March 1997 192 228 37 062 27 723 June 1997 164 867 26 894 18 376 September 1997 175 464 30 388 25 296 December 1997 176 222 34 428 24 360
West Penn March 1998 280 703 52 619 39 001 June 1998 263 023 40 627 26 308 September 1998 288 272 56 248 42 835 December 1998 246 729 17 038 4 476
March 1997 282 530 47 271 36 901 June 1997 252 731 35 661 21 963 September 1997 266 746 43 865 34 333 December 1997 280 155 55 850 41 468
AGC March 1998 18 604 9 450 5 937 June 1998 19 126 9 258 5 961 September 1998 18 303 9 297 5 625 December 1998 17 783 8 649 5 230
March 1997 20 216 10 328 6 368 June 1997 20 408 10 311 6 395 September 1997 19 664 10 230 15 396 December 1997 16 170 7 664 4 109
*For AE and West Penn - 1998 results exclude the effect of extraordinary charges in June 1998 ($265,446, net of taxes, or $2.17 per share) and December 1998 ($9,980, net of taxes, or $.08 per share).
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders of Allegheny Energy, Inc.
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Allegheny Energy, Inc. and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
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 Energy, Inc.) at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
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 Energy, Inc.) at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
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 Energy, Inc. and its subsidiaries) at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
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 (a subsidiary of Allegheny Energy, Inc.) at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania February 4, 1999
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
For AE and its subsidiaries, none.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
AE, 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, 1998, and the business experience during the past five years of the directors of the System companies are set forth below:
Business Experience during Director since date shown of Name the Past Five Years Age AE MP PE WP AGC
Eleanor Baum See below (a) 58 1988 1988 1988 1988 William L. Bennett See below (b) 49 1991 1991 1991 1991 Thomas K. Henderson Company employee (1) 58 1996 Wendell F. Holland See below (c) 46 1994 1994 1994 1994 Kenneth M. Jones Company employee (1) 61 1991 Phillip E. Lint See below (d) 69 1989 1989 1989 1989 Frank A. Metz, Jr. See below (e) 64 1984 1984 1984 1984 Michael P. Morrell Company employee (1) 50 1996 1996 1996 1996 Alan J. Noia Company employee (1) 51 1994 1994 1987 1994 1994 Jay S. Pifer Company employee (1) 61 1995 1995 1992 Steven H. Rice See below (f) 55 1986 1986 1986 1986 Gunnar E. Sarsten See below (g) 61 1992 1992 1992 1992 Peter J. Skrgic Company employee (1) 57 1990 1990 1990 1989
(1) See Executive Officers of the Registrants in Part I of this report for further details.
(a) Eleanor Baum. Dean of The Albert Nerken School of Engineering of The Cooper Union for the Advancement of Science and Art. Director of Avnet, Inc. and United States Trust Company, Chair of the Engineering Workforce Commission, a fellow of the Institute of Electrical and Electronic Engineers, Chairman of Board of Governors, New York Academy of Sciences. Formerly, President of Accreditation Board for Engineering and Technology and President, American Society of Engineering Education.
(b) William L. Bennett. Vice-Chairman and Director of HealthPlan Services Corporation, and Director of Sylvan, Inc. Formerly, Chairman, Director and Chief Executive Officer of Noel Group, Inc. and Director of Belding Heminway Company, Inc.
(c) Wendell F. Holland. Vice President, American International Water Services Company and Director of Bryn Mawr Trust 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) Frank A. Metz, Jr. Retired. Director of Norrell Corporation and Solutia, Inc. Formerly, Senior Vice President, Finance and Planning, and Director of International Business Machines Corporation and Director of Monsanto Company.
(f) Steven H. Rice. President, LaJolla Bank, FSB, Northeast Region and Director, LaJolla Bank, FSB. Formerly, Chief Executive Officer and Vice Chairman of the Board of Stamford Federal Savings Bank, bank consultant, President and Director of The Seamen's Bank for Savings, and Director of Royal Group, Inc.
