ITEM 1. BUSINESS.
CORPORATE STRUCTURE
Part I of this Annual Report on Form 10-K should be read in conjunction with our audited consolidated financial statements, which are set forth on pages 18 through 39 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. is a multi-utility delivery and services company. Our subsidiaries are Duquesne Light Company; AquaSource, Inc.; DQE Capital Corporation; DQE Energy Services, Inc.; DQE Enterprises, Inc. (formerly Duquesne Enterprises, Inc.); DQE Financial Corp. (formerly Montauk, Inc.); and DQE Systems, Inc. (formerly DQEnergy Partners, Inc.).
Duquesne Light, our largest operating subsidiary, is an electric utility engaged in the supply, transmission, distribution and sale of electric energy. On December 3, 1999, Duquesne Light completed a power station asset exchange with FirstEnergy Corp. This was the first phase of our Pennsylvania Public Utility Commission (PUC)-approved plan to divest our generation assets. We expect to complete this divestiture through the pending sale of our remaining generation assets to Orion Power Holdings, Inc. Final sale agreements must be approved by various regulatory agencies, including the PUC. We expect the sale to close in the second quarter of 2000. After that time, we expect to meet our energy supply obligations through a provider of last resort service agreement with Orion. (See "Restructuring Plan" discussion on page 17.)
AquaSource, our second largest operating subsidiary, is a water resource management company that acquires, develops and manages water and wastewater utilities, bottled water operations and complementary businesses.
Our expanded business lines engage in a wide range of initiatives, including: the distribution of propane; the production of landfill gas and synthetic fuels; investments in electronic commerce, energy-related technology and communications systems; energy facility development and operation; and independent power production. DQE Capital provides financing for DQE and various affiliates.
Service Areas
Duquesne Light's electric utility operations provide service to approximately 580,000 direct customers in southwestern Pennsylvania (including in the City of Pittsburgh), a territory of approximately 800 square miles. We have also historically sold electricity to other utilities, and will continue to do so until the generation asset sale is complete. (See "Restructuring Plan" discussion on page 17.)
AquaSource's water operations currently provide service to approximately 430,000 water and wastewater customer connections in 18 states.
Our expanded business lines have operations and investments in several states and Canada.
Regulation
DQE and Duquesne Light are subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). In addition, Duquesne Light'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 May 29, 1998, final order regarding our restructuring plan under the Customer Choice Act (see "Rate Matters" on page 16), the electricity supply segment of our business does not meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Pursuant to the PUC's final restructuring order, our generation-related regulatory assets are being recovered through a competitive transition charge (CTC) collected in connection with providing transmission and distribution services, and these assets have been reclassified accordingly. The balance of transition costs will be adjusted by receipt of the proceeds from the pending generation asset sale. 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, 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 16.)
On December 15, 1999, the FERC issued its Order No. 2000, which calls on transmission-owning utilities such as Duquesne Light to voluntarily join regional transmission organizations. The goal of the order is to put transmission facilities in a region under common control in an effort to reduce costs. The order requires utilities to file a proposal for a regional transmission organization, a description of efforts to join one, or reasons for not joining one, by October 15, 2000. We are currently studying Order No. 2000, and have not yet determined our response.
AquaSource's water utility operations are subject to regulation by the utility regulatory bodies in their respective states. In the second quarter of 2000, we anticipate filing a consolidated rate case in Texas, AquaSource's largest state.
Business Segments
For the purposes of complying with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information (SFAS No. 131), we are required to disclose information about our business segments separately. This information is set forth in "Results of Operations" on page 9 and in "Business Segments and Related Information," Note O to our consolidated financial statements on page 37.
EMPLOYEES
At December 31, 1999, DQE and its subsidiaries had 3,578 employees. This reflects a reduction by approximately 1,100 employees through transfers to FirstEnergy following the power station exchange and early retirement under the divestiture-related program discussed below. In connection with the pending generation asset sale to Orion, we anticipate a further reduction by approximately 400 employees. Duquesne Light is party to a labor contract expiring in September 2001 with the International Brotherhood of Electrical Workers (IBEW), which represents the majority of Duquesne Light's employees. The contract provides, among other things, employment security, income protection and, in September 2000, a 3 percent wage increase. Duquesne Light and the IBEW have agreed on a package of additional benefits and protections for union employees affected by the divestiture of generation assets.
