Item 1. Business.
Corporate Structure - --------------------------------------------------------------------------------
Part I of this Annual Report on Form 10-K (Report) should be read in conjunction with DQE's audited consolidated financial statements, which are set forth on pages 25 through 51 in Part IV of this Report. Explanations of certain financial and operating terms used in this Report are set forth in a GLOSSARY at the front of this Report.
DQE, Inc. (DQE) is a multi-utility delivery and services company. Its subsidiaries are Duquesne Light Company (Duquesne); AquaSource, Inc. (AquaSource); DQE Energy Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); Duquesne Enterprises, Inc. (DE); and Montauk, Inc. (Montauk). DQE and its subsidiaries are collectively referred to as "the Company."
The Company's utility operations include an electric utility engaged in the generation, transmission, distribution and sale of electric energy and a water resource management company that acquires, develops and manages water and wastewater utilities. The Company's expanded business lines offer a wide range of energy-related technologies, industrial and commercial energy services, telecommunications, and other complementary services. The expanded business lines' initiatives include energy facility development and operation, domestic and international independent power production, the production and supply of innovative fuels, investments in communications systems (including long-distance telephone service) and electronic commerce. In addition, one of the Company's subsidiaries is a financial services company that makes long-term investments and provides financing for the other expanded business lines and related customers.
On December 18, 1998, the Pennsylvania Public Utility Commission (PUC) approved the Company's plan to divest itself of its generation assets through an auction (including an auction of its provider of last resort service), and an agreement in principle to exchange certain power stations with FirstEnergy Corporation (FirstEnergy). Final agreements governing these transactions must be approved by various regulatory agencies. The Company currently expects these transactions to close in late 1999 or early 2000. (See "Rate Matters" on page 19.)
The Company's Service Areas
The Company's electric utility operations provide service to customers in the City of Pittsburgh and surrounding areas. (See "Rate Matters" on page 19.) This territory represents approximately 800 square miles in southwestern Pennsylvania. The population of the area served by the Company's electric utility operations, based on 1990 census data, is approximately 1,510,000, of whom 370,000 reside in the City of Pittsburgh. In addition to serving approximately 580,000 direct customers, the Company's utility operations also sell electricity to other utilities.
The Company's water utility operations provide service throughout the United States. The Company's water utility and related service operations have grown rapidly and are currently approaching 300,000 customer connections.
Regulation
The Company is subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). In addition, the Company's electric utility operations are subject to regulation by the PUC, including regulation under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Customer Choice Act), and the Federal Energy Regulatory Commission (FERC) under the Federal Power Act with respect to rates for interstate sales, transmission of electric power, accounting and other matters. (See "Rate Matters" on page 19.)
The Company's electric utility operations are also subject to regulation by the Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954, as amended, with respect to the operation of its jointly owned/leased nuclear power plants, Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and Perry Unit 1.
The Company's water utility operations are subject to regulation by the utility regulatory bodies in their respective states.
As a result of the PUC's May 29, 1998, final order regarding the Company's restructuring plan under the Customer Choice Act (see "Rate Matters" on page 19), the electricity generation portion of the Company's business no longer meets the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Accordingly, application of SFAS No.71 to this portion of the Company's business has been discontinued and the Company now applies SFAS No. 101, Regulated Enterprises Accounting for the Discontinuation of Application of FASB Statement No. 71 (SFAS No. 101), as interpreted by Emerging Issues Task Force 97-4, Deregulation of the Pricing of Electricity Issues Related to the Application of FASB Statements No. 71 and 101. Under SFAS No. 101, the regulatory assets and liabilities of the generation portion of the Company are determined on the basis of the source from which the regulated cash flows to realize such regulatory assets and settle such liabilities will be derived. Pursuant to the PUC's final restructuring order, certain of the Company's generation-related regulatory assets will be recovered through a competitive transition charge (CTC) collected in connection with providing transmission and distribution services (the
electricity delivery business segment). The Company will continue to apply SFAS No. 71 with respect to such assets. Fixed assets related to the generation portion of the Company's business have been evaluated in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of (SFAS No. 121). Applying SFAS No. 121 to the non-regulated generation assets, it has been determined that the Company's generation assets are impaired. However, pursuant to the PUC's final restructuring order, the Company will recover its above-market investment in generation assets through the CTC. Under the Company's plan to auction its generation assets (currently expected to close in late 1999 or early 2000), the market value utilized by the PUC in determining the value of the generation assets will be the net after-tax proceeds received from the auction. Accordingly, the amount of book value authorized by the PUC to be recovered has been reclassified on the consolidated balance sheet from property, plant and equipment to transition costs, until the auction has been completed and all approvals for the final CTC accounting have been granted. The electricity delivery business segment continues to meet SFAS No. 71 criteria, and accordingly reflects regulatory assets and liabilities consistent with cost- based ratemaking regulations. The regulatory assets represent probable future revenue to the Company, because provisions for these costs are currently included, or are expected to be included, in charges to electric utility customers through the ratemaking process. (See "Rate Matters" on page 19.)
Business Segments
Historically, Duquesne has been treated as a single integrated business segment due to its regulated operating environment. The PUC authorized a combined rate for supplying and delivering electricity to customers. This rate was based on the Company's cost of service, which was designed to recover the Company's operating expenses and investment in electric utility assets and to provide a return on the investment. As a result of the Customer Choice Act, generation of electricity will be deregulated and charged at a separate rate from the delivery of electricity beginning in 1999 (five percent of customers chose alternative generation suppliers in 1998). For the purposes of complying with SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS No. 131), the Company is required to disclose information about its business segments separately. Accordingly, the Company has used the PUC-approved separate rates for 1999 to develop the financial information of the business segments for the periods ended December 31, 1998, 1997 and 1996. (Additional information regarding the Company's business segments is set forth in "Results of Operations" on page 12 and "Business Segments and Related Information," Note O to the consolidated financial statements on page 49.)
Property, Plant and Equipment (PP&E) - --------------------------------------------------------------------------------
Investment in PP&E and Accumulated Depreciation
The Company's total investment in PP&E and the related accumulated depreciation balances for major classes of property at December 31, 1998 and 1997 are as follows:
PP&E and Related Accumulated Depreciation as of December 31, - --------------------------------------------------------------------------------
(a) See "Restructuring Plan" discussion on page 19.
Electric delivery PP&E includes: (1) high voltage transmission wires used in delivering electricity from the generating stations to substations; (2) substations and transformers; (3) lower voltage distribution wires used in delivering electricity to customers; and (4) related poles and equipment. Electric production PP&E includes fossil and nuclear generating stations and, in 1998, an allocated portion of electric general PP&E. This allocation was done in conjunction with the PUC restructuring order. Electric production accumulated depreciation in 1998 reflects the write-down of production plant values to the PUC-determined market value. (See "Restructuring Plan" discussion on page 19.) Electric general PP&E includes internal telecommunication equipment, vehicles and office equipment. The Company's capital leases are primarily associated with leased nuclear fuel and, to a lesser extent, other electric plant. Other PP&E is comprised of water systems, water treatment facilities, various buildings and land, E-Fuel(R) facilities, landfill gas recovery equipment and other property related to the Company's expanded business lines.
Joint Interests in Generating Units
The Company has various contracts with subsidiaries of FirstEnergy (Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company (CEI) and The Toledo Edison Company), with respect to several jointly owned/leased generating units, which include provisions for coordinated maintenance responsibilities, limited and qualified mutual back-up in the event of outages, and certain capacity and energy transactions.
In September 1995, the Company commenced arbitration against CEI, seeking damages, termination of the operating agreement for Eastlake Unit 5 (Eastlake) and partition of the parties' interests in Eastlake through a sale and division of the proceeds. The arbitration demand alleged, among other things, the improper allocation by CEI of fuel and related costs; the mismanagement of the administration of the Saginaw coal contract in connection with the closing of the Saginaw mine, which historically supplied coal to Eastlake; and the concealment by CEI of material information. CEI also seeks monetary damages from the Company for alleged unpaid joint costs in connection with the operation of Eastlake. The Company removed the action to the United States District Court for the Northern District of Ohio, Eastern Division, where it is now pending. Pursuant to the agreement in principle regarding the power station exchange between Duquesne and FirstEnergy, the parties jointly sought and received, on October 26, 1998, a court order staying all proceedings pending execution of definitive exchange agreements. The parties will now seek a further stay of proceedings pending the closing of the exchange. (See "Power Station Exchange" discussion on page 20.)
Joint Interests in Power Stations - --------------------------------------------------------------------------------
*Denotes Operator
(a) In 1987, the Company sold and leased back its 13.74 percent interest in BV Unit 2. The Company leased back its interest in the unit for a term of 29.5 years.
Employees - --------------------------------------------------------------------------------
At December 31, 1998, the Company had 3,986 employees. Duquesne had 1,521 employees in the electricity generation business segment, 1,258 in the electricity delivery business segment and 582 in administration. AquaSource had 539 employees in the water and water service companies, and the other expanded business lines had 86 employees. Duquesne is party to a labor contract expiring in September 2001 with the International Brotherhood of Electrical Workers (IBEW), which represents approximately 2,000 of Duquesne's employees. The contract provides, among other things, employment security, income protection and 3 percent annual wage increases through September 2000. Duquesne and the IBEW have agreed on a package of additional benefits and protections for union employees affected by the divestiture of generation assets. Any buyer of generation assets currently owned by Duquesne will be required to offer work to current IBEW employees on a seniority basis, recognize the IBEW as the exclusive bargaining representative, establish comparable employee benefit plans, and assume the current labor contract.
In connection with the anticipated divestiture, Duquesne has developed early retirement programs and enhanced separation packages available for eligible IBEW and management employees. Duquesne expects to recover related costs through the divestiture proceeds.
Electric Utility Operations - --------------------------------------------------------------------------------
The Company anticipates divesting itself of its generation assets through the auction and the power station exchange by early 2000 and, depending on the regulatory approvals of the final agreements regarding the divestiture, expects certain obligations related to the divested assets will be transferred to the future owners.
The Company's fossil plants operated at an availability factor of 80 percent in 1998 and 84 percent in 1997. The Company's nuclear plants operated at an availability factor of 52 percent in 1998 and 68 percent in 1997. The next refueling outage for BV Unit 1 is currently scheduled to begin in the spring of 2000. BV Unit 2 began a scheduled refueling outage on February 26, 1999. The next refueling outage for Perry Unit 1 is scheduled to begin on March 27, 1999. The timing and duration of scheduled maintenance and refueling outages, as well as the duration of forced outages, affect the availability of power stations. The Company normally experiences its peak demand in the summer. The 1998 customer system peak demand of 2,484 megawatts (MW) occurred on August 7, 1998.
Beaver Valley Power Station (BVPS)
BV Unit 1 went off-line on January 30, 1998, due to an issue identified in a technical review completed by the Company. BV Unit 2 went off-line on December 16, 1997, to repair the emergency air supply system to the control room. BV Unit 2 remained off-line due to other issues identified by a technical review, similar to that performed at BV Unit 1. These technical reviews, held in response to a 1997 commitment made by the Company to the NRC, have been completed. The Company was one of many utilities faced with similar issues, some of which date back to the initial start-up of BVPS. BV Unit 1 returned to service on August 15, 1998, and BV Unit 2 returned to service on September 28, 1998.
BVPS's two units are equipped with steam generators designed and built by Westinghouse Electric Corporation (Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter stress corrosion cracking (ODSCC) has occurred in the steam generator tubes of both units. The units still have the capability to operate at 100 percent reactor power, although approximately 17 percent of BV Unit 1 and 3 percent of BV Unit 2 steam generator tubes have been removed from service. Material acceleration in the rate of ODSCC could lead to a loss in plant efficiency and significant repairs or replacement of BV Unit 1 steam generators. The total replacement cost of the BV Unit 1 steam generators is estimated at $125 million, $59 million of which would be the Company's responsibility. The earliest that the BV Unit 1 steam generators could be replaced during a currently scheduled refueling outage is the fall of 2001. BV Unit 2, which was placed in service 11 years after BV Unit 1, has not yet exhibited the degree of ODSCC experienced at BV Unit 1. It is too early in the life of BV Unit 2 to determine the extent to which ODSCC may become a problem at that unit.
Fossil Fuel
The Company believes that sufficient coal for its coal-fired generating units will be available from various sources to satisfy its requirements for the foreseeable future. During 1998, approximately 2.0 million tons of coal were consumed at the Company's two wholly owned coal-fired stations, Cheswick Power Station (Cheswick) and Elrama Power Station (Elrama).
The Company owns Warwick Mine, an underground mine located in southwestern Pennsylvania. At December 31, 1998, the Company's net investment in the mine was $4.4 million. The Company estimates that, at December 31, 1998, its economically recoverable coal reserves at Warwick Mine were in excess of 1.4 million tons. Commencing in 1997, an unaffiliated operator began producing up to 360,000 tons of coal per year, for exclusive use at Elrama. This arrangement terminates in March 2000. The Company purchases the remaining coal for use at Elrama on the open market. The current estimated liability for mine closing, including final site reclamation, mine water treatment and certain labor liabilities is $47.6 million, and the Company has recorded a liability on the consolidated balance sheet of approximately $39.9 million toward these costs. The remaining $7.7 million will be charged to expense during 1999 and the first quarter of 2000.
During 1998, 48 percent of the Company's coal supplies were provided by contracts, including Warwick Mine, with the remainder satisfied through purchases on the spot market. The Company had three long-term contracts in effect at December 31, 1998, that, in combination with spot market purchases, are expected to furnish an adequate future coal supply. The Company does not anticipate any difficulty in replacing or renewing these contracts as they expire from 2000 through 2005. At December 31, 1998, the Company's wholly owned generating units had on hand an average coal supply of 45 days.
Nuclear Fuel
The cycle of production and utilization of nuclear fuel consists of (1) mining and milling of uranium ore and processing the ore into uranium concentrates, (2) converting uranium concentrates to uranium hexafluoride, (3) enriching the uranium hexafluoride, (4) fabricating fuel assemblies, (5) utilizing the nuclear fuel in the generating station reactor, and (6) storing and disposing of spent fuel.
An adequate supply of uranium is under contract to meet the Company's requirements for its jointly owned/leased nuclear units through 2000. An adequate supply of conversion services through the year 2002 is also under contract. Enrichment services for the Company's joint interests in BV Units 1 and 2 and Perry Unit 1 will be supplied through fiscal year 1999 under a United States Enrichment Corporation (USEC) Utility Services contract. The Company has terminated, at zero cost, all of its enrichment services requirements under this contract for the fiscal years 2000 through 2009 and is planning to secure required enrichment services during this period from other suppliers. The Company continues to review on an annual basis its alternatives for enrichment services for the years 2010 through 2014 under the USEC contract and may terminate these future years if it can arrange more cost-effective enrichment services. Fuel fabrication contracts are in place to supply reload requirements through 2005 and 2004 respectively, for BV Unit 1 and BV Unit 2, and for the life of plant for Perry Unit 1. The Company will continue to make arrangements for future uranium supply and related services, as required. (See "Nuclear Fuel Leasing" discussion on page 18.)
Nuclear Decommissioning
The Company expects to decommission BV Unit 1, BV Unit 2 and Perry Unit 1 no earlier than the expiration of each plant's operating license in 2016, 2027 and 2026, respectively. At the end of its operating life, BV Unit 1 may be placed in safe storage until BV Unit 2 is ready to be decommissioned, at which time the units may be decommissioned together.
Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit 2, and a 1997 update of the 1994 study for Perry Unit 1, the Company's approximate share of the total estimated decommissioning costs, including removal and decontamination costs, is $170 million, $55 million and $90 million, respectively. The amount currently being used to determine the Company's cost of service related to decommissioning all three nuclear units is $224 million.
Funding for nuclear decommissioning costs is deposited in external, segregated trust accounts and invested in a portfolio of corporate common stock and debt securities, municipal bonds, certificates of deposit and United States government securities. The market value of the aggregate trust fund balances at December 31, 1998, totaled approximately $62.7 million.
As part of the power station exchange, FirstEnergy has agreed to assume the decommissioning liability for each of the nuclear plants in exchange for the balance in the decommissioning trust funds, plus the decommissioning costs expected to be collected through the CTC.
Nuclear Insurance
The Price-Anderson Amendments to the Atomic Energy Act of 1954 limit public liability from a single incident at a nuclear plant to $9.8 billion. The maximum available private primary insurance of $200 million has been purchased by the Company. Additional protection of $9.6 billion would be provided by an assessment of up to $88.1 million per incident on each licensed nuclear unit in the United States. The Company's maximum total possible assessment, $66.1 million, which is based on its ownership or leasehold interests in three nuclear generating units, would be limited to a maximum of $7.5 million per incident per year. This assessment is subject to indexing for inflation and may be subject to state premium taxes. If assessments from the nuclear industry prove insufficient to pay claims, the United States Congress could impose other revenue-raising measures on the industry.
The Company's share of insurance coverage for property damage, decommissioning and decontamination liability is $1.2 billion. The Company would be responsible for its share of any damages in excess of insurance coverage. In addition, if the property damage reserves of Nuclear Electric Insurance Limited (NEIL), an industry mutual insurance company that provides a portion of this coverage, are inadequate to cover claims arising from an incident at any United States nuclear site covered by that insurer, the Company could be assessed retrospective premiums totaling a maximum of $7.3 million.
In addition, the Company participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Subject to the policy deductible, terms and limit, the coverage provides for a weekly indemnity of the estimated incremental costs during the three-year period starting 17 weeks after an accident, with no coverage thereafter. If NEIL's losses for this program ever exceed its reserves, the Company could be assessed retrospective premiums totaling a maximum of $2.6 million.