(g) 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), and Deputy Chairman of the Third District Federal Reserve Bank in Philadelphia.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
During 1998, and for 1997 and 1996, the annual compensation paid by AE, 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 $100,000 was as follows:
Summary Compensation Tables (a) AE(b), Monongahela(c), Potomac Edison(c), West Penn(c) and AGC(c) Annual Compensation
All Name Other and Long-Term Compen- Principal Annual Performance sation Position(d) Year Salary($) Incentive($)(e) Plan($)(f) ($)(g)
Alan J. Noia, 1998 525,000 180,500 286,655 184,788 Chief Executive Officer 1997 460,000 253,000 250,657 124,495 1996 360,000 253,750 131,071 92,769
Peter J. Skrgic, 1998 280,008 123,000 204,753 50,757 Senior Vice President 1997 265,000 155,400 150,394 91,409 Supply 1996 245,000 176,300 96,119 24,830
Michael P. Morrell (h) 1998 255,000 117,000 114,870 28,599 Senior Vice President & 1997 240,000 95,200 (h) 26,068 Chief Financial Officer 1996 183,336 72,500 (h) (h)
Jay S. Pifer, 1998 250,008 66,500 131,042 41,542 Senior Vice President 1997 240,000 95,200 150,394 67,810 Delivery 1996 230,000 112,000 87,381 30,949
Richard J. Gagliardi 1998 200,016 60,400 114,662 25,345 Vice President 1997 190,000 75,600 100,263 25,340 Administration 1996 175,000 100,800 52,429 17,898
(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 AE and its subsidiaries. All salaries and bonuses of these executives are paid by APSC.
(b) AE has no paid employees.
(c) Monongahela, Potomac Edison, West Penn, and AGC have 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 1999.
(f) In 1994, the Board of Directors of the Company implemented a Performance Share Plan (the "Plan") for senior officers of the Company and its subsidiaries which was approved by the shareholders of AE at the annual meeting in May 1994. The first Plan cycle began on January 1, 1994 and ended on December 31, 1996. A second cycle began on January 1, 1995 and ended on December 31, 1997. The figure shown for 1996 represents the dollar value paid in 1997 to each of the named executive officers who participated in Cycle I. The figure shown for 1997 represents the dollar value paid in 1998 to each of the named executive officers who participated in Cycle II. A third cycle began on January 1, 1996 and ended on December 31, 1998. The figure shown for 1998 represents the dollar value paid in 1999 to each of the named executives who participated in Cycle III. A fourth cycle began on January 1, 1997 and will end on December 31, 1999. In 1998, the Board of Directors of AE implemented a new Long-Term Incentive Plan, which was approved by the shareholders of AE at the AE annual meeting in May 1998. A fifth cycle (the first three-year performance period of this Plan) began on January 1, 1998 and will end on December 31, 2000. After completion of each cycle, AE stock, stock options (for Cycle V), cash, or a combination may be paid if performance criteria have been met.
(g) The figures in this column include the present value of the executives' cash value at retirement attributable to the current year's premium payment for both the Executive Life Insurance and Secured Benefit Plans (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 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.
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 five 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, except Mr. Morrell, who is not covered by this plan. Effective January 1, 1993, Allegheny started to provide funds to pay for the future benefits due
under the supplemental retirement plan (Secured Benefit Plan). To do this, Allegheny purchased, during 1993, life insurance on the lives of the covered executives. The premium costs of both policies plus a factor for the use of the money are returned to Allegheny 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. Under the ESOSP for 1998, all eligible employees may elect to have from 2% to 10% 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 of nine available funds. Fifty percent of the pre-tax contributions up to 6% of compensation are matched with common stock of AE. Effective January 1 1997, the maximum amount of any employee's compensation that may be used in these computations is $160,000. 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. For 1998, 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) ESOSP contributions, respectively, as follows: Mr. Noia $179,988 and $4,800; Mr. Skrgic $45,957 and $4,800; Mr. Morrell $25,399 and $3,200; Mr. Pifer $36,742 and $4,800; and Mr. Gagliardi $20,545 and $4,800.