In connection with the power station exchange with FirstEnergy and the pending generation asset sale to Orion, Duquesne Light developed early retirement programs and enhanced available separation packages for eligible IBEW and management employees. Duquesne Light expects to recover related costs through the sale proceeds.
PROPERTY, PLANT AND EQUIPMENT (PP&E)
Investment in PP&E and Accumulated Depreciation
Our total investment in PP&E and the related accumulated depreciation balances for major classes of property at December 31, 1999 and 1998 are as follows:
Electric delivery PP&E includes: (1) high voltage transmission wires used in delivering electricity from generating stations to substations; (2) substations and transformers; (3) lower voltage distribution wires used in delivering electricity to customers; (4) related poles and equipment; and (5) internal telecommunication equipment, vehicles and office equipment. Electric production PP&E includes fossil and, in 1998, nuclear generating stations. Electric production accumulated depreciation reflects the write-down of production plant values to the PUC-determined market value. (See "Restructuring Plan" discussion on page 17.) Water distribution PP&E includes water systems and water treatment facilities. Our capital leases are primarily associated with leased nuclear fuel in 1998 and other electric plant. The Other PP&E is comprised of various buildings and land, E-Fuel(R) facilities, landfill gas recovery equipment and property related to our other expanded business lines.
Electric Utility Operations
We anticipate completing the divestiture of generation assets through the sale to Orion in the second quarter of 2000. Certain obligations related to the divested assets have been transferred to FirstEnergy, and others will be transferred to Orion.
Duquesne Light's fossil plants operated at an availability factor of 86 percent in 1999 and 80 percent in 1998. Duquesne Light's nuclear plants (which all were acquired by FirstEnergy in December 1999) operated at an availability factor of 84 percent in 1999 and 52 percent in 1998. The timing and duration of scheduled maintenance and refueling outages, as well as the duration of forced outages, affect the availability of power stations. Duquesne Light normally experiences its peak demand in the summer. The 1999 customer system peak demand of 2,756 megawatts (MW) occurred on July 6, 1999.
Fossil Fuel
Duquesne Light believes that sufficient coal for its coal-fired generating units will be available from various sources to satisfy its requirements through the closing of the pending generation asset sale. During 1999, approximately 2.0 million tons of coal were consumed at Duquesne Light's two wholly owned coal- fired stations, Cheswick Power Station (Cheswick) and Elrama Power Station (Elrama).
Duquesne Light owns Warwick Mine, an underground mine located in southwestern Pennsylvania. The current estimated liability for mine closing, including final site reclamation, mine water treatment and certain labor liabilities, is $49.3 million. Duquesne Light has recorded a liability for this amount on the consolidated balance sheet.
During 1999, 52 percent of Duquesne Light's coal supplies were provided by contracts, including Warwick Mine, with the remainder satisfied through purchases on the spot market.
ENVIRONMENTAL MATTERS
Various federal and state authorities regulate DQE and our subsidiaries with respect to air and water quality and other environmental matters. Environmental compliance obligations with respect to the plants transferred to FirstEnergy in the power station exchange have been assumed by FirstEnergy. In addition, FirstEnergy has contractually retained responsibility for operating the plants we acquired in the exchange, including the day-to-day environmental compliance. Upon completion of the generation asset sale, Orion will assume the environmental obligations related to all of the plants sold, both those originally owned by Duquesne Light and those acquired in the power station exchange. The following discussion of air quality and acid rain compliance primarily addresses environmental matters at the plants we both own and operate: Cheswick, Elrama, Brunot Island and Phillips.
As required by Title V of the Clean Air Act Amendments (Clean Air Act), we filed comprehensive air operating permit applications for Cheswick, Elrama, Brunot Island and Phillips in 1995. Approval is still pending for these applications. We filed our Title IV Phase II Clean Air Act compliance plan with the PUC on December 27, 1995. We 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. On December 30, 1999, we amended the Cheswick and Elrama applications, and filed a Phase II NO\x\ Averaging Plan. Approval also is pending for these applications.