Spent Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 established a federal policy for handling and disposing of spent nuclear fuel and a policy requiring the establishment of a final repository to accept spent nuclear fuel. Electric utility companies have entered into contracts with the United States Department of Energy (DOE) for the permanent disposal of spent nuclear fuel and high-level radioactive waste in compliance with this legislation. The DOE has indicated that its repository under these contracts will not be available for acceptance of spent nuclear fuel before 2010. The DOE has not yet established an interim or permanent storage facility, despite a ruling by the United States Court of Appeals for the District of Columbia Circuit that the DOE was legally obligated to begin acceptance of spent nuclear fuel for disposal by January 31, 1998. Existing on-site spent nuclear fuel storage capacities at BV Unit 1, BV Unit 2 and Perry Unit 1 are expected to be sufficient until 2018, 2012 and 2011, respectively.
In early 1997, the Company joined 35 other electric utilities and 46 states, state agencies and regulatory commissions in filing suit in the United States Court of Appeals for the District of Columbia Circuit against the DOE. The parties requested the court to suspend the utilities' payments into the Nuclear Waste Fund and to place future payments into an escrow account until the DOE fulfills its obligation to accept spent nuclear fuel. The DOE had requested that the court delay litigation while it pursued alternative dispute resolution under the terms of its contracts with the utilities. The court ruling, issued November 14, 1997, and affirmed on rehearing May 5, 1998, denied the relief requested by the utilities and states and permitted the DOE to pursue alternative dispute resolution, but prohibited the DOE from using its lack of a spent fuel repository as a defense. The United States Supreme Court declined to review the decision. The utilities' remaining remedy is to sue the DOE in federal court for money damages caused by the DOE's delay in fulfilling its obligations.
Uranium Enrichment Obligations
Nuclear reactor licensees in the United States are assessed annually for the decontamination and decommissioning of DOE uranium enrichment facilities. Assessments are based on the amount of uranium a utility had processed for enrichment prior to enactment of the National Energy Policy Act of 1992 and are to be paid by such utilities over a 15-year period. At December 31, 1998, the Company's liability for contributions was approximately $6.2 million (subject to an inflation adjustment), which will be recovered through the CTC as part of transition costs.
Environmental Matters - --------------------------------------------------------------------------------
Various federal and state authorities regulate the Company with respect to air and water quality and other environmental matters. The Company believes it is in current compliance with all material applicable environmental regulations. As discussed above, the Company anticipates divesting itself of its generation assets, and expects that environmental obligations related to divested assets will transfer to the new owners.
As required by Title V of the Clean Air Act Amendments (Clean Air Act), the Company filed comprehensive air operating permit applications for Cheswick, Elrama, BI and Phillips in 1995. Approval is still pending for these applications. The Company filed its Title IV Phase II Clean Air Act compliance plan with the PUC on December 27, 1995. The Company also filed Title IV Phase II permit applications for oxides of nitrogen (NO/X/) emissions from Cheswick, Elrama and Phillips with the Allegheny County Health Department and the Pennsylvania Department of Environmental Protection (DEP) on December 23, 1997. Approval is also pending for these applications.
Acid Rain Program Requirements. Although the Company believes it has satisfied all of the Phase I Acid Rain Program requirements of the Clean Air Act, the Phase II Acid Rain Program requires significant additional reductions of sulfur dioxide (SO/2/) through the end of 2000. The Company currently has 662 MW of nuclear capacity and 887 MW of coal capacity equipped with SO/2/ emission- reducing equipment. Through the year 2000, the Company will implement a combination of compliance methods that include fuel switching; increased use of, and improvements in, SO/2/ emission-reducing equipment; and the purchase of emission allowances for those remaining stations where it is anticipated that emissions will exceed allocated SO/2/ allowances.
The Company has developed, patented and installed low NO/X/ burner technology for the Elrama boilers. These cost-effective NO/X/ reduction systems installed on the Elrama roof-fired boilers were specified as the benchmark for the industry for this class of boilers in the Environmental Protection Agency's (EPA) final Group II rulemaking. In 1998, the Company installed low-cost burner modifications to existing low NO/X/ burner technology and a new flue gas conditioning system to maximize the effects of combustion-related controls at Cheswick.
Ozone Reduction Requirements. In addition to the Phase II Acid Rain Program requirements, the Company is responsible for NO/X/ reduction requirements to meet the current Ozone Ambient Air Quality Standards under Title I of the Clean Air Act. Compliance with the current ozone standard is based on pre-1997 ozone data, using a one-hour average value approach. During the 1998 summer ozone season, the western Pennsylvania "area" achieved compliance with the one-hour ozone standard. The Company believes it will continue its current low NO/X/ emission levels under the maintenance plan being established by the DEP. The Company further believes it will be able to meet any additional NO/X/ reduction levels specified under the maintenance plan, through reductions required in 1999 under the Ozone Transport Commission control program described below.
In September 1998, the EPA issued additional ozone-related NO/X/ reduction requirements under the Clean Air Act, which will affect the Company's power plants and will supersede reduction levels specified for 2003 by the Ozone Transport Commission control program. The EPA requires states in the northeast and midwest to amend their implementation plans to impose NO/X/ allowance caps on emissions during the May to September control period. Because the DEP has only recently proposed implementation regulations, the costs of compliance cannot be determined by the Company at this time. However, the Company anticipates that compliance would require additional capital and operation costs beyond those already estimated through 2000.
Future Air Quality Requirements. The Company is closely monitoring other future air quality programs and air emission control requirements that could result from more stringent ambient air quality and emission standards for SO/2/ and NO/X/ particulates and other by-products of coal combustion. In 1997, the DEP finalized a regulation to implement additional NO/X/ control requirements that were recommended by the Ozone Transport Commission. The estimated costs to comply with this program have been included in the Company's capital cost estimates through the year 2000. The Company currently estimates that additional capital costs to comply with the Clean Air Act requirements through the year 2000 will be approximately $5 million. These capital costs may be reduced by short term optimization of NO/X/ reduction systems and the purchase of NO/X/ emission allowances.
In July 1997, the EPA announced new national ambient air quality standards for ozone and fine particulate matter. To allow each state time to determine which areas may not meet the standards, and to adopt control strategies to achieve compliance, the ozone standards will not be implemented until 2004, and the fine particulate matter standards will not be implemented until 2007 or later. Because appropriate state ambient air monitoring and implementation plans have not been developed, the costs of compliance with these new standards cannot be determined by the Company at this time.
In December 1997, more than 160 nations reached a preliminary agreement (Kyoto Protocol), under which, among other things, the United States would be required to reduce its greenhouse gas emissions during the years 2008 through 2012. The Kyoto Protocol has been signed by the Clinton administration. However, until the Kyoto Protocol has been ratified by the Senate and the related greenhouse gas reduction programs have been developed, the costs of compliance cannot be determined by the Company at this time.
Other. In 1992, the DEP issued Residual Waste Management Regulations governing the generation and management of non-hazardous residual waste, such as coal ash. The Company is assessing the sites it utilizes and has developed compliance strategies that are currently under review by the DEP. Capital costs of $3.8 million were incurred by the Company in 1998 to comply with these DEP regulations. Based on information currently available, approximately $4.5 million will be spent in 1999. The additional capital cost of compliance is estimated, based on current information, to be approximately $4.8 million per year for the next three years. This estimate is subject to the results of groundwater assessments and DEP final approval of compliance plans.
Under the Emergency Planning and Community Right-to-Know Act of 1986, certain manufacturing and industrial companies are required to file annual toxic release inventory reports. The first submission by coal- and oil-fired electric utility generating stations is due July 1, 1999, to report on emissions and discharges for 1998. Toxic release inventory reporting does not involve emission reductions. The Company does not anticipate any material impact resulting from this requirement.
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and the Superfund Amendments and Reauthorization Act of 1986 established a variety of informational and environmental action programs. Through its investment in GSF Energy (GSF), the Company indirectly became involved in three hazardous waste sites. GSF was a minor contributor of materials to each site, and other solvent potentially responsible parties are involved. GSF believes that available defenses, along with its overall limited involvement, will limit any potential liability it may have for clean-up costs. Additionally, as part of the GSF investment the Company is indemnified for any costs that it may incur related to these sites by at least one financially responsible party. Accordingly, the Company believes that these matters will not have a material adverse effect on its financial position, results of operations or cash flows.
The Company's water and water-related operations are subject to the federal Safe Drinking Water Act, which provides for uniform minimum national water quality standards, as well as governmental authority to specify treatment processes to be used for drinking water. These operations are also subject to the federal Clean Water Act, which regulates the discharge of pollutants into waterways.
The Company is involved in various other environmental matters. The Company believes that such matters, in total, will not have a materially adverse effect on its financial position, results of operations or cash flows.
Other - --------------------------------------------------------------------------------
Customer Advanced Reliability System
The Customer Advanced Reliability System (CARS) is a communications service that provides the Company with an electronic link to its customers, including the ability to read customer meters. During 1998, the Company's service contract with Itron, Inc. was expanded to include additional advanced commercial and industrial customer metering capabilities and associated software. Installation of this advanced metering subsystem commenced in 1998 and will continue during 1999. As of December 31, 1998, the base CARS system had essentially been completed, with nearly all residential meters adapted for CARS, and approximately 470,000 meters being read daily.
Retirement Plan Measurement Assumptions
The Company decreased the discount rate used to determine the projected benefit obligation on the Company's retirement plans at December 31, 1998, to 6.5 percent. The assumed change in compensation levels and the assumed rate of return on plan assets were also decreased to reflect current market and economic conditions. The effects of these changes on the Company's retirement plan obligations are reflected in the amounts shown in "Employee Benefits," Note N to the consolidated financial statements, on page 46. The resulting change in related expenses for subsequent years is not expected to be material.
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133). This statement establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, (collectively referred to as derivatives) and for hedging activities. The adoption of SFAS No. 133 is not expected to have a significant impact on the Company's financial statements and disclosures.
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Except for historical information contained herein, the matters discussed in this Annual Report on Form 10-K are forward-looking statements which involve risks and uncertainties including, but not limited to, economic, competitive, governmental and technological factors affecting the Company's operations, markets, products, services and prices and other factors discussed in the Company's filings with the Securities and Exchange Commission.
Executive Officers of the Registrant - --------------------------------------------------------------------------------
Set forth below are the names, ages as of March 10, 1999, and positions during the past five years of the executive officers of DQE. Additional information related to the executive officers of DQE is set forth on page 20 of DQE's Annual Report to Shareholders for the year ended December 31, 1998. The information is incorporated here by reference.
Item 2.
Item 2. Properties.
The principal properties of the Company consist of electric generating stations, transmission and distribution facilities, and supplemental properties and appurtenances, comprising as a whole an integrated electric utility system, located substantially in Allegheny and Beaver counties in southwestern Pennsylvania. Substantially all of the Company's electric utility properties are subject to a first mortgage lien.
The Company owns all or a portion of the following generating units except Beaver Valley Unit 2, which is leased. These units are used in the electricity generation business segment. The Company anticipates divesting itself of these units through the auction and the power station exchange by early 2000. (See "Restructuring Plan" discussion on page 19.)
(1) Amounts represent the Company's share of the unit, which is owned by the Company in common with one or more other electric utilities (or, in the case of Beaver Valley Unit 2, leased by the Company).
The Company owns 24 transmission substations (including interests in common in the step-up transformers at Sammis Unit 7; Eastlake Unit 5; Bruce Mansfield Unit 1; Beaver Valley Unit 1; Beaver Valley Unit 2; Perry Unit 1; Bruce Mansfield Unit 2; and Bruce Mansfield Unit 3) and 562 distribution substations. The Company has 714 circuit-miles of transmission lines, comprising 345,000, 138,000 and 69,000 volt lines. Street lighting and distribution circuits of 23,000 volts and less include approximately 50,000 miles of lines and cables. These facilities are used in the electricity delivery business segment.
The Company owns the Warwick Mine, including 4,849 acres owned in fee of unmined coal lands and mining rights, located on the Monongahela River in Greene County, Pennsylvania. (See "Fossil Fuel" discussion on page 4.) This property is used in the electricity generation business segment.
The Company owns three office buildings in Pennsylvania: the corporate headquarters at 500 Cherrington Parkway in Coraopolis; Duquesne's headquarters at 411 Seventh Avenue in Pittsburgh; and One NorthShore Center, 15 Federal Street in Pittsburgh. The Company also owns the six E-Fuel(R) plants located in Kentucky, North Carolina, Ohio, Pennsylvania, South Carolina, and Virginia.
Additional information relating to properties is set forth in "Property, Plant and Equipment," Note C to the consolidated financial statements on page 33 of this Report. The information is incorporated here by reference.
Item 3.
Item 3. Legal Proceedings.
Eastlake Unit 5
In September 1995, the Company commenced arbitration against CEI, seeking damages, termination of the operating agreement for Eastlake and partition of the parties' interests in Eastlake through a sale and division of the proceeds. The arbitration demand alleged, among other things, the improper allocation by CEI of fuel and related costs; the mismanagement of the administration of the Saginaw coal contract in connection with the closing of the Saginaw mine, which historically supplied coal to Eastlake; and the concealment by CEI of material information. CEI also seeks monetary damages from the Company for alleged unpaid joint costs in connection with the operation of Eastlake. The Company removed the action to the United States District Court for the Northern District of Ohio, Eastern Division, where it is now pending. Pursuant to the agreement in principle regarding the power station exchange between Duquesne and FirstEnergy, the parties jointly sought and received, on October 26, 1998, a court order staying all proceedings pending execution of definitive exchange agreements. The parties will now seek a further stay of proceedings pending the closing of the exchange. (See "Power Station Exchange" discussion on page 20.)
Termination of the AYE Merger
On October 5, 1998, the Company announced its unilateral termination of the merger agreement with AYE. More information regarding this termination is set forth in the Company's Current Report on Form 8-K dated October 5, 1998. AYE promptly filed suit in the United States District Court for the Western District of Pennsylvania, seeking to compel the Company to proceed with the merger and seeking a temporary restraining order and preliminary injunction to prevent the Company from certain actions pending a trial, or in the alternative seeking an unspecified amount of money damages. On October 28, 1998, the judge denied AYE's motion for the temporary restraining order and preliminary injunction. AYE appealed to the United States Court of Appeals for the Third Circuit, asking for an injunction pending the appeal and expedited treatment of the appeal. On November 6, 1998, the Third Circuit denied the motion for an injunction and granted the motion to expedite the appeal.
On March 11, 1999, the Third Circuit vacated the October 28 denial of a preliminary injunction. The Third Circuit remanded the case to the District Court for further proceedings to address certain issues, including whether AYE could demonstrate a reasonable likelihood of success on the merits, before determining whether any injunctive relief is warranted. On March 12, 1999, AYE filed a motion for a temporary restraining order with the district court, and a hearing was held that same day. On March 16, 1999, AYE and DQE entered into a consent agreement, which was approved by the district court on March 18. Pursuant to the consent agreement, AYE and DQE have agreed, among other things, that pending the consolidated hearing on AYE's application for a preliminary injunction and/or an expedited trial on the merits, both parties will give each other 10 business days' notice before taking or omitting to take any action which would prevent the merger from qualifying for "pooling of interests" accounting treatment. This would not prevent either party from entering into any agreement, but would require the 10 business days' notice prior to closing any transaction which prevents pooling. The consent agreement shall terminate on September 16, 1999, unless earlier terminated or extended by mutual agreement or an order of the district court.
The Company continues to believe that AYE's claim is entirely without merit in light of the $1 billion disallowance of its stranded costs, which constituted a material adverse effect under the merger agreement and entitled the Company to terminate it as of October 5, 1998. The Company will continue to defend itself vigorously against AYE's claims and intends to pursue a prompt resolution of the litigation. On March 25, 1999, the Company petitioned the Third Circuit for rehearing. The ultimate outcome of this suit cannot be determined at this time.
Proceedings involving the Company's rates are reported in Item 7 under "Rate Matters."
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
a. On November 24, 1998, DQE held its 1998 Annual Meeting of Stockholders.
b. Proxies for the Annual Meeting were solicited pursuant to Regulation 14A under the Securities and Exchange Act of 1934, as amended. There was no solicitation in opposition to management's nominees for directors as listed in the proxy statement dated October 9, 1998, and all nominees were elected.
c. Two proposals were submitted to stockholders for a vote at the Annual Meeting.
Proposal 1 was the election of two directors to the Board of Directors to serve until the 2001 Annual Meeting and until their respective successors have been chosen and qualified. The vote on this proposal was as follows:
The following Directors' terms continue after the Annual Meeting of Stockholders: until 1999 - Sigo Falk and Eric W. Springer; until 2000 - Daniel Berg, Robert P. Bozzone, William H. Knoell and Thomas J. Murrin.
Proposal 2 was the ratification of the appointment, by the Board of Directors, of Deloitte & Touche LLP as independent public accountants to audit the books of the Company for the year ending December 31, 1998. The vote on this proposal was as follows:
Part II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Shareholder Matters.
Information relating to the market for DQE's Common Stock and other matters related to its holders is set forth inside of the back cover of the DQE Annual Report to Shareholders for the year ended December 31, 1998 and on page 46 in Note M and page 51 in Note P hereto. The information is incorporated here by reference. During 1998 and 1997, DQE declared quarterly dividends on its common stock totaling $1.46 per share and $1.38 per share, respectively. At February 28, 1999, there were approximately 67,000 holders of record of the Common Stock of DQE.
Item 6.
Item 6. Selected Financial Data.
Selected financial data for each year of the eleven-year period ended December 31, 1998, are set forth on pages 22 and 23 of the DQE Annual Report to Shareholders for the year ended December 31, 1998. The information is incorporated here by reference.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Results of Operations - --------------------------------------------------------------------------------
Overall Performance
1998 Compared to 1997
On May 29, 1998, the PUC issued its final order related to the Company's restructuring plan. In the second quarter of 1998 the Company recorded an extraordinary charge (Pennsylvania restructuring charge) against earnings for $142.3 million ($82.5 million, net of tax) for the generation-related stranded costs not considered by the PUC's restructuring order to be recoverable from customers. The Pennsylvania restructuring charge included Phillips Power Station (Phillips), Brunot Island Power Station (BI), deferred caretaker costs related to the two stations, and deferred coal costs. The charge resulted in a reduction of Duquesne's contribution to the Company's earnings per share by $1.06. (See "Rate Matters" on page 19.)