(h) Michael P. Morrell joined Allegheny on May 1, 1996, and did not receive a payment from the Long- Term Performance Plan for the first or second Plan cycles. His Cycle III payout is prorated for the period May 1, 1996 - December 31, 1998.
ALLEGHENY ENERGY, INC. LONG-TERM INCENTIVE PLAN SHARES AWARDED IN LAST FISCAL YEAR (CYCLE V)
Estimated Future Payout
The named executives were awarded the above number of performance shares for the 1998-2000 period. Such number of shares are only targets. As described below, no payouts will be made unless certain criteria are met. Each executive's 1998-2000 target long-term incentive opportunity was converted into performance shares equal to an equivalent number of shares of AE common stock based on the price of such stock on December 31, 1997. 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 AE common stock on December 31, 2000 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 Allegheny 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. The final value of an executive's account, if any, will be paid to the executive in early 2001.
The actual payout of an executive's award may range from 0 to 200% of the target amount, before dividend reinvestment. The Management Review of Director Affairs Committee of the Board and Directors may decide to convert the value of such performance shares to stock options at that time or deliver cash or shares of common stock. The payout is based upon stockholder performance versus the peer group. The 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% if there is a 90% or higher ranking.
Retirement Plan
The Company maintains a Retirement Plan covering substantially all employees. The Retirement Plan is a noncontributory, trusteed pension plan designed to meet the requirements of Section 401(a) of the Internal Revenue Code of 1986, as amended (the Code). Each covered employee is eligible for retirement at normal retirement date (age 65), with early retirement permitted. In addition, executive officers and other senior managers participate in a supplemental executive retirement plan (Secured Benefit Plan).
Pursuant to the Secured Benefit Plan, senior executives of Allegheny 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 incentive award paid beginning February 1, 1996 and 100% beginning February 1, 1999. 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. To provide funds to pay such benefits, beginning January 1, 1993, the Company purchased insurance on the lives of the participants in the Secured Benefit Plan. 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 portion of the premiums for this insurance required to be deemed "compensation" by the Securities and Exchange Commission is included in the "All Other Compensation" column on page 56 of this Form 10-K. All exectuive officers are participants in the Secured Benefit Plan. It also provides for use of Average Compensation in excess of Code maximums.
The following table shows estimated maximum annual benefits payable following retirement (assuming payments on a normal life annuity basis and not including any survivor benefit) to an employee in specified remuneration and years of credited service classifications. These amounts are based on an estimated Average Compensation (defined as average total earnings during the highest- paid 36 consecutive calendar months or, if smaller, the member's highest rate of pay as of any July 1st), retirement at age 65 and without consideration of any effect of various options which may be elected prior to retirement. The benefits listed in the Pension Plan Table are not subject to any deduction for Social Security or any other offset amounts.
PENSION PLAN TABLE
(a) The earnings of Messrs. Noia, Skrgic, Pifer, Morrell and Gagliardi covered by the plan correspond substantially to such amounts shown for them in the summary compensation table. As of December 31, 1998, they had accrued 29, 34, 34, 2-1/2 and 20 years of credited service, respectively, under the Retirement Plan. Pursuant to an agreement with Mr. Morrell, at the end of ten years of employment with the Company, Mr. Morrell will be credited with an additional eight years of service.
Change In Control Contracts
AE has entered into Change in Control contracts with the named and certain other Allegheny 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 AE (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 AE 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 base annual salary and target short-term incentive together with AE maintaining existing benefits for the employee and the employee's dependents for a period of three years. Each Agreement expires on December 31, 2001, but is automatically extended for one year periods thereafter unless either AE 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.
Compensation of Directors
In 1998, AE 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, (c) $250 for each Board meeting of each company attended, and (d) 200 shares of AE 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. In addition to the fees mentioned above, the Chairperson of each of the Audit, Finance, Management Review and Director Affairs, New Business, and Strategic Affairs Committees receives a further fee of $4,000 per year.