Acid Rain Program Requirements. We believe we have satisfied all of the Phase I Acid Rain Program requirements of the Clean Air Act. However, the Phase II Acid Rain Program requires significant additional reductions of sulfur dioxide (SO\2\) through the end of 2000. We currently own and operate 611 MW of coal capacity equipped with SO\2\ emission-reducing equipment.
In 1999 we installed gas reburn NO\x\ reduction technology at Elrama Units 1, 2 and 3, and installed new, improved low NO\x\ burner technology at Elrama Unit 4. In 1998, Duquesne Light 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, we are 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. Duquesne Light believes it will continue its current low NO\x\ emission levels under the maintenance plan being established by the DEP. Duquesne Light 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 Environmental Protection Agency (EPA) issued additional ozone-related NO\x\ reduction requirements under Section 110 of the Clean Air Act, which may affect our power plants and supersede reduction levels specified for 2003 by the Ozone Transport Commission control program. Under this program, the EPA requires states in the northeast and midwest to amend their implementation plans to impose more stringent NO\x\ allowance caps on emissions during the May to September control period. In response to a Federal court stay of this program, the DEP has not finalized proposed implementation regulations, but has indicated it will proceed with a similar control program under Section 126 of the Clean Air Act. Until the Federal stay is resolved and regulations are
implemented, the costs of compliance cannot be determined. However, we anticipate that compliance would require additional capital and operational costs beyond those already estimated through 2000. Such compliance costs will be the responsibility of Orion following the generation asset sale.
Other. On November 3, 1999, the EPA and the Department of Justice filed suit against seven electric utility companies, including FirstEnergy. The suit alleges that the companies made illegal modifications to certain power plants, including Sammis Unit 7. FirstEnergy acquired Duquesne Light's interest in Sammis in the power station exchange. The ultimate outcome of this suit, and any potential impact it may have on Duquesne, cannot be determined at this time.
In 1992, the DEP issued Residual Waste Management Regulations governing the generation and management of non-hazardous residual waste, such as coal ash. We have assessed our residual waste management sites, and the DEP has approved our compliance strategies. We incurred capital costs of $0.5 million in 1999 to comply with these DEP regulations. We expect the capital cost of compliance to be approximately $5.0 million over the next two years with respect to sites we will continue to own after the generation asset sale.
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 was made on July 1, 1999, to report on emissions and discharges for 1998. Toxic release inventory reporting does not involve emission reductions. We do 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 our investment in GSF Energy (GSF), we 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 we are indemnified for any costs that GSF may incur related to these sites by at least one financially responsible party. Accordingly, we believe that these matters will not have a material adverse effect on our financial position, results of operations or cash flows.
AquaSource'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. In the fourth quarter of 1999, AquaSource met the water quality reporting requirement under the act by providing timely reports to its customers. AquaSource's operations are also subject to the Federal Clean Water Act, which regulates the discharge of pollutants into waterways. In connection with its acquisition strategy, AquaSource is aware of various compliance issues at its water and wastewater facilities, and is communicating and working closely with appropriate regulators to correct those issues in a timely manner. We do not believe that any of these compliance issues will have a material effect on DQE's financial position, results of operations or cash flows.
We are involved in various other environmental matters. We believe that such matters, in total, will not have a materially adverse effect on our financial position, results of operations or cash flows.
OUTLOOK
As discussed previously, we expect to close on the sale of our generation assets to Orion during the second quarter of 2000. However, if the closing is delayed we will experience electricity market price risks during the volatile summer months. In that event, we would evaluate entering into advance purchase power contracts to mitigate the risk of price spikes similar to those seen during the summer of 1999. If the closing is delayed beyond September 24, 2000, Orion could, under certain circumstances, terminate the transaction. In that event, while exploring other divestiture options, we would continue to operate the generating plants and would continue to collect CTC revenues at current levels.