The Company's earnings per share in 1998 were $2.52, excluding the Pennsylvania restructuring charge, compared to $2.57 in 1997, resulting in a decrease of $0.05 per share or 1.9 percent. Earnings available for common stock were $195.8 million in 1998, excluding the Pennsylvania restructuring charge, compared to $199.1 million in 1997, resulting in a decrease of $3.3 million or 1.7 percent. The decrease in earnings available for common stock can be primarily attributed to the gains recorded on the sale of Chester Engineers (Chester) and of Exide Electronics Group, Inc. (Exide) stock in 1997, which together contributed $0.17 to earnings per share. Excluding these gains, the resulting increase to earnings per share of $0.12 in 1998 is primarily the result of income attributable to the increased level of long-term investments made late in 1997 and throughout 1998 through the expanded business lines.
1997 Compared to 1996
The Company's earnings per share in 1997 of $2.57 increased by $0.25 or 10.8 percent, compared to earnings per share of $2.32 in 1996. Earnings for common stock were $199.1 million in 1997 compared to $179.1 million in 1996, an increase of $20.0 million or 11.2 percent. The sale of Chester and of Exide stock in 1997 together contributed $0.17 to earnings per share, and an additional $0.19 per share was earned by the expanded business lines, the result of income attributable to the increased level of long-term investments. A partial offset to these increases in net income in 1997 was an incremental $25 million of accelerated nuclear fixed asset recovery as detailed in Duquesne's 1996 PUC-approved mitigation plan.
Dividends
Once all dividends on DQE's Preferred Stock, Series A (Convertible), $100 liquidation preference per share (DQE Preferred Stock), have been paid, dividends may be paid on the Company's common stock to the extent permitted by law and as declared by the board of directors. However, payments of dividends on Duquesne's common stock may be restricted by Duquesne's obligations to holders of preferred and preference stock pursuant to Duquesne's Restated Articles of Incorporation and by obligations of Duquesne's subsidiaries to holders of their preferred securities. No dividends or distributions may be made on Duquesne's common stock if Duquesne has not paid dividends or sinking fund obligations on its preferred or preference stock. Further, the aggregate amount of Duquesne's common stock dividend payments or distributions may not exceed certain percentages of net income if the ratio of total common shareholder's equity to total capitalization is less than specified percentages. As all of Duquesne's common stock is owned by DQE, to the extent that Duquesne cannot pay common dividends, the Company may not be able to pay dividends on its common stock or DQE Preferred Stock.
The Company has continuously paid dividends on common stock since 1953. The Company's annualized dividends per share were $1.52, $1.44, and $1.36 at December 31, 1998, 1997 and 1996. During 1998, the Company paid a quarterly dividend of $0.36 per share on each of January 1, April 1, July 1 and October 1. The quarterly dividend declared in the fourth quarter of 1998 was increased from $0.36 to $0.38 per share payable January 1, 1999. The Company expects that funds generated from operations will continue to be sufficient to pay dividends. The Company's need for and the availability of funds will be influenced by, among other things: new investment opportunities; the economic activity within the Company's utility service territory; competitive and environmental legislation; the results of the anticipated divestiture; and regulatory matters experienced by the electric utility industry generally, more specifically the transition to competition in Pennsylvania. (See "Rate Matters" on page 19.) The Company's stock price was $43 15/16 at the end of 1998.
Results of Business Segments
Beginning in 1999, the Company will have two principal business segments: (1) the transmission and distribution by Duquesne of electricity (electricity delivery business segment) and (2) the generation by Duquesne of electricity and collection of the CTC (electricity generation business segment). To comply with SFAS No. 131, the Company has reported the results for 1998, 1997 and 1996 by these business segments and an "all other" category. The all other category includes the Company's expanded business lines and Duquesne investments. These expanded business lines include water utilities, energy products and services, and other activities. Intercompany transactions primarily relate to sales of electricity, property rental, management fees and dividends. Upon the anticipated completion of the auction of the Company's generation assets and provider of last resort services, the electricity generation business segment will be comprised solely of the collection of the CTC.
1998 Compared to 1997
Electricity Delivery Business Segment. The electricity delivery business segment contributed $57.2 million to net income in 1998 compared to $61.9 million in 1997, a decrease of $4.7 million or 7.7 percent. Operating revenues for this business segment are primarily derived from the Company's delivery of electricity.
Sales to residential and commercial customers are influenced by weather conditions. Warmer summer and colder winter seasons lead to increased customer use of electricity for cooling and heating. Commercial sales are also affected by regional development. Sales to industrial customers are influenced by national and global economic conditions.
Operating revenues increased by $4.5 million or 1.4 percent compared to 1997 due to an increase in sales to electric utility customers of 1.0 percent in 1998. Residential and commercial sales increased as a result of warmer summer temperatures during 1998 compared to 1997. Industrial sales decreased primarily due to a reduction in electricity consumption by steel manufacturers, which experienced a decline in demand. The following table sets forth kilowatt-hours (KWH) delivered to electric utility customers.
Operating expenses for the electricity delivery business segment are primarily made up of costs to operate and maintain the transmission and distribution system; meter reading and billing costs; customer service; collection; administrative expenses; and non-income taxes, such as property and payroll taxes. Operating expenses increased $9.9 million or 7.2 percent from 1997, primarily as a result of higher costs of maintenance of the transmission and distribution system, and start-up costs related to the Customer Advanced Reliability System, including electronic meter reading and installation. The increase in the system maintenance was primarily due to the increase in frequency and severity of storms during 1998.
Depreciation and amortization expense increased $1.7 million or 3.8 percent in 1998 due to additions to the plant and equipment balance throughout the year partially offset by retirements.
Other income is primarily comprised of interest and dividend income. A decrease of $1.6 million or 22.8 percent was the result of lower interest income from a smaller amount of cash available for investing compared to the prior year.
Interest and other charges include interest on long-term debt, other interest and preferred stock dividends of Duquesne. In 1998, there was $0.9 million or 2.3 percent less in interest and other charges compared to 1997. The decrease was the result of the refinancing of long-term debt at lower interest rates and the maturity of approximately $75 million of long-term debt during 1998.
Decreased taxable income during 1998 resulted in lower income taxes by $3.1 million or 7.6 percent.
Electricity Generation Business Segment. In 1998, the electricity generation business segment reported net income of $71.9 million, excluding the Pennsylvania restructuring charge, compared to $60.5 million in 1997, an increase of $11.4 million or 18.8 percent.
For the electricity generation business segment, operating revenues are primarily derived from the Company's supply of electricity for delivery to retail customers and the supply of electricity to wholesale customers. Beginning in 1999, revenues will include the recovery of transition costs through the collection of the CTC. Under prior fuel cost recovery provisions, fuel revenues generally equaled fuel expense, as costs were recoverable from customers through the Energy
Cost Rate Adjustment Clause (ECR), including the fuel component of purchased power, and did not affect net income. Beginning May 29, 1998 (the date of the PUC's final restructuring order), fuel costs were expensed as incurred, and had an impact on net income to the extent fuel costs exceeded amounts included in Duquesne's authorized generation rates. (See "Rate Matters" on page 19.)
Energy requirements for residential and commercial customers are influenced by weather conditions. Warmer summer and colder winter seasons lead to increased customer use of electricity for cooling and heating. Commercial energy requirements are also affected by regional development. Energy requirements for industrial customers are influenced by national and global economic conditions.
Short-term sales to other utilities are made at market rates. Fluctuations in electricity sales to other utilities are related to the Company's customer energy requirements, the energy market and transmission conditions, and the availability of the Company's generating stations. Future levels of short-term sales to other utilities will be affected by market rates, the level of participation in customer choice, the Company's decision to sell 600 MW to licensed generation suppliers and the Company's divestiture of its generation assets. (See "Rate Matters" on page 19.)
Operating revenues decreased by $3.7 million or 0.4 percent compared to 1997. The decrease in revenues can be attributed to a decrease in energy supplied to electric utility customers due to participation in the customer choice pilot program, and a decrease in energy costs that were recovered through the ECR. Partially offsetting these decreases were increased energy supplied to other utilities of 32.2 percent in 1998, due to higher demand from other utilities and increased capacity available to sell as a result of participation in the customer choice pilot program. The following table sets forth KWH supplied for customers who have not chosen an alternative generation supplier.
Operating expenses for the electricity generation business segment are primarily made up of energy costs; costs to operate and maintain the power stations; administrative expenses; and non-income taxes, such as property and payroll taxes.
Fluctuations in energy costs generally result from changes in the cost of fuel, the mix between coal and nuclear generation, total KWH supplied, and generating station availability. Because of the ECR, changes in fuel and purchased power costs did not impact earnings for the first five months of 1998 or any of 1997 or 1996. Beginning May 29, 1998, fuel costs for customers were expensed as incurred, and had an impact on net income to the extent fuel costs exceeded amounts included in Duquesne's authorized generation rates. (See "Rate Matters" on page 19.)
Operating expenses increased $14.4 million or 2.8 percent from 1997 as a result of increased energy costs, partially offset by decreased maintenance costs and reduced BV Unit 2 lease costs due to the PUC's final restructuring order.
In 1998, fuel and purchased power expense increased by $39.1 million or 17.5 percent compared to 1997. This increase was the result of increased energy costs due to an unfavorable power supply mix and higher purchased power prices. Reduced availability of nuclear generating stations due to an increase in outage hours required the Company to purchase power and generate power from the higher fuel cost fossil stations. (See "Beaver Valley Power Station" discussion on page 4.)
Maintenance expense decreased in 1998, primarily related to the reversal of fossil station maintenance outage accruals for outages scheduled after the Company's planned divestiture of generation. (See "Rate Matters" on page 19.) A reduction in nuclear station outage cost amortization in 1998 also contributed to the decrease in maintenance expense.
Depreciation and amortization expense includes the depreciation of the power stations' plant and equipment and accrued nuclear decommissioning costs. A decrease of $32.3 million or 16.8 percent compared to 1997 was the result of reduced depreciation of generation assets in accordance with the PUC's final restructuring order. Beginning in 1999, the Company will be recovering its $2,133 million ($1,485 million, net of tax) of transition costs, as may be adjusted to account for the proceeds of the generation asset auction, through the CTC and will reflect amortization expense related to this recovery.
Other income is primarily comprised of interest and dividend income. A decrease of $3.7 million or 29.1 percent was the result of lower interest income, due to a smaller amount of cash available for investing compared to the prior year.
Interest and other charges include interest on long-term debt, other interest and preferred stock dividends of Duquesne. In 1998 there was a $5.2 million or 8.1 percent reduction in interest and other charges compared to 1997. The decrease reflected the refinancing of long-term debt at lower interest rates and the maturity of approximately $75 million of long-term debt during 1998.
Increased taxable income during 1998 resulted in higher income tax expense by $4.4 million or 13.5 percent.
All Other. The all other category contributed $69.0 million to net income in 1998 compared to $78.1 million in 1997, a decrease of $9.1 million or 11.6 percent.
Operating revenues primarily include revenues from operating activities of the expanded business lines. Operating revenues increased in 1998 by $41.7 million or 64.3 percent compared to 1997. This increase was primarily the result of increased revenues from AquaSource and other new investments through the operating activities of the expanded business lines, partially offset by the loss of operating revenues from the sale of Chester in the second quarter of 1997.
Operating expenses include expenses from operating activities of the expanded business lines and Duquesne investments. In 1998, operating expenses increased $51.1 million or 81.4 percent over 1997. The growth of the expanded business lines' start-up and developmental activities and acquisitions accounted for most of the increase. Also, in the third quarter of 1998 the Company wrote off costs related to the failed merger with Allegheny Energy, Inc. (AYE), resulting in an increase to other operating expenses of $14.1 million. (See "Rate Matters" on page 19.) Offsetting in part the increases to operating expenses was the 1997 sale of Chester, which resulted in reduced operating costs of $7.8 million and the recognition of the favorable resolution of certain associated contingencies in 1998.
Depreciation and amortization expense primarily includes the depreciation of plant and equipment of the expanded business lines and amortization of certain investments. In 1998, depreciation and amortization expense increased by $4.9 million or 107.1 percent, primarily due to the acquisition of water and water-related companies by AquaSource during 1997 and throughout 1998.
Other income primarily includes long-term investment income, and interest and dividend income related to the expanded business lines and Duquesne investments. Other income in 1998 was $9.7 million or 8.1 percent higher than in 1997. This increase was the result of new investments made by the expanded business lines during late 1997 and throughout 1998, and a new investment made at Duquesne in the fourth quarter of 1997. Partially offsetting the increase were the gains on the sale of Chester and of Exide stock in 1997 of approximately $23 million ($13 million, net of tax), net of costs of the sale and reserves for contingencies realized for the sale of Chester.
Interest and other charges are made up of interest on long-term debt, other interest and preferred stock dividends of the expanded business lines, and Duquesne investments. An increase of $0.6 million or 4.5 percent in 1998 was the result of higher long-term debt interest expense, primarily related to AquaSource debt assumptions associated with the acquisition of certain water and water service companies.
Higher income tax expense of $3.8 million or 15.6 percent in 1998 can be attributed to the increase in taxable income.
1997 Compared to 1996
Electricity Delivery Business Segment. The electricity delivery business segment contributed $61.9 million to net income in 1997 compared to $56.6 million in 1996, an increase of $5.3 million or 9.4 percent.
Operating revenues increased by $8.1 million or 2.6 percent compared to 1996, due to an increase in sales to electric utility customers of 1.1 percent in 1997 and a settlement for pole rental revenue in 1997. Sales to electric utility customers increased despite 1997's mild temperatures compared to 1996 primarily as a result of stronger industrial sales. The following table sets forth KWH delivered for electric utility customers.
Operating expenses decreased $1.0 million or 0.7 percent from 1996, as a result of small decreases in operating and maintenance costs of the transmission and distribution system.
Depreciation and amortization expense increased $0.2 million or 0.5 percent in 1997 due to additions to the plant and equipment balance throughout the year, which were partially offset by retirements.
Other income increased $1.6 million or 31.4 percent and was the result of higher interest income from a larger amount of cash available for investing compared to 1996.
In 1997, there was a $1.4 million or 3.8 percent increase in interest and other charges compared to 1996. This increase was the result of paying a full year of dividends in 1997 related to the Monthly Income Preferred Securities (MIPS) issued in May 1996.
Increased taxable income during 1997 resulted in higher income tax expense by $3.8 million or 10.3 percent.
Electricity Generation Business Segment. In 1997, the electricity generation business segment reported net income of $60.5 million compared to $77.6 million in 1996, a decrease of $17.0 million or 22.0 percent.
Operating revenues decreased by $19.6 million or 2.2 percent compared to 1996, due to a decrease in energy supplied to other utilities of 56.4 percent in 1997. This decrease was due to reduced availability resulting from the sale of the Ft. Martin Power Station in the fourth quarter of 1996 and increased forced outages. Partially offsetting the decrease in energy supplied to other utilities was a $3.2 million increase related to charges to the other BVPS owners for administrative costs. The following table sets forth KWH supplied for customers who have not chosen an alternative generation supplier.
Operating expenses decreased $9.7 million or 1.8 percent from 1996, as a result of decreased energy volume supplied partially offset by increased maintenance costs.
In 1997, fuel and purchased power expense decreased by $13.5 million or 5.7 percent compared to 1996, as a result of an 11.1 percent reduction in energy volume supplied. This $26.7 million decrease due to energy volume supplied was partially offset by increased energy costs of $13.2 million, primarily the result of purchased power prices. Reduced availability of generating stations due to an increase in outage hours forced the Company to purchase power during high demand periods, resulting in increased costs.
Maintenance expense increased in 1997 compared to 1996. The increase was due to more forced outage hours at nuclear stations than during 1996.
An increase in depreciation and amortization expense of $19.7 million or 11.4 percent over 1996 was due to the May 1, 1996, increase in the Company's nuclear generation plant depreciation rate resulting in higher depreciation for the first four months of 1997. In addition, accelerated nuclear lease recovery, which began on May 1, 1997, resulted in higher annualized amortization expense of $25 million. Offsetting these increases by $8.5 million was the mid-1996 completion of the recovery of the investment in Perry Unit 2, the construction of which was abandoned by the Company in 1986. The remaining increase can be attributed to incremental depreciation for 1997 fixed asset additions and an increased level of nuclear decommissioning cost recognition.
Other income increased $2.9 million or 29.7 percent and was the result of higher interest income, due to a larger amount of cash available for investing compared to the prior year.
In 1997 there was a $0.4 million or 0.7 percent increase in interest and other charges compared to 1996. The increase was the result of paying a full year of dividends in 1997 related to the MIPS issued in May 1996.
Decreased taxable income during 1997 resulted in lower income tax expense by $10.1 million or 23.9 percent.
All Other. The all other category contributed $78.1 million to net income in 1997 compared to $48.7 million in 1996, an increase of $29.4 million or 60.4 percent.
Operating revenues increased in 1997 by $5.9 million or 10.0 percent compared to 1996. The increase resulted primarily from a $20.4 million increase in revenues from a landfill gas recovery investment made in the fourth quarter of 1996 and growth in the operating activities of the expanded business lines. Partially offsetting the increase in revenues was the sale of Chester in the second quarter of 1997, which decreased revenues by approximately $20 million.
In 1997 operating expenses increased $8.3 million or 15.2 percent over 1996. The increase is attributable to operating costs from a landfill gas recovery investment made during 1996 and the growth of the expanded business lines, partially offset by the reduced operating costs associated with Chester during the first half of 1997.