In addition, a Deferred Stock Unit Plan for Outside Directors provides for a lump sum payment (payable at the director's election in one or more installments, including interest thereon equivalent to the dividend yield) to directors calculated by reference to AE's common stock. Directors who serve at least five years on the Board and leave at or after age 65, or upon death or disability, or as otherwise directed by the Board will receive such payments. Each year, AE credits each Outside Director's account with 275 deferred stock units.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The table below shows the number of shares of AE common stock that are beneficially owned, directly or indirectly, by each director and named executive officer of AE, 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, 1998. To the best of the knowledge of AE, there is no person who is a beneficial owner of more than 5% of the voting securities of AE other than the one shareholder shown in the chart below.
Executive Shares of Officer or APS Percent Name Director of Common Stock of Class
Eleanor Baum AE,MP,PE,WP 2,800* .02% or less William L. Bennett AE,MP,PE,WP 3,570* " Richard J. Gagliardi AE 10,541 " Thomas K. Henderson AE,MP,PE,WP,AGC 5,761 " Wendell F. Holland AE,MP,PE,WP 1,057* " Kenneth M. Jones AE,AGC 11,541 " Phillip E. Lint AE,MP,PE,WP 1,517* " Frank A. Metz, Jr. AE,MP,PE,WP 3,355* " Michael P. Morrell AE,MP,PE,WP,AGC 252 " Alan J. Noia AE,MP,PE,WP,AGC 27,947 " Jay S. Pifer AE,MP,PE,WP 14,547 " Steven H. Rice AE,MP,PE,WP 3,640* " Gunnar E. Sarsten AE,MP,PE,WP 6,800* " Peter J. Skrgic AE,MP,PE,WP,AGC 16,101 "
Sanford C. Bernstein & Co., Inc. 7,948,382 6.49% 767 Fifth Avenue New York, NY 10153
All directors and executive officers of AE as a group (18 persons) 122,459 Less than .10%
All directors and executive officers of MP as a group (18 persons) 115,334 "
All directors and executive officers of PE as a group (18 persons) 115,334 "
All directors and executive officers of WP as a group (19 persons) 121,352 .10%
All directors and executive officers of AGC as a group (8 persons) 74,378 .06%
*Excludes the outside directors' accounts in the Deferred Stock Unit Plan which, at March 1, 1999, were valued at the number of shares shown: Baum 3,463; Bennett 1,720; Holland 1,578; Lint 5,084; Metz 3,732; Rice 2,270; and Sarsten 3,159.
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 AE. 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
None.
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 48.
(b) No companies filed reports on Form 8-K during the quarter ended December 31, 1998.
(c) Exhibits for AE, Monongahela, Potomac Edison, West Penn, and AGC are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ALLEGHENY ENERGY, INC.
By: /s/ Alan J. Noia (Alan J. Noia) Chairman, President and Chief Executive Officer Date: March 4, 1999
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.
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: /s/ Jay S. Pifer (Jay S. Pifer) President and Director Date: March 4, 1999
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.
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: /s/ Jay S. Pifer (Jay S. Pifer) President and Director Date: March 4, 1999
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.
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: /s/ Jay S. Pifer (Jay S. Pifer) President and Director Date: March 4, 1999
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.
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: /s/ Alan J. Noia (Alan J. Noia) Chief Executive Officer Date: March 4, 1999
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.
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectus constituting part of Allegheny Power System Inc.'s (now Allegheny Energy, Inc.) Registration Statements on Form S-3 (Nos. 33-36716 and 33-57027) relating to the Dividend Reinvestment and Stock Purchase Plan of Allegheny Energy, Inc.; in the Prospectus constituting part of Allegheny Power System, Inc.'s (now Allegheny Energy, Inc.) 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. 333-31493, 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. 333-33413, 33- 51305 and 33-59493); and in the Prospectus constituting part of West Penn Power Company's Registration Statements on Form S-3 (Nos. 333-34511, 33-51303, 33- 56997, 33-52862, 33-56260 and 33-59133); of our reports dated February 4, 1999 included in ITEM 8 of this Form 10-K. We also consent to the references to us under the heading "Experts" in such Prospectuses.