Other income in 1997 was $48.0 million or 67.5 percent higher compared to 1996. The increase was the result of long-term investment income, gains on the sale of Chester and of Exide stock, and interest and dividend income from a higher level of short-term investments. The increase in long-term investment income of approximately $15 million was the result of investments made during 1996 and 1997. The Company invested approximately $180 million in lease investments in 1997. In the second quarter of 1997, Chester was sold for a pre- tax gain of approximately $12 million, net of estimated costs of the sale. Also, in the fourth quarter of 1997, the Company sold its investment in Exide stock for a pre-tax gain of approximately $11 million.
An increase in interest and other charges of $3.0 million or 27.5 percent in 1997 compared to 1996 was the result of higher long-term debt interest expense associated with higher average borrowings outstanding.
Higher income tax expense of $13.2 million or 117.7 percent in 1997 resulted from an increase in taxable income.
Liquidity and Capital Resources - --------------------------------------------------------------------------------
Capital Expenditures
The Company spent approximately $190.5 million in 1998, $116.0 million in 1997 and $101.2 million in 1996 for capital expenditures, of which $113.3 million in 1998, $90.4 million in 1997 and $87.9 million in 1996 was spent for electric utility construction. The remaining capital expenditures were related to the Company's expanded business lines and Duquesne investments. The Company's capital expenditures for electric utility construction focus on improving and/or expanding electric utility generation, transmission and distribution systems. The Company currently estimates that it will spend, excluding allowance for funds used during construction (AFC) and nuclear fuel, approximately $110 million during 1999 (including $30 million for generation), $75 million in 2000 (excluding generation) and $70 million in 2001 (excluding generation) for electric utility construction.
In 1998 the Company completed construction of six plants to produce E- Fuel(R), a coal-based synthetic fuel, at a cost of approximately $40 million. All of these plants are currently in operation.
Long-Term Investments
The Company has made long-term investments in the following areas: leases, affordable housing, gas reserves and energy solutions. Investing activities during 1998 included approximately $22 million in affordable housing partnerships, $22 million in natural gas reserves and the remaining $25 million in the decommissioning trust fund and other investments. This $25 million includes investments in BroadPoint Communications, Inc. BroadPoint has introduced the FreeWay(TM) Service, in which customers earn free long-distance telephone service in exchange for listening to short, targeted audio advertisements. The Company also invested in North American Power Brokers, Inc., a provider of a low-bid, Internet auction-based approach to purchasing natural gas and electricity through a secure website. Investing activities during 1997 included approximately $180 million in lease investments, $11 million in landfill gas reserve investments, $16 million in affordable housing partnerships, and $12 million in the decommissioning trust fund and other investments. During 1997, the Company committed to approximately $5 million in equity funding obligations for lease investments. Investing activities during 1996 included approximately $50 million in lease investments, $30 million in gas reserve investments, $15 million in affordable housing partnerships, and $6 million in energy solution and other investments. During 1996, the Company also committed to approximately $37 million in equity funding obligations for lease and affordable housing partnerships.
Acquisitions and Dispositions
In 1998, the Company issued 337,262 shares of DQE Preferred Stock, representing an investment of approximately $34 million (out of a total investment of approximately $156 million in stock and cash) in the acquisition of water and water-related companies. The Company has invested approximately $35 million in stock and cash for additional water and water-related company acquisitions through February 1999. The Company also invested $22 million to acquire a 50 percent interest in and finance the growth of Control Solutions, LLC, a commercial and industrial heating, ventilation and air conditioning service and energy controls company.
Dispositions in 1998 related to assets acquired by the Company through leasehold interest investments. Dispositions in 1997 related primarily to the sale of Chester and of Exide stock. Dispositions in 1996 were comprised of long- term leveraged lease assets totaling $18 million.
The Company is studying restructuring its current investment portfolio, including the possible divestiture of its $131 million portfolio of affordable housing investments.
Financing
The Company currently expects to meet its current obligations and debt maturities through the year 2003 with funds generated from operations, through new financings and through the proceeds from the auction of generation assets. To the extent that acquisition and long-term investment opportunities prior to the generation divestiture exceed current expectations, the Company may explore various financing alternatives. At December 31, 1998, the Company was in compliance with all of its debt covenants.
During 1998, $75 million of mortgage bonds matured and were retired and $100 million of 8.75 percent mortgage bonds due in May 2022 were redeemed. The retirement and redemption were financed using available cash, the proceeds of the $40 million of 6.45 percent mortgage bonds due in February 2008 and the proceeds of the $100 million of 7.375 percent mortgage bonds due in April 2038 issued by Duquesne. Mortgage bonds in the amount of $75 million will mature in July 1999. The Company expects to retire these bonds with available cash, or to refinance the bonds.
In connection with the investment in certain landfill gas property and equipment during 1998, the Company issued a $25 million note maturing in 2019, with an annual interest rate of 8.0 percent.
In connection with the power station exchange with FirstEnergy, the Company anticipates terminating the BV Unit 2 lease, in which case the lease liability recorded on the consolidated balance sheet would no longer be an obligation of the Company. The underlying collateralized lease bonds ($371.0 million at December 31, 1998) would become direct obligations of the Company and be recorded on the consolidated balance sheet. The Company would also pay approximately $230 million in termination costs, a portion of which the Company expects to recover through the proceeds of the generation asset auction. (See "Power Station Exchange" discussion on page 20.)
The Company has $150 million in bank term loans outstanding at December 31, 1998, with $65 million maturing in 2000 and $85 million maturing in 2001.
In July 1997, the Company authorized and registered 1,000,000 shares of the DQE Preferred Stock, all with $100 liquidation preference, for use in connection with acquisitions by the Company of other businesses, assets or securities. Approximately $25 million in long-term debt has been assumed in connection with these acquisitions. (See "Acquisitions and Dispositions" discussion on page 17.) As of December 31, 1998, 352,742 shares of DQE Preferred Stock had been issued and were outstanding. An additional 29,928 shares of DQE Preferred Stock were issued in January and February 1999.
A Duquesne subsidiary has 15 shares of preferred stock, par value $100,000 per share outstanding. The holders of such shares are entitled to a 6.5 percent annual dividend to be paid each September 30.
In May 1996, Duquesne Capital L.P. (Duquesne Capital), a special-purpose limited partnership of which Duquesne is the sole general partner, issued $150.0 million principal amount of 8 3/8 percent MIPS with a stated liquidation value of $25.00. The holders of MIPS are entitled to annual dividends of 8 3/8 percent, payable monthly. Such dividends are guaranteed by Duquesne.
The Company repurchased shares of its common stock on the open market late in 1998.
Short-Term Borrowings
At December 31, 1998, the Company had two extendible revolving credit arrangements, including a $125 million facility expiring in June 1999 and a $150 million facility expiring in October 1999. Interest rates can, in accordance with the option selected at the time of the borrowing, be based on prime, Eurodollar or certificate of deposit rates. Commitment fees are based on the unborrowed amount of the commitments. Both credit facilities contain two-year repayment periods for any amounts outstanding at the expiration of the revolving credit periods. At December 31, 1998 and December 31, 1997, there were no short- term borrowings outstanding.
Sale of Accounts Receivable
The Company and an unaffiliated corporation have an agreement that entitles the Company to sell, and the corporation to purchase, on an ongoing basis, up to $50 million of accounts receivable. The Company had no receivables sold at December 31, 1998 or December 31, 1997. The accounts receivable sales agreement, which expires in June 1999, is one of many sources of funds available to the Company. The Company may attempt to extend the agreement, replace it with a similar facility, or eliminate it upon expiration.
Nuclear Fuel Leasing
The Company finances its acquisitions of nuclear fuel through a leasing arrangement, under which it may finance up to $75 million of nuclear fuel. As of December 31, 1998, the amount of nuclear fuel financed by the Company under this arrangement totaled approximately $41.8 million. The actual nuclear fuel costs to be financed will be influenced by such factors as changes in interest rates; lengths of the respective fuel cycles; reload cycle design; operations; the power station exchange; and changes in nuclear material costs and services, the prices and availability of which are not known at this time. Such costs may also be influenced by other events not presently foreseen. The Company plans to continue leasing nuclear fuel to fulfill its requirements at least through September 1999, the remaining term of the leasing arrangement. The Company may attempt to extend the arrangement, replace it with a similar facility, or eliminate it upon expiration through the purchase of the balance of the nuclear fuel. The Company anticipates divesting its nuclear stations. (See "Power Station Exchange" discussion on page 20.)
Rate Matters - --------------------------------------------------------------------------------
Competition and the Customer Choice Act
The electric utility industry continues to undergo fundamental change in response to development of open transmission access and increased availability of energy alternatives. Under historical ratemaking practice, regulated electric utilities were granted exclusive geographic franchises to sell electricity, in exchange for making investments and incurring obligations to serve customers under the then-existing regulatory framework. Through the ratemaking process, those prudently incurred costs were recovered from customers, along with a return on the investment. Additionally, certain operating costs were approved for deferral for future recovery from customers (regulatory assets). As a result of this historical ratemaking process, utilities had assets recorded on their balance sheets at above-market costs, thus creating transition and stranded costs.
In Pennsylvania, the Customer Choice Act went into effect on January 1, 1997. The Customer Choice Act enables Pennsylvania's electric utility customers to purchase electricity at market prices from a variety of electric generation suppliers (customer choice). Although the Customer Choice Act will give customers their choice of electric generation suppliers, the existing, franchised local distribution utility is still responsible for delivering electricity from the generation supplier to the customer. The local distribution utility is also required to serve as the provider of last resort for all customers in its service territory, unless other arrangements are approved by the PUC. The provider of last resort must provide electricity for any customer who cannot or does not choose an alternative electric generation supplier, or whose supplier fails to deliver. The Customer Choice Act provides that the existing franchised utility may recover, through a CTC, an amount of transition costs that are determined by the PUC to be just and reasonable. Pennsylvania's electric utility restructuring is being accomplished through a two-stage process consisting of an initial customer choice pilot period (which ended in December 1998) and a phase-in to competition period (which began in January 1999). The Company's estimated negative net income impact of the customer choice pilot program during 1998, with five percent of customers participating, was approximately $6 million.
Phase-In to Competition
The phase-in to competition began in January 1999, when 66 percent of customers became eligible to participate in customer choice (including customers covered by the pilot program); all customers will have customer choice in January 2000. As of February 28, 1999, approximately 12.5 percent of the Company's customers had chosen alternative generation suppliers. Customers that have chosen an electricity generation supplier other than the Company pay that supplier for generation charges, and pay the Company a CTC (discussed below) and charges for transmission and distribution. Customers that continue to buy their generation from the Company pay for their service at current regulated tariff rates divided into generation, transmission and distribution charges. Under the Customer Choice Act, an electric distribution company, such as Duquesne, remains a regulated utility and may only offer PUC-approved rates, including generation rates. Also under the Customer Choice Act, electricity delivery (including transmission, distribution and customer service) remains regulated in substantially the same manner as under current regulation.
In an effort to "jump start" retail competition, the Company has made 600 MW of power available to licensed electric generation suppliers, to be used in supplying electricity to Duquesne's customers who have chosen alternative generation suppliers. The power will be available for the first six months of 1999 at a price of 2.6 cents per KWH. This power availability will be structured to ensure the power is used to benefit Duquesne's retail customers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, has been imposed on the transmission and distribution charges of Pennsylvania electric utility companies under the Customer Choice Act. Additionally, electric utility companies may not increase the generation price component of rates as long as transition costs are being recovered, with certain exceptions.
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that the Company should recover most of the above-market costs of the generation assets, including plant and regulatory assets through the collection of the CTC from electric utility customers. The total of the transition costs to be recovered is $2,133 million ($1,485 million, net of tax) over a seven-year period beginning January 1, 1999, as may be adjusted to account for the proceeds of the generation asset auction. In addition, the transition costs as reflected on the consolidated balance sheet will be amortized over the same period that the CTC revenues are being recognized. The Company will earn an 11 percent pre-tax return on the unrecovered balance.
In the second quarter of 1998, the Company recorded an extraordinary charge (PUC restructuring charge) against earnings of $142.3 million ($82.5 million, net of tax) for the generation-related stranded costs not considered by the PUC's restructuring order to be recoverable from customers. The Pennsylvania restructuring charge included Phillips, BI, deferred caretaker costs related to the two stations and deferred coal costs. The charge resulted in a reduction of Duquesne's contribution to the Company's earnings per share by $1.06.
Restructuring Plan and Auction Plan. With respect to transition cost recovery, the PUC's final order on the restructuring plan approved Duquesne's proposal to auction its generation assets and use the proceeds to offset transition costs. The remaining balance of such costs (with certain exceptions described below) will be recovered from ratepayers through a CTC, collectible through 2005. Until the divestiture is complete, Duquesne has been ordered to use an interim system average CTC and price to compare based on the methodology approved in its pilot program (approximately 2.9 cents per KWH for the CTC and approximately 3.8 cents per KWH for the price to compare).
On December 18, 1998, the PUC approved Duquesne's auction plan, including an auction of its provider of last resort service, as well as an agreement in principle to exchange certain generation assets with FirstEnergy. The assets to be auctioned will include Duquesne's wholly owned Cheswick Power Station, Elrama Power Station, Phillips and BI, as well as the stations to be received from FirstEnergy in the power station exchange described below. The auction plan calls for a two-phase, sealed bid process similar to that used in other power plant divestitures. The initial confidential bidding process is expected to begin in the spring of 1999, with potential buyers identified by Duquesne being asked to submit non-binding bids. Final agreements governing the transactions must be approved by various regulatory agencies, including the PUC, the FERC, the NRC, the Department of Justice and/or the Federal Trade Commission. Duquesne currently expects the sale to close at the end of 1999 or the beginning of 2000.
Power Station Exchange. Pursuant to the definitive agreements entered into on March 25, 1999 (which remain subject to regulatory approval), Duquesne and FirstEnergy will exchange ownership interests in certain power stations. Duquesne will receive 100 percent ownership rights in three coal-fired power plants located in Avon Lake and Niles, Ohio and New Castle, Pennsylvania (totaling approximately 1,300 MW), which the Company expects to sell simultaneously as part of the auction of generation assets. FirstEnergy will acquire Duquesne's interests in BV Unit 1, BV Unit 2, Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield Units 1, 2 and 3 (totaling approximately 1,400 MW). In connection with the power station exchange, the Company anticipates terminating the BV Unit 2 lease. (See "Financing" discussion on page 17.) Pursuant to the December 18, 1998, PUC order and subject to final approval, the proceeds from the sale of the power stations received in the exchange will be used to offset the transition costs associated with Duquesne's currently-held generation assets and the costs associated with completing the exchange. Duquesne expects this exchange to enhance the value received from the auction, because participants will bid on plants that are wholly owned by Duquesne, rather than plants that are jointly owned and/or operated by another entity. Additionally, the auction will include only coal- and oil-fired plants, which are anticipated to have a higher market value than nuclear plants. These value-enhancing features, along with a minimum level of auction proceeds guaranteed by FirstEnergy, are expected to maximize auction proceeds, minimize transition costs required to be recovered through the CTC (by shortening the length of the CTC recovery period), and thus reduce customer bills as rapidly as possible. Other benefits of this exchange include the resolution of all joint ownership issues, and other risks and costs associated with the jointly-owned units. Although the PUC has said the exchange appears to be in the public interest, the definitive exchange agreement must be submitted for PUC approval, and certain aspects of the exchange will have to be approved by, among other agencies, the FERC, the NRC and the Department of Justice. The power station exchange is expected to occur simultaneously with the anticipated closing of the sale of Duquesne's generation through the auction at the end of 1999 or in early 2000.
Termination of the AYE Merger
On July 28, 1998, DQE's board of directors concluded that it could not consummate the merger with AYE, toward which the Company had been working. The Company believes that AYE suffered a material adverse effect as a result of the PUC's final restructuring order regarding AYE's utility subsidiary, West Penn Power Company. More information regarding this decision is set forth in the Company's Current Report on Form 8-K dated July 28, 1998. On July 30, 1998, AYE informed DQE that it would continue to work toward consummation of the merger, and also pursue all remedies available to protect the legal and financial interests of AYE and its shareholders.
On September 17, 1998, the PUC issued an order stating that, unless the parties jointly agreed to an extension of time to consummate the merger beyond October 5, 1998 (the relevant date under the merger agreement), their merger application with the PUC would be considered withdrawn. On October 5, 1998, the Company announced its unilateral termination of the merger agreement. More information regarding this termination is set forth in the Company's Current Report on Form 8-K dated October 5, 1998. In a letter dated February 24, 1999, the PUC informed the Company that the merger application was deemed withdrawn and the docket was closed.
AYE filed suit in the United States District Court for the Western District of Pennsylvania, seeking to compel the Company to proceed with the merger and seeking a temporary restraining order and preliminary injunction to prevent the Company from certain actions pending a trial, or in the alternative seeking an unspecified amount of money damages. On October 28, 1998, the judge denied AYE's motion for the temporary restraining order and preliminary injunction. AYE appealed to the United States Court of Appeals for the Third Circuit, asking for an injunction pending the appeal and expedited treatment of the appeal. On November 6, 1998, the Third Circuit denied the motion for an injunction and granted the motion to expedite the appeal.
On March 11, 1999, the Third Circuit vacated the October 28 denial of a preliminary injunction. The Third Circuit remanded the case to the District Court for further proceedings to address certain issues, including whether AYE could demonstrate a reasonable likelihood of success on the merits, before determining whether any injunctive relief is warranted. On March 12, 1999, AYE filed a motion for a temporary restraining order with the district court, and a hearing was held that same day. On March 16, 1999, AYE and DQE entered into a consent agreement, which was approved by the district court on March 18. Pursuant to the consent agreement, AYE and DQE have agreed, among other things, that pending the consolidated hearing on AYE's application for a preliminary injunction and/or an expedited trial on the merits, both parties will give each other 10 business days' notice before taking or omitting to take any action which would prevent the merger from qualifying for "pooling of interests" accounting treatment. This would not prevent either party from entering into any agreement, but would require the 10 business days' notice prior to closing any transaction which prevents pooling. The consent agreement shall terminate on September 16, 1999, unless earlier terminated or extended by mutual agreement or an order of the district court.
The Company continues to believe that AYE's claim is entirely without merit in light of the $1 billion disallowance of its stranded costs, which constituted a material adverse effect under the merger agreement and entitled the Company to terminate it as of October 5, 1998. The Company will continue to defend itself vigorously against AYE's claims and intends to pursue a prompt resolution of the litigation. On March 25, 1999, the Company petitioned the Third Circuit for rehearing. In the interim, the Company intends to continue to pursue the implementation of customer choice under its PUC-approved restructuring plan, including the power station exchange with FirstEnergy and the generation asset auction. The ultimate outcome of this suit cannot be determined at this time.
Deferred Energy Costs
As part of its restructuring plan filing, the Company requested recovery of $11.5 million ($6.7 million, net of tax) through the CTC for energy costs previously deferred under the ECR. Recovery of this amount was approved in the PUC's final restructuring order. The Company also requested recovery of an additional $31.2 million ($18.2 million, net of tax). This amount relates to fuel costs that had been deferred between the time of the restructuring plan filing and the restructuring order in accordance with a PUC order with respect to the Company's ECR. As part of its December 18, 1998, order the PUC denied recovery of this additional amount. The Company has appealed the PUC's denial of recovery to the Pennsylvania Commonwealth Court.
Based upon the Customer Choice Act, which mandates recovery of all regulatory assets, and the PUC's specific authorization for the Company to create a regulatory asset for these costs, the Company believes that it is probable that these costs will be recovered through retail rates. In the event that the Company does not prevail in its appeal with the Pennsylvania Commonwealth Court, these costs would be written off as a charge against income.
Year 2000 - --------------------------------------------------------------------------------
Many existing computer programs and embedded microprocessors use only two digits to identify a year (for example, "98" is used to represent "1998"). Such programs read "00" as the year 1900, and thus may not recognize dates beginning with the year 2000, or may otherwise produce erroneous results or cease processing when dates after 1999 are encountered.
Year 2000 Plan. In 1994, the Company began reviewing its critical information systems that impact operations and financial reporting in order to develop a strategy to address required computer software and system changes and upgrades. The Company has since assembled a Year 2000 team, comprised of management representatives from all functional areas of the Company, which continues to explore the exposure to Year 2000-related issues in computer software and in devices and equipment (such as plant components, substations, elevators, and heating and cooling systems) containing embedded microprocessors that may not correctly identify the year. The team is also exploring potential related issues that may originate with third parties with whom the Company does business. To support the planning, organization and management of its efforts, the team has retained Year 2000 consultants.
In general, the Company's overall strategy to address the Year 2000 issue is comprised of four phases that, in some cases, are performed simultaneously. These phases are: inventory, assessment, remediation, and testing and implementation.
Inventory consists of identifying the various components, equipment, hardware, and software used in the Company's operations that may potentially be faced with Year 2000 issues. This inventory effort was completed during the fourth quarter of 1998.
Assessment consists of evaluating all inventoried items for Year 2000 compliance or readiness. This is accomplished by contacting the vendors and manufacturers, inspecting software and code, researching the results of other companies' assessment of like components, and various other means. Assessment activities have been completed as of the date of this Report. The Company's business is dependent upon external suppliers for the reliable delivery of their products and services. The Company has inquired in writing of its suppliers and service providers with regard to their Year 2000 readiness. The Company is meeting with critical suppliers and service providers to further corroborate evidence of their Year 2000 readiness.
Remediation refers to the activities necessary to fix or replace those components that have Year 2000 issues that will adversely affect the Company's operations. Remediation concentrates first on those systems, components, and equipment that substantially impact the Company's ability to perform its essential business functions (mission critical). Remediation is currently under way and is scheduled to be substantially complete in the second quarter of 1999. This remediation is in addition to previously planned improvements to the Company's systems with benefits beyond Year 2000 solutions, such as total system replacements discussed below.
Testing and implementation consists of placing renovated processes, systems, equipment, and other items into use within the Company's operations. Testing is performed on all mission critical processes, whether or not remediation activities were involved in the process. Testing and implementation will be substantially completed during the second quarter of 1999.
Throughout the execution of its Year 2000 plan, the Company has been providing and will continue to provide information on its activities to the PUC, the NRC and the North American Electric Reliability Counsel (NERC), which coordinates the network of interconnected utilities across the nation. The Company's plan is in accordance with NRC guidelines, and the Company is working with the NRC to certify that its nuclear power station safety and operations systems, and issues related to suppliers, will be ready for the Year 2000. NERC has been requested by the United States Department of Energy (DOE) to review the national electric power production and delivery infrastructure to ensure a reliable power supply during the Year 2000 transition period. The Company is working with NERC to address these issues through monthly status reporting and participation in regional Year 2000 tests. The Company also participates in the Electric Power Research Institute's project to share information about technical issues regarding Year 2000 with other entities in the electric utility industry.
Risks and Contingency Plans. The Company currently believes that implementation of its plan will minimize the Year 2000 issues relating to its systems and equipment. The Company's goal is to ensure that all components and services that in any material manner contribute to operational reliability, customer relations, safety, revenue and regulatory compliance will be suitable for continued use beyond December 31, 1999, in some cases with appropriate work- arounds or contingency plans. The Company understands that many variables outside the control of the Company may have an adverse affect on the ability of the Company to perform its mission critical processes (e.g.,telecommunication providers may not be able to provide uninterrupted service). Therefore, the Company is developing contingency plans for all mission critical processes in an effort to mitigate these risks. Contingency plans will be developed and tested for all mission critical processes by the end of the second quarter of 1999. The Company continues to review its operations and its critical external suppliers and service providers in order to determine any worst-case scenarios it could face as a result of Year 2000 problems.
Costs. The estimated total cost of implementing the Company's Year 2000 plan is approximately $49 million, which includes costs related to total system replacements (the Year 2000 solution comprises only a portion of the benefit resulting from such replacements). These costs to date, primarily incurred as a result of software and system changes and upgrades by Duquesne, have been approximately $39 million. Of this amount, approximately $35 million represents capital costs attributable to the licensing and installation of new software for total system replacements. The remaining $4 million has been expensed as incurred. Funds for the Company's Year 2000 plan have come from the Company's operating and capital budgets. Approximately $10 million has been budgeted for 1999 to address Year 2000 issues. The Company does not anticipate that Year 2000 issues and related costs will be material to the Company's operations, financial condition and results of operations.
The foregoing paragraphs contain forward-looking statements regarding the timetable, effectiveness and ultimate cost of the Company's Year 2000 strategy. Actual results could materially differ from those implied by such statements due to known and unknown risks and uncertainties, including, but not limited to: the possibility that changes and upgrades are not timely completed, that corrections to the systems of other companies on which the Company's systems rely may not be timely completed, and that such changes and upgrades may be incompatible with the Company's systems; the availability and cost of trained personnel; and the ability to locate and correct all relevant computer code and microprocessors.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Market risk represents the risk of financial loss that may impact the Company's consolidated financial position, results of operations or cash flows due to adverse changes in market prices and rates.
Funding for nuclear decommissioning costs is deposited by the Company in external, segregated trust accounts and invested in a portfolio of corporate common stock and debt securities, municipal bonds, certificates of deposit and United States government securities. The market value of the aggregate trust fund balances at December 31, 1998 totaled approximately $62.7 million. The amount funded into the trusts is based on estimated returns which, if not achieved as projected, could require additional unanticipated funding requirements.
Item 8.
Item 8. Consolidated Financial Statements and Supplementary Data.
Report of Independent Certified Public Accountants - --------------------------------------------------------------------------------
To the Directors and Shareholders of DQE, Inc.:
We have audited the accompanying consolidated balance sheets of DQE, Inc. and its subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1998. Our audits also included the financial statement schedule listed in the Index at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and signicant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DQE, Inc. and its subsidiaries as of 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. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth herein.
/s/ Deloitte & Touche LLP Pittsburgh, Pennsylvania January 26, 1999
Statement of Consolidated Income - --------------------------------------------------------------------------------
See notes to consolidated financial statements.
Consolidated Balance Sheet - --------------------------------------------------------------------------------
See notes to consolidated financial statements.
See notes to consolidated financial statements.
Statement of Consolidated Cash Flows - --------------------------------------------------------------------------------
See notes to consolidated financial statements.
Statement of Consolidated Comprehensive Income - --------------------------------------------------------------------------------
See notes to consolidated financial statements.
Statement of Consolidated Retained Earnings - --------------------------------------------------------------------------------
See notes to consolidated financial statements.
Notes to Consolidated Financial Statements
A. Summary of Significant Accounting Policies
Consolidation
DQE, Inc. (DQE) is a multi-utility delivery and services company. Its subsidiaries are Duquesne Light Company (Duquesne); AquaSource, Inc. (AquaSource); DQE Energy Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); Duquesne Enterprises, Inc. (DE); and Montauk, Inc. (Montauk). DQE and its subsidiaries are collectively referred to as "the Company."
The Company's utility operations include an electric utility engaged in the generation, transmission, distribution and sale of electric energy and a water resource management company that acquires, develops and manages water and wastewater utilities. The Company's expanded business lines offer a wide range of energy-related technologies, industrial and commercial energy services, telecommunications and other complementary services. The expanded business lines' initiatives include energy facility development and operation, domestic and international independent power production, the production and supply of innovative fuels, investments in communications systems (including long-distance telephone service) and electronic commerce. In addition, one of the Company's subsidiaries is a financial services company that makes long-term investments and provides financing for the other expanded business lines and related customers.
On December 18, 1998, the Pennsylvania Public Utility Commission (PUC) approved the Company's plan to divest itself of its generation assets through an auction (including an auction of its provider of last resort service), and an agreement in principle to exchange certain power stations with FirstEnergy Corporation (FirstEnergy). Final agreements governing these transactions must be approved by various regulatory agencies. The Company currently expects these transactions to close in late 1999 or early 2000. (See "Rate Matters" discussion, Note F, on page 34.)
Basis of Accounting
The Company is subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). In addition, the Company's electric utility operations are subject to regulation by the PUC, including regulation under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Customer Choice Act), and the Federal Energy Regulatory Commission (FERC) under the Federal Power Act with respect to rates for interstate sales, transmission of electric power, accounting and other matters.
As a result of the PUC's final order regarding the Company's restructuring plan under the Customer Choice Act (see "Rate Matters," Note F, on page 34), the electricity generation portion of the Company's business no longer meets the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Accordingly, application of SFAS No. 71 to this portion of the Company's business has been discontinued and the Company now applies SFAS No. 101, Regulated Enterprises -- Accounting for the Discontinuation of Application of FASB Statement No. 71 (SFAS No. 101) as interpreted by Emerging Issues Task Force 97-4, Deregulation of the Pricing of Electricity -- Issues Related to the Application of FASB Statements No. 71 and 101. Under SFAS No. 101, the regulatory assets and liabilities of the generation portion of the Company are determined on the basis of the source from which the regulated cash flows to realize such regulatory assets and settle such liabilities will be derived. Pursuant to the PUC's final restructuring order, certain of the Company's generation-related regulatory assets will be recovered through a competitive transition charge (CTC) collected in connection with providing transmission and distribution services (the electricity delivery business segment). The Company will continue to apply SFAS No. 71 with respect to such assets. Fixed assets related to the generation portion of the Company's business have been evaluated in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of (SFAS No. 121). Applying SFAS No. 121 to the non- regulated generation assets, it has been determined that the Company's generation assets are impaired. However, pursuant to the PUC's final restructuring order, the Company will recover its above-market investment in generation assets through the CTC. Under the Company's plan to auction its generation assets, the market value utilized by the PUC in determining the value of the generation assets will be the net after-tax proceeds received from the auction. Accordingly, the amount of book value authorized by the PUC to be recovered has been reclassified on the consolidated balance sheet from property, plant and equipment to transition costs, until the auction has been completed and all approvals for the final CTC accounting have been granted. The electricity delivery business segment continues to meet SFAS No. 71 criteria and accordingly reflects regulatory assets and liabilities consistent with cost- based ratemaking regulations. The regulatory assets represent probable future revenue to the Company, because provisions for these costs are currently included, or are expected to be included, in charges to electric utility customers through the ratemaking process. (See "Rate Matters," Note F, on page 34.)
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities, at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results could differ from those estimates.
Energy Cost Rate Adjustment Clause (ECR)
Through the ECR, the Company previously recovered (to the extent that such amounts were not included in base rates) nuclear fuel, fossil fuel and purchased power expenses. Also through the ECR, the Company passed to its customers the profits from short-term power sales to other utilities (collectively, ECR energy costs). As a consequence of the PUC's final order regarding the Company's restructuring plan (see "Rate Matters," Note F, on page 34), such fuel costs are no longer recoverable through the ECR. Instead, effective May 29, 1998 (the date of the PUC's final restructuring order), fuel costs are expensed as incurred and thus impact net income.
Under-recoveries from customers prior to May 29, 1998, were recorded on the consolidated balance sheet as a regulatory asset. At December 31, 1998, $42.7 million was receivable from customers. The Company expects to recover this amount through the CTC. (See "Restructuring Plan" discussion, Note F, on page 35.) At December 31, 1997, $23.5 million was receivable from customers.
Revenues from Utility Sales
The Company's electric utility operations provide service to customers in the City of Pittsburgh and surrounding areas. (See "Rate Matters," Note F, on page 34.) This territory represents approximately 800 square miles in southwestern Pennsylvania. The population of the area served by the Company's electric utility operations, based on 1990 census data, is approximately 1,510,000, of whom 370,000 reside in the City of Pittsburgh. In addition to serving approximately 580,000 direct customers, the Company's utility operations also sell electricity to other utilities.
The Company's water utility operations provide service to customers throughout the United States. The Company's water operations have grown rapidly and are currently approaching 300,000 customer connections.
Meters are read monthly and utility customers are billed on the same basis. Revenues are recorded in the accounting periods for which they are billed, with the exception of energy cost recovery revenues. (See "Energy Cost Rate Adjustment Clause" discussion on page 30.)
Maintenance
Effective January 1, 1999, as a result of the PUC's final restructuring order, all electric utility maintenance costs will be expensed as incurred. Historically, incremental maintenance costs incurred for refueling outages at the Company's nuclear units were deferred for amortization over the period between refueling outages (generally 18 months); the Company would accrue, over the periods between outages, anticipated costs for scheduled major fossil generating station outages. Maintenance costs incurred for non-major scheduled outages and for forced outages were charged to expense as such costs were incurred. During the fourth quarter of 1998, a reversal of the fossil maintenance outage accrual was made for outages planned to occur after the divestiture of the generation assets.
Depreciation and Amortization
Depreciation of property, plant and equipment, including plant-related intangibles, is recorded on a straight-line basis over the estimated remaining useful lives of properties. Goodwill, representing the excess of the cost over the net tangible and identifiable assets of acquired businesses, is stated at cost and is amortized on a straight-line basis over the estimated future periods to be benefited (25 to 40 years). Goodwill is included in other non-current assets on the consolidated balance sheet. In certain regulatory jurisdictions the Company expects to recover its goodwill and to earn a return on those costs through the ratemaking process. Amortization of gas reserve investments and depreciation of related property are on a units of production method over the total estimated gas reserves. Amortization of interests in affordable housing partnerships is based upon a method that approximates the equity method; and amortization of certain other leases is on the basis of benefits recorded over the lives of the investments. Depreciation and amortization of other properties are calculated on various bases.
The Company records nuclear decommissioning costs under the category of depreciation and amortization expense, and accrues a liability, equal to that amount, for nuclear decommissioning expense. On the Company's consolidated balance sheet, the decommissioning trusts have been reflected in other long-term investments, and the related liability has been recorded as other non-current liabilities. Trust fund earnings increase the fund balance and the recorded liability. (See "Nuclear Decommissioning" discussion, Note J, on page 40.)
The Company's electric utility operations' composite depreciation rate increased from 3.5 percent to 4.25 percent effective May 1, 1996. Also in 1996, the Company expensed $9 million related to the depreciation portion of deferred rate synchronization costs in conjunction with the Company's 1996 PUC-approved mitigation plan. As a result of the May 29, 1998, PUC restructuring order, the Company reduced its rate of depreciation on its generation assets, including plant and transition costs, to achieve a net book value as of December 31, 1998, equal to the level approved for recovery as transition costs.
Income Taxes
The Company uses the liability method in computing deferred taxes on all differences between book and tax bases of assets. These book/tax differences occur when events and transactions recognized for financial reporting purposes are not recognized in the same period for tax purposes. The deferred tax liability or asset is also adjusted in the period of enactment for the effect of changes in tax laws or rates.
For its electricity delivery business segment, the Company recognizes a regulatory asset for the deferred tax liabilities that are expected to be recovered from customers through rates. (See "Rate Matters," Note F, and "Income Taxes," Note H, on pages 34 and 38.)
The Company reflects the amortization of the regulatory tax receivable resulting from reversals of deferred taxes as depreciation and amortization expense. Reversals of accumulated deferred income taxes are included in income tax expense.
When applied to reduce the Company's income tax liability, investment tax credits related to the electricity delivery business segment generally are deferred. Such credits are subsequently reflected, over the lives of the related assets, as reductions to income tax expense.
Other Operating Revenues and Other Income
Other operating revenues include the Company's non-kilowatt-hour (KWH) utility revenues and revenues from expanded business lines' operating activities. Other income primarily is made up of income from long-term investments entered into by the expanded business lines. The income is separated from other revenues as the investment income does not result from operating activities.
Property, Plant and Equipment
The asset values of the Company's properties are stated at original construction cost, which includes related payroll taxes, pensions and other fringe benefits, as well as administrative costs. Also included in original construction cost is an allowance for funds used during construction (AFC), which represents the estimated cost of debt and equity funds used to finance construction.