PricewaterhouseCoopers, LLP
Pittsburgh, Pennsylvania March 29, 1999
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Energy, 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, 1998 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 4, 1999
/s/ Eleanor Baum /s/ Frank A. Metz, Jr. (Eleanor Baum) (Frank A. Metz, Jr.)
/s/ William L. Bennett /s/ Alan J. Noia (William L. Bennett) (Alan J. Noia)
/s/ Wendell F. Holland /s/ Steven H. Rice (Wendell F. Holland) (Steven H. Rice)
/s/ Phillip E. Lint /s/ Gunnar E. Sarsten (Phillip E. Lint) (Gunnar E. Sarsten)
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, 1998 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 4, 1999
/s/ Michael P. Morrell (Michael P. Morrell)
/s/ Jay S. Pifer (Jay S. Pifer)
/s/ Peter J. Skrgic (Peter J. Skrgic)
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Generating Company, a Virginia corporation, do hereby constitute and appoint 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, 1998 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 4, 1999
/s/ Thomas K. Henderson (Thomas K. Henderson)
/s/ Thomas J. Kloc (Thomas J. Kloc)
/s/ Michael P. Morrell (Michael P. Morrell)
/s/ Alan J. Noia (Alan J. Noia)
/s/ Peter J. Skrgic (Peter J. Skrgic)
E-1
EXHIBIT INDEX (Rule 601(a))
Allegheny Energy, Inc. Incorporation Documents by Reference
3.1 Charter of the Company, Form 10-K of the Company as amended, September 16, 1997 (1-267), December 31, 1997, exh. 3.1
3.2 By-laws of the Company, Form 10-Q of the Company as amended May 14, 1998 (1-267), June 30, 1998, exh. 3.2
4 Subsidiaries' Indentures described below
10.1 Directors' Deferred Form 10-K of the Company Compensation Plan (1-267), December 31, 1994, exh. 10.1
10.2 Executive Compensation Plan Form 10-K of the Company (1-267), December 31, 1996 exh. 10.2
10.3 Allegheny Power System Incentive Form 10-K of the Company Compensation Plan (1-267), December 31, 1996 exh. 10.3
10.4 Allegheny Power System Form 10-K of the Company Supplemental Executive (1-267), December 31, 1996 Retirement Plan exh. 10.4
10.5 Executive Life Insurance Form 10-K of the Company Program and Collateral (1-267), December 31, 1994, Assignment Agreement exh. 10.5
10.6 Secured Benefit Plan Form 10-K of the Company and Collateral Assignment (1-267), December 31, 1994, Agreement exh. 10.6
10.7 Restricted Stock Plan for Outside Directors
10.8 Deferred Stock Unit Plan Form 10-K of the Company for Outside Directors (1-267), December 31, 1997, exh. 10.8
E-1 (cont'd.)
EXHIBIT INDEX (Rule 601(a))
Allegheny Energy, Inc. Incorporation Documents by Reference
10.9 Allegheny Power System Form 10-K of the Company Performance Share Plan (1-267), December 31, 1994, exh. 10.9
10.10 Form of Change in Control Contract With Certain Executive Officers Under Age 55
10.11 Form of Change in Control Contract With Certain Executive Officers Over Age 55
10.12 Allegheny Energy, Inc. Form S-8 of the Company 1998 Long-Term Incentive Plan (1-267), October 14, 1998, exh. 4.1
11 Statement re computation of per share earnings: Clearly determinable from the financial statements contained in Item 8.
21 Subsidiaries of AE:
Name of Company State of Organization
Allegheny Generating Company (a) Virginia Allegheny Power Service Corporation Maryland AYP Capital, Inc. Delaware Monongahela Power Company Ohio The Potomac Edison Company Maryland and Virginia West Penn Power Company Pennsylvania
(a) Owned directly by Monongahela, Potomac Edison, and West Penn.