Additions to, and replacements of, property units are charged to plant accounts. Maintenance, repairs and replacement of minor items of property are recorded as expenses when they are incurred. The costs of electricity delivery business segment properties that are retired (plus removal costs and less any salvage value) are charged to accumulated depreciation and amortization.
The asset values of the Company's electricity generation business segment properties were written down to market value in accordance with SFAS No. 121 in conjunction with the final PUC restructuring order. (See "Basis of Accounting" discussion on page 29.)
Substantially all of the Company's electric utility properties are subject to a first mortgage lien.
Temporary Cash Investments
Temporary cash investments are short-term, highly liquid investments with original maturities of three or fewer months. They are stated at market, which approximates cost. The Company considers temporary cash investments to be cash equivalents.
Earnings Per Share
Basic earnings per share is computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock, or resulted in the issuance of common stock that then shared in the earnings of the entity.
The preference stock of the ESOP, as described in Note N, "Employee Benefits," was the primary cause for the dilution of earnings per share for the years ended December 31, 1998, 1997 and 1996 as shown on the statement of consolidated income. Each share of the preference stock is exchangeable for one and one-half shares of DQE common stock. Assuming conversion at the beginning of each year, the number of DQE shares was added to the denominator (weighted- average number of common shares outstanding). Partially offsetting the dilutive effect of the additional shares, the preference stock has an annual dividend rate of $2.80 per share, which was added back to the numerator (income available to common stockholders). The result of calculating both basic and dilutive earnings per share was a $0.02 dilutive effect for 1998, after the Pennsylvania restructuring charge, and a $0.03 dilutive effect for 1997 and 1996.
Stock-Based Compensation
The Company accounts for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount any employee must pay to acquire the stock. Compensation cost for stock appreciation rights is recorded annually, based on the quoted market price of the Company's stock at the end of the period.
Reclassification The 1997 and 1996 consolidated financial statements have been reclassified to conform with 1998 presentation.
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133). This statement establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. The adoption of SFAS No. 133 is not expected to have a significant impact on the Company's financial statements and disclosures.
B. Changes in Working Capital Other than Cash
Changes in Working Capital Other than Cash (Net of Dispositions and Acquisitions) for the Year Ended December 31, - --------------------------------------------------------------------------------
C. Property, Plant and Equipment
In addition to its wholly owned generating units, the Company, together with FirstEnergy, has an ownership or leasehold interest in certain jointly owned units. The Company is required to pay its share of the construction and operating costs of the units. The Company's share of the operating expenses of the units is included in the statement of consolidated income. The Company anticipates divesting itself of its generation assets at the end of 1999 or in early 2000. (See "Rate Matters," Note F, on page 34.)
Generating Units - --------------------------------------------------------------------------------
(a) The units are equipped with flue gas desulfurization equipment. (b) The Nuclear Regulatory Commission (NRC) has granted a license to operate through January 2016. (c) In 1987, the Company sold and leased back its 13.74 percent interest in Beaver Valley Unit 2. (d) The NRC has granted a license to operate through May 2027. (e) The NRC has granted a license to operate through March 2026. (f) Jointly owned with FirstEnergy.
Additionally, the Company has an ownership interest in certain generating units not currently included in electric plant in service on the consolidated balance sheet. The Brunot Island (BI) Units 3 and 4 and the Phillips Power Station (Phillips) will be offered as part of the Company's generation asset auction.
D. Long-Term Investments
The Company makes equity investments in affordable housing and gas reserve partnerships as a limited partner. At December 31, 1998, the Company had investments in 27 affordable housing funds and 29 gas reserve sites. The Company is the lessor in nine leveraged lease arrangements involving mining equipment, rail equipment, fossil generating stations, a waste-to-energy facility, high speed service ferries and natural gas processing equipment. These leases expire in various years beginning in 2004 through 2033. The recorded residual value of the equipment at the end of the lease terms is approximately two percent of the original cost. The Company's aggregate investment represents 20 percent of the aggregate original cost of the property and is either leased to a creditworthy lessee or is secured by guarantees of the lessee's parent or affiliate. The remaining 80 percent was financed by non-recourse debt provided by lenders who have been granted, as their sole remedy in the event of default by the lessees, an assignment of rentals due under the leases and a security interest in the leased property. This debt amounted to $949 million and $950 million at December 31, 1998 and 1997.
The Company's other leases include investments in fossil generating stations, a waste-to-energy facility, computers, vehicles and equipment. The Company's other investments are primarily in assets of nuclear decommissioning trusts and marketable securities. Deferred income primarily relates to the Company's other lease investments and certain gas reserve investments. Deferred amounts will be recognized as income over the lives of the underlying investments for periods generally not exceeding seven years from the time of investment.
E. Acquisitions
In 1997, the Company created the Preferred Stock, Series A (Convertible), $100 liquidation preference per share (DQE Preferred Stock), to issue as consideration in lieu of cash in connection with acquisitions by the Company of other businesses, assets or securities. (See "Preferred and Preference Stock," Note L, on page 44.) Through December 31, 1998, the Company had invested approximately $166 million (of which approximately $35 million was in the form of DQE Preferred Stock) to acquire the stock or assets of water and water- related companies. The Company also invested $22 million to acquire a 50 percent interest in and finance the growth of Control Solutions, LLC, a commercial and industrial heating, ventilation and air conditioning service and energy controls company.
F. Rate Matters
Competition and the Customer Choice Act
The electric utility industry continues to undergo fundamental change in response to development of open transmission access and increased availability of energy alternatives. Under historical ratemaking practice, regulated electric utilities were granted exclusive geographic franchises to sell electricity, in exchange for making investments and incurring obligations to serve customers under the then-existing regulatory framework. Through the ratemaking process, those prudently incurred costs were recovered from customers, along with a return on the investment. Additionally, certain operating costs were approved for deferral for future recovery from customers (regulatory assets). As a result of this historical ratemaking process, utilities had assets recorded on their balance sheets at above-market costs, thus creating transition and stranded costs.
In Pennsylvania, the Customer Choice Act went into effect on January 1, 1997. The Customer Choice Act enables Pennsylvania's electric utility customers to purchase electricity at market prices from a variety of electric generation suppliers (customer choice). Although the Customer Choice Act will give customers their choice of electric generation suppliers, the existing, franchised local distribution utility is still responsible for delivering electricity from the generation supplier to the customer. The local distribution utility is also required to serve as the provider of last resort for all customers in its service territory, unless other arrangements are approved by the PUC. The provider of last resort must provide electricity for any customer who cannot or does not choose an alternative electric generation supplier, or whose supplier fails to deliver. The Customer Choice Act provides that the existing franchised utility may recover, through a CTC, an amount of transition costs that are determined by the PUC to be just and reasonable. Pennsylvania's electric utility restructuring is being accomplished through a two-stage process consisting of an initial customer choice pilot period (which ended in December 1998) and a phase-in to competition period (which began in January 1999). The Company's estimated negative net income impact of the customer choice pilot program during 1998, with five percent of customers participating, was approximately $6 million.
Phase-In to Competition
The phase-in to competition began in January 1999, when 66 percent of customers became eligible to participate in customer choice (including customers covered by the pilot program); all customers will have customer choice in January 2000. As of February 28, 1999, approximately 12.5 percent of the Company's customers had chosen alternative generation suppliers. Customers that have chosen an electricity generation supplier other than the Company pay that supplier for generation charges, and pay the Company a CTC (discussed below) and charges for transmission and distribution. Customers that continue to buy their generation from the Company pay for their service at current regulated tariff rates divided into generation, transmission and distribution
charges. Under the Customer Choice Act, an electric distribution company, such as Duquesne, remains a regulated utility and may only offer PUC-approved rates, including generation rates. Also under the Customer Choice Act, electricity delivery (including transmission, distribution and customer service) remains regulated in substantially the same manner as under current regulation.
In an effort to "jump start" retail competition, the Company has made 600 megawatts (MW) of power available to licensed electric generation suppliers, to be used in supplying electricity to Duquesne's customers who have chosen alternative generation suppliers. The power will be available for the first six months of 1999 at a price of 2.6 cents per kilowatt-hour (KWH). This power availability will be structured to ensure the power is used to benefit Duquesne's retail customers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, has been imposed on the transmission and distribution charges of Pennsylvania electric utility companies under the Customer Choice Act. Additionally, electric utility companies may not increase the generation price component of rates as long as transition costs are being recovered, with certain exceptions.
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that the Company should recover most of the above-market costs of the generation assets, including plant and regulatory assets through the collection of the CTC from electric utility customers. The total of the transition costs to be recovered is $2,133 million ($1,485 million, net of tax) over a seven-year period beginning January 1, 1999, as may be adjusted to account for the proceeds of the generation asset auction. In addition, the transition costs as reflected on the consolidated balance sheet will be amortized over the same period that the CTC revenues are being recognized. The Company will earn an 11 percent pre-tax return on the unrecovered balance.
In the second quarter of 1998, the Company recorded the Pennsylvania restructuring charge against earnings of $142.3 million ($82.5 million, net of tax) for the generation-related stranded costs not considered by the PUC's restructuring order to be recoverable from customers. The Pennsylvania restructuring charge included Phillips, BI, deferred caretaker costs related to the two stations and deferred coal costs. The charge resulted in a reduction of Duquesne's contribution to the Company's earnings per share by $1.06. The following table sets forth the amounts reclassified from regulatory assets and property, plant, and equipment to transition costs.
Other Non-Current Assets as of December 31, - --------------------------------------------------------------------------------
(a) Amount represents the above-market costs of the power plants and was reclassified in the second quarter of 1998 from property, plant, and equipment to transition costs. A final determination of plant market value will be determined in conjunction with the generation auction. (b) Amount represents deferred taxes related to the taxable gain on the sale/leaseback of Beaver Valley Unit 2 and was reclassified from deferred tax liabilities to transition costs. (c) In the second quarter of 1998 amounts were written off as an extraordinary charge to the consolidated statement of income as part of the Pennsylvania restructuring charge. (d) Amounts reflected in transition costs include reclassifications from other non-current assets and other non-current liabilities. In addition, there are amounts included in transition costs that had not previously been recorded on the consolidated balance sheet but were determined in the final PUC restructuring order to be costs recoverable from customers through the CTC. In the case of amounts not recorded, a regulatory liability was recorded for the same amount as the transition costs.
As part of its restructuring plan filing, the Company requested recovery of $11.5 million ($6.7 million, net of tax) through the CTC for energy costs previously deferred under the ECR. Recovery of this amount was approved in the PUC's final restructuring order. The Company also requested recovery of an additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On December 18, 1998, the PUC denied recovery of this additional amount. The Company has appealed the PUC's denial of recovery to the Pennsylvania Commonwealth Court. Based upon the Customer Choice Act, which mandates recovery of all regulatory assets, and the PUC's specific authorization for the Company to create a regulatory asset for these costs, the Company believes that it is probable that these costs will be recovered through retail rates. In the event that the Company does not prevail in its appeal, these costs would be written off as a charge against income during 1999.
Restructuring Plan and Auction Plan. With respect to transition cost recovery, the PUC's final order on the restructuring plan approved Duquesne's proposal to auction its generation assets and use the proceeds to offset transition costs. The remaining balance of such costs (with certain exceptions described below) will be recovered from ratepayers through a CTC, collectible through 2005. Until the divestiture is complete, Duquesne has been ordered to use an interim system average CTC and price to compare based on the methodology approved in its pilot program (approximately 2.9 cents per KWH for the CTC and approximately 3.8 cents per KWH for the price to compare).
On December 18, 1998, the PUC approved Duquesne's auction plan, including an auction of its provider of last resort service, as well as an agreement in principle to exchange certain generation assets with FirstEnergy. The assets to be auctioned will include Duquesne's wholly owned Cheswick Power Station, Elrama Power Station, Phillips and BI, as well as the stations to be received from FirstEnergy in the power station exchange described below. The auction plan calls for a two-phase, sealed bid process similar to that used in other power plant divestitures. The initial confidential bidding process is expected to begin in the spring of 1999, with potential buyers identified by Duquesne being asked to submit non-binding bids. Final agreements governing the transactions must be approved by various regulatory agencies, including the PUC, the FERC, the NRC, the Department of Justice and/or the Federal Trade Commission. Duquesne currently expects the sale to close at the end of 1999 or the beginning of 2000.
Power Station Exchange. Pursuant to the definitive agreements entered into on March 25, 1999 (which remain subject to regulatory approval), Duquesne and FirstEnergy will exchange ownership interests in certain power stations. Duquesne will receive 100 percent ownership rights in three coal-fired power plants located in Avon Lake and Niles, Ohio and New Castle, Pennsylvania (totaling approximately 1,300 MW), which the Company expects to sell simultaneously as part of the auction of generation assets. FirstEnergy will acquire Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield Units 1, 2 and 3 (totaling approximately 1,400 MW). In connection with the power station exchange, the Company anticipates terminating the BV Unit 2 lease. (See "Leases," Note I, on page 39.) Pursuant to the December 18, 1998, PUC order and subject to final approval, the proceeds from the sale of the power stations received in the exchange will be used to offset the transition costs associated with Duquesne's currently-held generation assets and costs associated with completing the exchange. Duquesne expects this exchange to enhance the value received from the auction, because participants will bid on plants that are wholly owned by Duquesne, rather than plants that are jointly owned and/or operated by another entity. Additionally, the auction will include only coal- and oil-fired plants, which are anticipated to have a higher market value than nuclear plants. These value-enhancing features, along with a minimum level of auction proceeds guaranteed by FirstEnergy, are expected to maximize auction proceeds, minimize transition costs required to be recovered through the CTC (by shortening the length of the CTC recovery period), and thus reduce customer bills as rapidly as possible. Other benefits of this exchange include the resolution of all joint ownership issues, and other risks and costs associated with the jointly-owned units. Although the PUC has said the exchange appears to be in the public interest, the definitive exchange agreement must be submitted for PUC approval, and certain aspects of the exchange will have to be approved by, among other agencies, the FERC, the NRC and the Department of Justice. The power station exchange is expected to occur simultaneously with the anticipated closing of the sale of Duquesne's generation through the auction at the end of 1999 or in early 2000.
Termination of the AYE Merger
On July 28, 1998, DQE's board of directors concluded that it could not consummate the merger with AYE, toward which the Company had been working. The Company believes that AYE suffered a material adverse effect as a result of the PUC's final restructuring order regarding AYE's utility subsidiary, West Penn Power Company. More information regarding this decision is set forth in the Company's Current Report on Form 8-K dated July 28, 1998. On July 30, 1998, AYE informed DQE that it would continue to work toward consummation of the merger, and also pursue all remedies available to protect the legal and financial interests of AYE and its shareholders.
On September 17, 1998, the PUC issued an order stating that, unless the parties jointly agreed to an extension of time to consummate the merger beyond October 5, 1998 (the relevant date under the merger agreement), their merger application with the PUC would be considered withdrawn. On October 5, 1998, the Company announced its unilateral termination of the merger agreement. More information regarding this termination is set forth in the Company's Current Report on Form 8-K dated October 5, 1998. In a letter dated February 24, 1999, the PUC informed the Company that the merger application was deemed withdrawn and the docket was closed.
AYE filed suit in the United States District Court for the Western District of Pennsylvania, seeking to compel the Company to proceed with the merger and seeking a temporary restraining order and preliminary injunction to prevent the Company from certain actions pending a trial, or in the alternative seeking an unspecified amount of money damages. On October 28, 1998, the judge denied AYE's motion for the temporary restraining order and preliminary injunction. AYE appealed to the United States Court of Appeals for the Third Circuit, asking for an injunction pending the appeal and expedited treatment of the appeal. On November 6, 1998, the Third Circuit denied the motion for an injunction and granted the motion to expedite the appeal.
On March 11, 1999, the Third Circuit vacated the October 28 denial of a preliminary injunction. The Third Circuit remanded the case to the District Court for further proceedings to address certain issues, including whether AYE could demonstrate a reasonable likelihood of success on the merits, before determining whether any injunctive relief is warranted. On March 12, 1999, AYE filed a motion for a temporary restraining order with the district court, and a hearing was held that same day. On March 16, 1999, AYE and DQE entered into a consent agreement, which was approved by the district court on March 18. Pursuant to the consent agreement, AYE and DQE have agreed, among other things, that pending the consolidated hearing on AYE's application for a preliminary injunction and/or an expedited trial on the merits, both parties will give each other 10 business days' notice before taking or omitting to take any action which would prevent the merger from qualifying for "pooling of interests" accounting treatment. This would not prevent either party from entering into any agreement, but would require the 10 business days' notice prior to closing any transaction which prevents pooling. The consent agreement shall terminate on September 16, 1999, unless earlier terminated or extended by mutual agreement or an order of the district court.
The Company continues to believe that AYE's claim is entirely without merit in light of the $1 billion disallowance of its stranded costs, which constituted a material adverse effect under the merger agreement and entitled the Company to terminate it as of October 5, 1998. The Company will continue to defend itself vigorously against AYE's claims and intends to pursue a prompt resolution of the litigation. On March 25, 1999, the Company petitioned the Third Circuit for rehearing. In the interim, the Company intends to continue to pursue the implementation of customer choice under its PUC-approved restructuring plan, including the power station exchange with FirstEnergy and the generation exchange auction. The ultimate outcome of this suit cannot be determined at this time.
G. Short-Term Borrowing and Revolving Credit Arrangements
At December 31, 1998, the Company had two extendible revolving credit arrangements, including a $125 million facility expiring in June 1999 and a $150 million facility expiring in October 1999. Interest rates can, in accordance with the option selected at the time of the borrowing, be based on prime, Eurodollar or certificate of deposit rates. Commitment fees are based on the unborrowed amount of the commitments. Both credit facilities contain two-year repayment periods for any amounts outstanding at the expiration of the revolving credit periods. At December 31, 1998 and December 31, 1997, there were no short- term borrowings outstanding.
H. Income Taxes
The annual federal corporate income tax returns have been audited by the Internal Revenue Service (IRS) for the tax years through 1992. The IRS is reviewing the 1993 and 1994 returns, and the tax years 1995, 1996, 1997 and 1998 remain subject to IRS review. The Company does not believe that final settlement of the federal income tax returns for the years 1990 through 1998 will have a materially adverse effect on its financial position, results of operations or cash flows.
Deferred Tax Assets (Liabilities) as of December 31, - --------------------------------------------------------------------------------
Income Taxes - --------------------------------------------------------------------------------
Total income taxes differ from the amount computed by applying the statutory federal income tax rate to income before income taxes.
Income Tax Expense Reconciliation - --------------------------------------------------------------------------------
I. Leases
The Company leases nuclear fuel, a portion of a nuclear generating plant, certain office buildings, computer equipment, and other property and equipment.
Capital Leases as of December 31, - --------------------------------------------------------------------------------
(a) Includes $2,037 in 1998 and $2,874 in 1997 of capital leases with associated obligations retired.
In 1987, the Company sold and leased back its 13.74 percent interest in BV Unit 2; the sale was exclusive of transmission and common facilities. The Company subsequently leased back its interest in the unit for a term of 29.5 years. The lease provides for semi-annual payments and was accounted for as an operating lease. In conjunction with the PUC restructuring order, it was determined that the costs related to the lease were transition costs to be recovered through the CTC. The Company recorded the lease liability and a corresponding regulatory asset for the present value of the future lease payments. The Company is responsible under the terms of the lease for all costs related to its interest in the unit. In December 1992, the Company participated in the refinancing of collateralized lease bonds to take advantage of lower interest rates, thus reducing the annual lease payments. The bonds were originally issued in 1987 to partially fund the lease of BV Unit 2. The associated letter of credit securing the lessor's equity interest in the unit is $194 million and the term of the letter of credit extends to 1999. The Company currently anticipates terminating the lease in connection with the power station exchange with FirstEnergy, in which case the lease liability recorded on the consolidated balance sheet would no longer be an obligation of the Company. The underlying collateralized lease bonds ($371.0 million at December 31, 1998) would become direct obligations of the Company and be recorded as debt on the consolidated balance sheet. (See "Rate Matters," Note F, on page 34.)
Leased nuclear fuel is amortized as the fuel is burned and charged to fuel and purchased power expense on the statement of consolidated income. The amortization of all other leased property is based on rental payments made (except the BV Unit 2 lease). These lease-related expenses are charged to operating expenses on the statement of consolidated income.
Summary of Rental Payments - --------------------------------------------------------------------------------
Future Minimum Lease Payments - --------------------------------------------------------------------------------
(a) Includes current obligations of $21.1 million at December 31, 1998.
Future minimum lease payments for operating leases are related principally to certain corporate offices. Future minimum lease payments for capital leases are related principally to the estimated use of nuclear fuel financed through leasing arrangements expiring in 1999 and building leases.
Future payments due to the Company, as of December 31, 1998, under subleases of certain corporate office space are approximately $6.0 million in 1999, $6.0 million in 2000 and $12.7 million thereafter.
J. Commitments and Contingencies
The Company anticipates divesting itself of its generation assets through the auction and the power station exchange by early 2000 and, depending on the regulatory approvals of the final agreements regarding the divestiture, expects certain obligations related to the divested assets will be transferred to the future owners. (See "Restructuring Plan" discussion, Note F, on page 35.)
Construction, Investments and Acquisitions
The Company estimates that it will spend, excluding AFC and nuclear fuel, approximately $110 million in 1999 (including $30 million for generation), $75 million in 2000 (excluding generation) and $70 million in 2001 (excluding generation) for electric utility construction.
Nuclear-Related Matters
The Company has an interest in three nuclear units, two of which it operates. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Specific information about risk management and potential liabilities is discussed below.
Nuclear Decommissioning. The Company expects to decommission BV Unit 1, BV Unit 2 and Perry Unit 1 no earlier than the expiration of each plant's operating license in 2016, 2027 and 2026, respectively. At the end of its operating life, BV Unit 1 may be placed in safe storage until BV Unit 2 is ready to be decommissioned, at which time the units may be decommissioned together.
Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit 2, and a 1997 update of the 1994 study for Perry Unit 1, the Company's approximate share of the total estimated decommissioning costs, including removal and decontamination costs, is $170 million, $55 million and $90 million, respectively. The amount currently used to determine the Company's cost of service related to decommissioning all three nuclear units is $224 million.
Funding for nuclear decommissioning costs is deposited in external, segregated trust accounts and invested in a portfolio of corporate common stock and debt securities, municipal bonds, certificates of deposit and United States government securities. The market value of the aggregate trust fund balances at December 31, 1998, totaled approximately $62.7 million.
As part of the power station exchange, FirstEnergy has agreed to assume the decommissioning liability for each of the nuclear plants in exchange for the balance in the decommissioning trust funds, plus the decommissioning costs expected to be collected through the CTC.
Nuclear Insurance. The Price-Anderson Amendments to the Atomic Energy Act of 1954 limit public liability from a single incident at a nuclear plant to $9.8 billion. The maximum available private primary insurance of $200 million has been purchased by the Company. Additional protection of $9.6 billion would be provided by an assessment of up to $88.1 million per incident on each licensed nuclear unit in the United States. The Company's maximum total possible assessment, $66.1 million, which is based on its ownership or leasehold interests in three nuclear generating units, would be limited to a maximum of $7.5 million per incident per year. This assessment is subject to indexing for inflation and may be subject to state premium taxes. If assessments from the nuclear industry prove insufficient to pay claims, the United States Congress could impose other revenue-raising measures on the industry.
The Company's share of insurance coverage for property damage, decommissioning and decontamination liability is $1.2 billion. The Company would be responsible for its share of any damages in excess of insurance coverage. In addition, if the property damage reserves of Nuclear Electric Insurance Limited (NEIL), an industry mutual insurance company that provides a portion of this coverage, are inadequate to cover claims arising from an incident at any United States nuclear site covered by that insurer, the Company could be assessed retrospective premiums totaling a maximum of $7.3 million.
In addition, the Company participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Subject to the policy deductible, terms and limit, the coverage provides for a weekly indemnity of the estimated incremental costs during the three-year period starting 17 weeks after an accident, with no coverage thereafter. If NEIL's losses for this program ever exceed its reserves, the Company could be assessed retrospective premiums totaling a maximum of $2.6 million.
Beaver Valley Power Station (BVPS). BVPS's two units are equipped with steam generators designed and built by Westinghouse Electric Corporation (Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter stress corrosion cracking (ODSCC) has occurred in the steam generator tubes of both units. BV Unit 1, which was placed in service in 1976, has removed approximately 17 percent of its steam generator tubes from service through a process called "plugging." However, BV Unit 1 still has the capability to operate at 100 percent reactor power and has the ability to return tubes to service by repairing them through a process called "sleeving." No tubes at either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was placed in service 11 years after BV Unit 1, has not yet exhibited the degree of ODSCC experienced at BV Unit 1. Approximately 3 percent of BV Unit 2's tubes are plugged; however, it is too early in the life of the unit to determine the extent to which ODSCC may become a problem at that unit.
The Company has undertaken certain measures, such as increased inspections, water chemistry control and tube plugging, to minimize the operational impact of and reduce susceptibility to ODSCC. Although the Company has taken these steps to allay the effects of ODSCC, the inherent potential for future ODSCC in steam generator tubes of the Westinghouse design still exists. Material acceleration in the rate of ODSCC could lead to a loss of plant efficiency, significant repairs or the possible replacement of the BV Unit 1 steam generators. The total replacement cost of the BV Unit 1 steam generators is currently estimated at $125 million. The Company would be responsible for $59 million of this total, which includes the cost of equipment removal and replacement steam generators, but excludes replacement power costs. The earliest that the BV Unit 1 steam generators could be replaced during a currently scheduled refueling outage is the fall of 2001.
The Company continues to explore all viable means of managing ODSCC, including new repair technologies, and plans to continue to perform 100 percent tube inspections during future refueling outages. However, the Company may be required to perform an earlier inspection of BV Unit 1's tubes and other equipment during a mid-cycle outage in 1999, to comply with NRC requirements to conduct such inspections at BV Unit 1 at least every 20 months. The Company has requested permission from the NRC to postpone these inspections until BV Unit 1's next refueling outage, currently scheduled to begin in the spring of 2000. The Company completed its inspection of BV Unit 2's tubes during a forced outage in 1998 to comply with NRC requirements to conduct such inspections at BV Unit 2 at least every 24 months. The next refueling outage for BV Unit 2 is currently scheduled to begin at the end of February 1999. No steam generator tube inspections will be performed until the subsequent refueling outage, currently scheduled for the fall of 2000. The Company will continue to monitor and evaluate the condition of the BVPS steam generators.
BV Unit 1 went off-line on January 30, 1998, due to an issue identified in a technical review completed by the Company. BV Unit 2 went off-line on December 16, 1997, to repair the emergency air supply system to the control room. BV Unit 2 remained off-line due to other issues identified by a technical review, similar to that performed at BV Unit 1. These technical reviews, held in response to a 1997 commitment made by the Company to the NRC, have been completed. The Company was one of many utilities faced with similar issues, some of which date back to the initial start-up of BVPS. BV Unit 1 returned to service on August 15, 1998, and BV Unit 2 returned to service on September 28, 1998.
Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982 established a federal policy for handling and disposing of spent nuclear fuel and a policy requiring the establishment of a final repository to accept spent nuclear fuel. Electric utility companies have entered into contracts with the United States Department of Energy (DOE) for the permanent disposal of spent nuclear fuel and high-level radioactive waste in compliance with this legislation. The DOE has indicated that its repository under these contracts will not be available for acceptance of spent nuclear fuel before 2010. The DOE has not yet established an interim or permanent storage facility, despite a ruling by the United States Court of Appeals for the District of Columbia Circuit that the DOE was legally obligated to begin acceptance of spent nuclear fuel for disposal by January 31, 1998. Existing on-site spent nuclear fuel storage capacities at BV Unit 1, BV Unit 2 and Perry Unit 1 are expected to be sufficient until 2018, 2012 and 2011, respectively.
In early 1997, the Company joined 35 other electric utilities and 46 states, state agencies and regulatory commissions in filing suit in the United States Court of Appeals for the District of Columbia Circuit against the DOE. The parties requested the court to suspend the utilities' payments into the Nuclear Waste Fund and to place future payments into an escrow account until the DOE fulfills its obligation to accept spent nuclear fuel. The DOE had requested that the court delay litigation while it pursued alternative dispute resolution under the terms of its contracts with the utilities. The court ruling, issued November 14, 1997, and affirmed on rehearing May 5, 1998, denied the relief requested by the utilities and states and permitted the DOE to pursue alternative dispute resolution, but prohibited the DOE from using its lack of a spent fuel repository as a defense. The United States Supreme Court declined to review the decision. The utilities' remaining remedy is to sue the DOE in federal court for money damages caused by the DOE's delay in fulfilling its obligations.
Uranium Enrichment Obligations. Nuclear reactor licensees in the United States are assessed annually for the decontamination and decommissioning of DOE uranium enrichment facilities. Assessments are based on the amount of uranium a utility had processed for enrichment prior to enactment of the National Energy Policy Act of 1992, and are to be paid by such utilities over a 15-year period. At December 31, 1998, the Company's liability for contributions was approximately $6.2 million (subject to an inflation adjustment), which will be recovered through the CTC as part of transition costs.
Fossil Decommissioning
Based on studies conducted in 1997, the amount for fossil decommissioning is currently estimated to be $130 million for the Company's interest in 17 units at six sites. Each unit is expected to be decommissioned upon the cessation of the unit's final operations. The Company was not permitted to recover these costs as part of its restructuring plan. (See "Rate Matters," Note F, on page 34.)
Guarantees
The Company and the other owners of Bruce Mansfield Power Station (Bruce Mansfield) have guaranteed certain debt and lease obligations related to a coal supply contract for Bruce Mansfield. At December 31, 1998, the Company's share of these guarantees was $10.4 million.
As part of the Company's investment portfolio in affordable housing, the Company has received fees in exchange for guaranteeing a minimum defined yield to third-party investors. A portion of the fees received has been deferred to absorb any required payments with respect to these transactions. Based on an evaluation of and recent experience with the underlying housing projects, the Company believes that such deferrals are ample for this purpose.
Residual Waste Management Regulations
In 1992, the Pennsylvania Department of Environmental Protection (DEP) issued Residual Waste Management Regulations governing the generation and management of non-hazardous residual waste, such as coal ash. The Company is assessing the sites it utilizes and has developed compliance strategies that are currently under review by the DEP. Based on information currently available, $4.5 million will be spent in 1999 to comply with these DEP regulations. The additional capital cost of compliance is estimated, based on current information, to be approximately $4.8 million per year for the next three years. This estimate is subject to the results of groundwater assessments and DEP final approval of compliance plans.
Employees
Duquesne is party to a labor contract expiring in September 2001 with the International Brotherhood of Electrical Workers (IBEW), which represents approximately 2,000 of Duquesne's employees. The contract provides, among other things, employment security, income protection and 3 percent annual wage increases through September 2000. Duquesne and the IBEW have agreed on a package of additional benefits and protections for union employees affected by the divestiture of generation assets. Any buyer of generation assets currently owned by Duquesne will be required to offer work to current IBEW employees on a seniority basis, recognize the IBEW as the exclusive bargaining representative, establish comparable employee benefit plans, and assume the current labor contract.
In connection with the anticipated divestiture, Duquesne has developed early retirement programs and enhanced separation packages available for eligible IBEW and management employees. Duquesne expects to recover related costs through the divestiture proceeds.
Other
The Company is involved in various other legal proceedings and environmental matters. The Company believes that such proceedings and matters, in total, will not have a materially adverse effect on its financial position, results of operations or cash flows.
K. Long-Term Debt
The pollution control notes arise from the sale of bonds by public authorities for the purposes of financing construction of pollution control facilities at the Company's plants or refunding previously issued bonds. The Company is obligated to pay the principal and interest on these bonds. For certain of the pollution control notes, there is an annual commitment fee for an irrevocable letter of credit. Under certain circumstances, the letter of credit is available for the payment of interest on, or redemption of, all or a portion of the notes.
Long-Term Debt as of December 31, - --------------------------------------------------------------------------------
(a) Excludes $75.0 million related to current maturities during 1999. (b) Excludes $75.0 million related to current maturities during 1998. (c) The pollution control notes have adjustable interest rates. The interest rates at year-end averaged 3.9 percent in 1998 and 3.9 percent in 1997. (d) Term notes have variable rates, adjusted quarterly. The interest rate at December 31, 1998, was 5.5 percent.
At December 31, 1998, sinking fund requirements and maturities of long-term debt outstanding for the next five years were $82.4 million in 1999, $167.1 million in 2000, $86.3 million in 2001, $1.2 million in 2002, and $101.1 million in 2003.
Total interest and other charges were $110.2 million in 1998, $115.6 million in 1997, and $110.3 million in 1996. Interest costs attributable to long-term debt and other interest were $95.6 million, $101.2 million and $99.4 million in 1998, 1997 and 1996, respectively. Of these amounts, $2.2 million in 1998, $2.3 million in 1997 and $1.2 million in 1996 was capitalized as AFC. Debt discount or premium and related issuance expenses are amortized over the lives of the applicable issues.
At December 31, 1998, the fair value of the Company's long-term debt, including current maturities and sinking fund requirements, estimated on the basis of quoted market prices for the same or similar issues or current rates offered to the Company for debt of the same remaining maturities, was $1,467.6 million. The principal amount included in the Company's consolidated balance sheet is $1,443.3 million.
At December 31, 1998 and 1997, the Company was in compliance with all of its debt covenants.
L. Preferred and Preference Stock
Preferred and Preference Stock as of December 31, - --------------------------------------------------------------------------------
(a) Preferred Stock: 4,000,000 authorized shares; no par value; Convertible; $100 liquidation preference per share (b) Preferred stock: 4,000,000 authorized shares; $50 par value; cumulative; $50 per share involuntary liquidation value (c) Non-redeemable (d) 500 authorized shares; $300,000 par value; involuntary liquidation value $300,000 per share; mandatory redemption beginning August 2000 (e) Cumulative Monthly Income Preferred Securities, Series A (MIPS): 6,000,000 authorized shares; $25 involuntary liquidation value (f) 1,500 authorized shares; $100,000 par value; $100,000 involuntary liquidation value (g) Preferred stock: 100 authorized shares; $50,000 par value; $50,000 per share involuntary liquidation value (h) Preference stock: 8,000,000 authorized shares; $1 par value; cumulative $35.50 per share involuntary liquidation value
In July 1997, the Company authorized and registered 1,000,000 shares of DQE Preferred Stock. As of December 31, 1998, 352,742 shares of DQE Preferred Stock had been issued and were outstanding. An additional 29,928 shares of DQE Preferred Stock were issued in January and February 1999. The DQE Preferred Stock ranks senior to the Company's common stock as to the payment of dividends and the distribution of assets on liquidations, dissolution or winding-up of the Company. Holders of DQE Preferred Stock are entitled to vote on all matters submitted to a vote of the holders of DQE common stock, voting together with the holders of common stock as a single class. Each share of DQE Preferred Stock is entitled to three votes. Each share of DQE Preferred Stock is convertible at the Company's option into the number of shares of DQE common stock computed by dividing the DQE Preferred Stock's $100 liquidation value by the five-day average
closing sales price of DQE common stock for the five trading days immediately prior to the conversion date. Each unredeemed share of DQE Preferred Stock will automatically be converted on the first day of the first month commencing after the sixth anniversary of its issuance.