23 Consent of Independent Accountants See page 69 herein.
24 Powers of Attorney See page 70 herein.
27 Financial Data Schedule
E-2
EXHIBIT INDEX (Rule 601(a))
Monongahela Power Company Incorporation Documents by Reference
3.1 Charter of the Company, Form 10-Q of the Company as amended (1-5164), September 1995, exh. (a)(3)(i)
3.2 Code of Regulations, Form 10-Q of the Company as amended (1-5164), September 1995, exh. (a)(3)(ii)
4 Indenture, dated as of S 2-5819, exh. 7(f) August 1, 1945, and S 2-8782, exh. 7(f)(1) certain Supplemental S 2-8881, exh. 7(b) Indentures of the S 2-9355, exh. 4(h)(1) Company defining rights S 2-9979, exh. 4(h)(1) of security holders.* S 2-10548, exh. 4(b) S 2-14763, exh. 2(b)(i) S 2-24404, exh. 2(c); S 2-26806, exh. 4(d); Forms 8-K of the Company (1-268-2) dated November 21, 1991, July 15, 1992, September 1, 1992, April 29, 1993 and May 23, 1995
* There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the Commission on its request with copies of such Supplemental Indentures.
10.1 Form of Change in Control Contract With Certain Executive Officers Under Age 55
10.2 Form of Change in Control Contract With Certain Executive Officers Over Age 55
E-2 (cont'd.)
EXHIBIT INDEX (Rule 601(a))
Monongahela Power Company Incorporation Documents by Reference
12 Computation of ratio of earnings to fixed charges
21 Subsidiaries: Monongahela Power Company has a 27% equity ownership in Allegheny Generating Company, incorporated in Virginia; and a 25% equity ownership in Allegheny Pittsburgh Coal Company, incorporated in Pennsylvania.
23 Consent of Independent Accountants See page 69 herein.
24 Powers of Attorney See pages 70-71 herein.
27 Financial Data Schedule
E-3
EXHIBIT INDEX (Rule 601(a))
The Potomac Edison Company
Incorporation Documents by Reference
3.1 Charter of the Company, Form 10-Q of the Company as amended (1-3376-2), September 1995, exh. (a)(3)(i)
3.2 By-laws of the Company, Form 10-Q of the Company as amended (1-3376-2), September 1995, exh. (a)(3)(ii)
4 Indenture, dated as of S 2-5473, exh. 7(b); Form October 1, 1944, and S-3, 33-51305, exh. 4(d) certain Supplemental Forms 8-K of the Company Indentures of the (1-3376-2) dated December 11, Company defining rights 1991, December 15, 1992, of security holders* February 17, 1993, March 30, 1993, June 22, 1994, May 12, 1995 and May 17, 1995
* There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the Commission on its request with copies of such Supplemental Indentures.
10.1 Form of Change in Control Contract With Certain Executive Officers Under Age 55
10.2 Form of Change in Control Contract With Certain Executive Officers Over Age 55
12 Computation of ratio of earnings to fixed charges
E-3 (cont'd.)
EXHIBIT INDEX (Rule 601(a))
The Potomac Edison Company
Incorporation Documents by Reference 21 Subsidiaries: The Potomac Edison Company has a 28% equity ownership in Allegheny Generating Company, incorporated in Virginia and a 25% equity ownership in Allegheny Pittsburgh Coal Company, incorporated in Pennsylvania.
23 Consent of Independent See page 69 herein. Accountants
24 Powers of Attorney See pages 70-71 herein.
27 Financial Data Schedule
E-4
EXHIBIT INDEX (Rule 601(a))
West Penn Power Company
Incorporation Documents by Reference
3.1 Charter of the Company, Form 10-Q of the Company as amended (1-255-2), September 1995, exh. (a)(3)(i)
3.2 By-laws of the Company, Form 10-Q of the Company as amended (1-255-2), September 1995, exh. (a)(3)(ii)
4 Indenture, dated as of S-3, 33-51303, exh. 4(d) March 1, 1916, and certain S 2-1835, exh. B(1), B(6) Supplemental Indentures of S 2-4099, exh. B(6), B(7) the Company defining rights S 2-4322, exh. B(5) of security holders.* S 2-5362, exh. B(2), B(5) S 2-7422, exh. 7(c), 7(i) S 2-7840, exh. 7(d), 7(k) S 2-8782, exh. 7(e) (1) S 2-9477, exh. 4(c), 4(d) S 2-10802, exh. 4(b), 4(c) S 2-13400, exh. 2(c), 2(d) Form 10-Q of the Company (1-255-2), June 1980, exh. D Forms 8-K of the Company (1-255-2) dated February 1991, December 1991, August 13, 1992, September 15, 1992, June 9, 1993, August 2, 1994 and May 19, 1995
* There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the Commission on its request with copies of such Supplemental Indentures.
10.1 Form of Employment Contract with Certain Executive Officers Under Age 55
E-4 (cont'd.)
EXHIBIT INDEX (Rule 601(a))
West Penn Power Company
Incorporation Documents by Reference
10.2 Form of Employment Contract with Certain Executive Officers Over Age 55
12 Computation of ratio of earnings to fixed charges
21 Subsidiaries: West Penn Power Company has a 45% equity ownership in Allegheny Generating Company, incorporated in Virginia; a 50% equity ownership in Allegheny Pittsburgh Coal Company, incorporated in Pennsylvania; and a 100% equity ownership in West Virginia Power and Transmission Company, incorporated in West Virginia, which owns a 100% equity ownership in West Penn West Virginia Water Power Company, incorporated in Pennsylvania.
23 Consent of Independent See page 69 herein. Accountants
24 Powers of Attorney See pages 70-71 herein.
27 Financial Data Schedule
E-5
EXHIBIT INDEX (Rule 601(a))
Allegheny Generating Company Incorporation Documents by Reference
3.1(a) Charter of the Company, as amended*
3.1(b) Certificate of Amendment to Charter, effective July 14, 1989**
3.2 By-laws of the Company, as amended, Form 10-K of the Company effective December 23, 1996. (0-14688), December 31, 1996
4 Indenture, dated as of December 1, 1986, and Supplemental Indenture, dated as of December 15, 1988, of the Company defining rights of security holders.***
10.1 APS Power Agreement-Bath County Pumped Storage Project, as amended, dated as of August 14, 1981, among Monongahela Power Company, West Penn Power Company, and The Potomac Edison Company and Allegheny Generating Company.****
10.2 Amendment No. 8, effective date January 1, 1999, to the APS Power Agreement - Bath County Pumped Storage Project.
10.3 Operating Agreement, dated as of June 17, 1981, among Virginia Electric and Power Company, Allegheny Generating Company, Monongahela Power Company, West Penn Power Company and The Potomac Edison Company.****
10.4 Equity Agreement, dated June 17, 1981, between and among Allegheny Generating Company, Monongahela Power Company, West Penn Power Company and The Potomac Edison Company.****
E-5 (cont'd.)
EXHIBIT INDEX (Rule 601(a))
Allegheny Generating Company
Incorporation Documents by Reference
10.5 United States of America Before The Federal Energy Regulatory Commission, Allegheny Generating Company, Docket No. ER84-504-000, Settlement Agreement effective October 1, 1985.****
12 Computation of ratio of earnings to fixed charges
23 Consent of Independent Accountants See page 69 herein.
24 Powers of Attorney See page 72 herein.
27 Financial Data Schedule
__________
* Incorporated by reference to the designated exhibit to AGC's registration statement on Form 10, File No. 0-14688.
** Incorporated by reference to Form 10-Q of the Company (0-14688) for June 1989, exh. (a).
*** Incorporated by reference to Forms 8-K of the Company (0-14688) for December 1986, exh. 4(A), and December 1988, exh. 4.1.
**** Incorporated by reference to Form 10-Q of the Company (0-14688) for June 1989, exh. (a).