Dividends on DQE Preferred Stock are paid quarterly on each January 1, April 1, July 1 and October 1. 11,720 shares of DQE Preferred Stock are entitled to an annual dividend of 4.3 percent, comprising a quarterly dividend of $1.075 per share. 3,760 shares are entitled to an annual dividend of 4.2 percent, comprising a quarterly dividend of $1.05 per share. 250,400 shares are entitled to an annual dividend of 4.0 percent, comprising a quarterly dividend of $1.00 per share. 3,120 shares are entitled to an annual dividend of 3.4 percent, comprising a quarterly dividend of $.85 per share. 107,543 shares (including 23,960 shares issued in January 1999) are entitled to an annual dividend of 3.6 percent, comprising a quarterly dividend of $.90 per share. 5,968 shares issued in February 1999 are entitled to an annual dividend of 3.8 percent, comprising a quarterly dividend of $.95 per share.
In June 1998, a DQE subsidiary issued 10 shares of preferred stock, par value $50,000 per share. The holders of such shares are entitled to a 6.5 percent annual dividend to be paid each September.
A Duquesne subsidiary has 15 shares of preferred stock, par value $100,000 per share, outstanding. The holders of such shares are entitled to a 6.5 percent annual dividend to be paid each September 30. In 1995, another Duquesne subsidiary issued 10 shares of preferred stock, par value $300,000 per share. The holders of such shares are entitled to a 9.0 percent annual dividend paid quarterly.
In May 1996, Duquesne Capital L.P. (Duquesne Capital), a special-purpose limited partnership of which Duquesne is the sole general partner, issued $150.0 million principal amount of 8 3/8 percent Monthly Income Preferred Securities (MIPS), Series A, with a stated liquidation value of $25.00. The holders of MIPS are entitled to annual dividends of 8 3/8 percent, payable monthly. The sole assets of Duquesne Capital are Duquesne's 8 3/8 percent debentures, with a principal amount of $151.5 million. These debt securities may be redeemed at Duquesne's option on or after May 31, 2001. Duquesne has guaranteed the payment of distributions on, and redemption price and liquidation amount in respect of the MIPS, to the extent that Duquesne Capital has funds available for such payment from the debt securities. Upon maturity or prior redemption of such debt securities, the MIPS will be mandatorily redeemed. The Company's consolidated balance sheet reflects only the $150.0 million of MIPS.
Holders of Duquesne's preferred stock are entitled to cumulative quarterly dividends. If four quarterly dividends on any series of preferred stock are in arrears, holders of the preferred stock are entitled to elect a majority of Duquesne's board of directors until all dividends have been paid. Holders of Duquesne's preference stock are entitled to receive cumulative quarterly dividends if dividends on all series of preferred stock are paid. If six quarterly dividends on any series of preference stock are in arrears, holders of the preference stock are entitled to elect two of Duquesne's directors until all dividends have been paid. At December 31, 1998, Duquesne had made all dividend payments. Preferred and preference dividends of subsidiaries included in interest and other charges were $16.7 million, $16.7 million and $12.1 million in 1998, 1997 and 1996. Total preferred and preference stock had involuntary liquidation values of $278.4 million and $244.4 million, which exceeded par by $26.9 million and $27.6 million at December 31, 1998 and 1997.
In December 1991, the Company established an Employee Stock Ownership Plan (ESOP) to provide matching contributions for a 401(k) Retirement Savings Plan for Management Employees. (See "Employee Benefits," Note N, on page 46.) The Company issued and sold 845,070 shares of preference stock, plan series A to the trustee of the ESOP. As consideration for the stock, the Company received a note valued at $30 million from the trustee. The preference stock has an annual dividend rate of $2.80 per share, and each share of the preference stock is exchangeable for one and one-half shares of DQE common stock. At December 31, 1998, $14.2 million of preference stock issued in connection with the establishment of the ESOP had been offset, for financial statement purposes, by the recognition of a deferred ESOP benefit. Dividends on the preference stock and cash contributions from the Company are used to fund the repayment of the ESOP note. The Company was not required to make a cash contribution for 1998. The Company made cash contributions of approximately $1.1 million for 1997 and $1.4 million for 1996. These cash contributions were the difference between the ESOP debt service and the amount of dividends on ESOP shares ($2.2 million in 1998, $2.3 million in 1997 and 1996). As shares of preference stock are allocated to the accounts of participants in the ESOP, the Company recognizes compensation expense, and the amount of the deferred compensation benefit is amortized. The Company recognized compensation expense related to the 401(k) plans of $1.6 million in 1998, $3.2 million in 1997 and $2.3 million in 1996. Although outstanding preferred stock is generally callable on notice of not less than 30 days, at stated prices plus accrued dividends, the outstanding MIPS and preference stock are not currently callable. None of the remaining Duquesne preferred or preference stock issues has mandatory purchase requirements.
M. Equity
Changes in the Number of Shares of DQE Common Stock Outstanding as of December 31, - --------------------------------------------------------------------------------
The Company has continuously paid dividends on common stock since 1953. The Company's annualized dividends per share were $1.52, $1.44 and $1.36 at December 31, 1998, 1997 and 1996. During 1998, the Company paid a quarterly dividend of $0.36 per share on each of January 1, April 1, July 1 and October 1. The quarterly dividend declared in the fourth quarter of 1998 was increased from $0.36 to $0.38 per share payable January 1, 1999. During 1997, the Company paid a quarterly dividend of $0.34.
Once all dividends on the DQE Preferred Stock have been paid, dividends may be paid on the Company's common stock to the extent permitted by law and as declared by the board of directors. However, payments of dividends on Duquesne's common stock may be restricted by Duquesne's obligations to holders of preferred and preference stock pursuant to Duquesne's Restated Articles of Incorporation and by obligations of Duquesne's subsidiaries to holders of their preferred securities. No dividends or distributions may be made on Duquesne's common stock if Duquesne has not paid dividends or sinking fund obligations on its preferred or preference stock. Further, the aggregate amount of Duquesne's common stock dividend payments or distributions may not exceed certain percentages of net income if the ratio of total common shareholder's equity to total capitalization is less than specified percentages. As all of Duquesne's common stock is owned by the Company, to the extent that Duquesne cannot pay common dividends, the Company may not be able to pay dividends on its common stock or DQE Preferred Stock. No part of the retained earnings of the Company was restricted at December 31, 1998.
Effective December 31, 1998, the Company adopted SFAS No. 130, Reporting Comprehensive Income (SFAS No. 130). This statement establishes standards for reporting and display of comprehensive income and its components (revenues, expenses, gains, and losses) in a full set of general-purpose financial statements. The objective of the statement is to report a measure of all changes in equity of a business enterprise that result from recognized transactions and other economic events of the period other than transactions with owners in their capacity as owners (comprehensive income).
Accumulated Other Comprehensive Income Balances as of December 31, - --------------------------------------------------------------------------------
In accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities (SFAS No. 115), these investments are classified as available-for-sale and are stated at market value. The amount of unrealized holding gains related to marketable securities was $8.9 million ($5.4 million, net of tax) at December 31, 1998, and $8.1 million ($4.7 million, net of tax) at December 31, 1997.
N. Employee Benefits
Pension and Postretirement Benefits
The Company maintains retirement plans to provide pensions for all eligible employees. Upon retirement, an employee receives a monthly pension based on his or her length of service and compensation. The cost of funding the pension plan is determined by the unit credit actuarial cost method. The Company's policy is to record this cost as an expense and to fund the pension plans by an amount that is at least equal to the minimum funding requirements of the Employee Retirement Income Security Act of 1974, but which does not exceed the maximum tax-deductible amount for the year. Pension costs charged to expense or construction were $12.2 million for 1998, $12.7 million for 1997, and $11.9 million for 1996.
In addition to pension benefits, the Company provides certain health care benefits and life insurance for some retired employees. Participating retirees make contributions, which may be adjusted annually, to the health care plan. The life insurance plan is non-contributory. Company-provided health care benefits terminate when covered individuals become eligible for Medicare benefits or reach age 65, whichever comes first. The Company funds actual expenditures for obligations under the plans on a "pay-as-you-go" basis. The Company has the right to modify or terminate the plans.
The Company accrues the actuarially determined costs of the aforementioned postretirement benefits over the period from the date of hire until the date the employee becomes fully eligible for benefits. The Company has elected to amortize the transition obligation over a 20 year period.
In 1998, the Company adopted SFAS No. 132, Employers' Disclosures about Pensions and Other Postretirement Benefits. This statement revises employers' disclosures about pension and other postretirement benefit plans.
The Company sponsors several qualified and nonqualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of plan assets over the two-year period ending December 31, 1998, a statement of the funded status as of December 31, 1998 and 1997, and summary of assumptions used in the measurement of the Company's benefit obligation:
Funded Status of the Pension and Postretirement Benefit Plans as of December 31, - --------------------------------------------------------------------------------
Weighted-Average Assumptions for the Year Ended December 31, - --------------------------------------------------------------------------------
All of the Company's plans for postretirement benefits, other than pensions, have no plan assets. The aggregate benefit obligation for those plans was $46.4 million as of December 31, 1998, and $46.3 million as of December 31, 1997. The accumulated postretirement benefit obligation comprises the present value of the estimated future benefits payable to current retirees, and a pro rata portion of estimated benefits payable to active employees after retirement.
Pension assets consist primarily of common stocks, United States obligations and corporate debt securities.
Components of Net Pension Cost for the Year Ended December 31, - --------------------------------------------------------------------------------
Components of Postretirement Cost for the Year Ended December 31, - --------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.
Effect of a One Percent Change in Health Care Cost Trend Rates for the Year Ended December 31, 1998 - --------------------------------------------------------------------------------
Retirement Savings Plan and Other Benefit Options
The Company sponsors separate 401(k) retirement plans for its management and bargaining unit employees.
The 401(k) Retirement Savings Plan for Management Employees provides that the Company will match employee contributions to a 401(k) account up to a maximum of 6 percent of an employee's eligible salary. The Company match consists of a $0.25 base match per eligible contribution dollar and an additional $0.25 incentive match per eligible contribution dollar, if Board- approved targets are achieved. The 1998 incentive target for management was not accomplished. The Company is funding its matching contributions to the 401(k) Retirement Savings Plan for Management Employees with payments to an ESOP established in December 1991. (See "Preferred and Preference Stock," Note L, on page 44.)
The 401(k) Retirement Savings Plan for IBEW Represented Employees provides that the Company will match employee contributions to a 401(k) account up to a maximum of 4 percent of an employee's eligible salary. The Company match consists of a $0.25 base match per eligible contribution dollar and an additional $0.25 incentive match per eligible contribution dollar, if certain targets are met. In 1998, the incentive target for bargaining unit employees was not accomplished.
The Company's shareholders have approved a long-term incentive plan, as amended, through which the Company may grant management employees options to purchase, during the years 1987 through 2006, up to a total of 9.9 million shares of the Company's common stock at prices equal to the fair market value of such stock on the dates the options were granted. At December 31, 1998, approximately 3.8 million of these shares were available for future grants.
As of December 31, 1998, 1997 and 1996, active grants totaled 1,230,946; 1,084,041; and 1,698,000 shares. Exercise prices of these options ranged from $15.8334 to $43.4375 at December 31, 1998; $15.8334 to $33.7813 at December 31, 1997; and from $8.2084 to $30.875 at December 31, 1996. Expiration dates of these grants ranged from 2000 to 2008 at December 31, 1998; from 2000 to 2007 at December 31, 1997; and from 1997 to 2006 at December 31, 1996. As of December 31, 1998, 1997 and 1996, stock appreciation rights (SARs) had been granted in connection with 867,104; 635,995; and 984,000 of the options outstanding. During 1998, 233,532 SARs were exercised; 170,476 options were exercised at prices ranging from $15.8334 to $31.5625; and no options were cancelled. During 1997, 694,984 SARs were exercised; 638,494 options were exercised at prices ranging from $8.2084 to $30.75; and no options were cancelled. During 1996, 715,000 SARs were exercised; 267,000 options were exercised at prices ranging from $8.2084 to $20.3334; and 150 options were cancelled. Of the active grants at December 31, 1998, 1997 and 1996, 750,463; 402,816; and 668,000 were not exercisable.
O. Business Segments and Related Information
Effective December 31, 1998, the Company adopted SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information (SFAS No. 131). This statement establishes standards for the way that public business enterprises report information about operating segments. Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. This statement also establishes standards for related disclosures about products and services, geographic areas, and major customers.
Historically, Duquesne has been treated as a single integrated business segment due to its regulated operating environment. The PUC authorized a combined rate for supplying and delivering electricity to customers which was cost-based and was designed to recover the Company's operating expenses and investment in electric utility assets and to provide a return on the investment. As a result of the Customer Choice Act, generation of electricity will be deregulated and charged at a separate rate from the delivery of electricity beginning in 1999 (five percent of customers chose alternative generation suppliers in 1998). For the purposes of complying with SFAS No. 131, the Company is required to disclose information about its business segments separately. Accordingly, the Company has used the PUC-approved separate rates for 1999 to develop the financial information of the business segments for the periods ended December 31, 1998, 1997 and 1996.
Beginning in 1999, the Company's principal business segments (determined by products and services) will consist of the transmission and distribution by Duquesne of electricity (electricity delivery business segment) and the generation by Duquesne of electricity and collection of the CTC (electricity generation business segment). To comply with SFAS No. 131, the Company has reported the results for 1998, 1997 and 1996 by these business segments and an "all other" category. The all other category in the following table includes the expanded business lines and Duquesne investments below the quantitative threshold for separate disclosure. These expanded business lines include water utilities, energy products and services, electronic commerce, and other activities. Intercompany eliminations primarily relate to intercompany sales of electricity, property rental, management fees and dividends. Upon the anticipated completion of the auction of the Company's generation assets and provider of last resort services, the electricity generation business segment will be comprised solely of the collection of the CTC.
Financial data for business segments is provided as follows:
P. Quarterly Financial Information (Unaudited)
(a) Restated to conform with 1998 presentation.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Part III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
Information relating to the Directors of DQE is set forth in the Proxy Statement for the DQE Annual Meeting of Shareholders to be held April 27, 1999. The information is incorporated here by reference. All Directors of DQE are also Directors of Duquesne Light Company. Information relating to the executive officers is set forth in Part I of this Report under the caption "Executive Officers of the Registrant."
Item 11.
Item 11. Executive Compensation.
Information relating to executive compensation is set forth in the Proxy Statement for the DQE Annual Meeting of Shareholders to be held April 27, 1999. The information is incorporated here by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Information relating to the ownership of equity securities of DQE by DQE directors, officers and certain beneficial owners is set forth under the caption "Beneficial Ownership of Stock" in the Proxy Statement for the DQE Annual Meeting of Shareholders to be held April 27, 1999. Information is incorporated here by reference.
Item 13.
Item 13. Certain Relations and Related Transactions.
None.
Part IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a)(1) The following information is set forth here in Item 8 (Consolidated Financial Statements and Supplementary Data) on pages 25 through 51 of this Report. The following financial statements and Report of Independent Certified Public Accountants are incorporated here by reference:
Report of Independent Certified Public Accountants.
Statement of Consolidated Income for the Three Years Ended December 31, 1998.
Consolidated Balance Sheet, December 31, 1997 and 1998.
Statement of Consolidated Cash Flows for the Three Years Ended December 31, 1998.
Statement of Consolidated Retained Earnings for the Three Years Ended December 31, 1998.
Notes to Consolidated Financial Statements.
(a)(2) The following financial statement schedule and the related Report of Independent Certified Public Accountants are filed here as a part of this Report:
Schedule for the Three Years Ended December 31, 1998:
II - Valuation and Qualifying Accounts.
The remaining schedules are omitted because of the absence of the conditions under which they are required or because the information called for is shown in the financial statements or notes to the consolidated financial statements.
(a)(3) Exhibits are set forth in the Exhibit Index below, incorporated here by reference. Documents other than those designated as being filed here are incorporated here by reference. Documents incorporated by reference to a DQE Annual Report on Form 10-K, a Quarterly Report on Form 10-Q or a Current Report on Form 8-K are at Securities and Exchange Commission File No. 1-10290. Documents incorporated by reference to a Duquesne Light Company Annual Report on Form 10-K, a Quarterly Report on Form 10-Q or a Current Report on Form 8-K are at Securities and Exchange Commission File No. 1-956. The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.
(b) Two reports on Form 8-K were filed during the fiscal quarter ended December 31, 1998, and two were filed thereafter.
A report was filed October 5, 1998, to report the Company's termination of the merger agreement with AYE. No financial statements were filed with this report.
A report was filed October 15, 1998, to report the execution by Duquesne and FirstEnergy Corporation of an agreement in principle to exchange interests in certain power stations. No financial statements were filed with this report.
A report was filed March 19, 1999, to report the consent agreement entered into by DQE and AYE. No financial statements were filed with this report.
A report was filed March 26, 1999, to report the execution of definitive power station exchange agreements. No financial statements were filed this report.
Exhibit Index
x An additional document, substantially identical in all material respects to this Exhibit, has been entered into relating to one additional limited partnership Owner Participant. Although the additional document may differ in some respects (such as name of the Owner Participant, dollar amounts and percentages), there are no material details in which the document differs from this Exhibit.
y Additional documents, substantially identical in all material respects to this Exhibit, have been entered into relating to four additional corporate Owner Participants. Although the additional documents may differ in some respects (such as names of the Owner Participants, dollar amounts and percentages), there are no material details in which the documents differ from this Exhibit.
z Additional documents, substantially identical in all material respects to this Exhibit, have been entered into relating to six additional Owner Participants. Although the additional documents may differ in some respects (such as names of the Owner Participants, dollar amounts and percentages), there are no material details in which the documents differ from this Exhibit.
Copies of the exhibits listed above will be furnished, upon request, to holders or beneficial owners of any class of DQE's stock as of February 28, 1999, subject to payment in advance of the cost of reproducing the exhibits requested.
SCHEDULE II
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 1998, 1997 and 1996 (Thousands of Dollars)
Notes: (A) Recovery of accounts previously written off. (B) Accounts receivable written off.
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.
DQE (Registrant)
Date: March 26, 1999 By: /s/ David D. Marshall --------------------- (Signature) David D. Marshall President and Chief Executive Officer
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.