Prospectively, assuming that the sale to Orion closes as expected, the electricity supply business will be a much smaller part of DQE than it has been historically. Among the challenges we will face is changing the role of our administrative infrastructure. While the number of electricity customers that we serve will not change, our margins from these customers will decline to reflect the fact that we are providing only the delivery service and not the electricity itself. Our reduced electricity margins will necessitate a lower level of support costs at the electricity business. We expect to retrain and redeploy some of our administrative employees, but we must also reduce our overall administrative costs to maintain profitability.
Also related to the generation divestiture, we will be changing the capital structure of Duquesne Light. With the proceeds from the sale, we expect to retire higher-cost series of outstanding debt and to reduce the level of equity accordingly to create a capital structure appropriate for an electricity delivery company.
As we continue our evolution into a multi-utility delivery company, we expect to continue our aggregation strategy in the water distribution and propane delivery businesses. Efforts during the beginning of 2000 will focus on continuing to increase operating efficiencies, clustering investments in
geographic regions and increasing returns on existing investments. Once operating efficiencies have been realized, we expect to proceed with a disciplined approach to growing these strategic businesses.
In addition to service-oriented delivery companies and an efficient support infrastructure, another integral component of our multi-utility vision is the use of electronic commerce channels to more efficiently offer products and services to our growing customer base. We expect to continue adding to our portfolio of technology-based investments, including those in electronic commerce. We expect some of the companies in our current technology-based portfolio of investments will consider additional capital raising activities, including potential public stock offerings, during 2000 and beyond. Related to such opportunities for market valuation of our investments, we see the potential for substantial increases in the value of some of our investments. However, as is the case with most early-stage companies, there is also the risk that the companies we have invested in will not continue to develop and will not produce acceptable returns. We have performed extensive due diligence and structured these investments to mitigate these risks.
In summary, we will continue to focus on targeted investment opportunities that add incremental value to our shareholders. We will maintain a disciplined approach to evaluating opportunities to expand our distribution businesses, and offer new products and services to our existing customer base. We face considerable challenges in completing the transformation of our business from a fully integrated electric utility into a multi-utility delivery company of the future. We expect that with continued successful negotiation of these challenges will come the opportunity for continued improvement in shareholder value.
OTHER
Retirement Plan Measurement Assumptions
The discount rate used to determine the projected benefit obligation on our retirement plans at December 31, 1999, increased to 7.5 percent. The effect of this change on our retirement plan obligations is reflected in the amounts shown in "Employee Benefits," Note N to the consolidated financial statements, on page 34. 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. 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. We are evaluating the impact on our financial statements and disclosures.
Market Risk
Market risk represents the risk of financial loss that may impact our consolidated financial position, results of operations or cash flows due to adverse changes in market prices and rates.
We manage our interest rate risk by balancing our exposure between fixed and variable rates while attempting to minimize our interest costs. Currently, our variable interest rate debt is approximately 25 percent of long-term borrowings. This variable rate debt is low-cost, tax-exempt debt. We also manage our interest rate risk by retiring and issuing debt from time to time and by maintaining a balance of short-term, medium-term and long-term debt. A 10 percent increase in interest rates would have affected our variable rate debt obligations by increasing interest expense by approximately $1.6 million for the years ended December 31, 1999, 1998 and 1997. A 10 percent reduction in interest rates would have increased the market value of our fixed rate debt by approximately $32.5 million and $22.8 million as of December 31, 1999 and 1998. Such changes would not have had a significant near-term effect on our future earnings or cash flows.
________________________________
Except for historical information contained herein, the matters discussed in this report are forward-looking statements that involve risks and uncertainties including, but not limited to: the timing of the anticipated transfer of generation assets to Orion and receipt of sale proceeds; the nature of final regulatory approvals regarding the generation asset sale; the final outcome of AYE's merger-related litigation; economic and business conditions with respect to Internet and energy technology companies; economic, competitive, governmental and technological factors affecting operations, markets, products, services and prices; and other factors discussed in our filings with the Securities and Exchange Commission.
EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below are the names, ages as of March 10, 2000, and positions during the past five years of our executive officers. Additional information is set forth on page 67 of the DQE Annual Report to Shareholders for the year ended December 31, 1999. The information is incorporated here by reference.
ITEM 2.
ITEM 2. PROPERTIES.
Our principal properties consist of Duquesne Light's 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 electric utility properties are subject to a mortgage lien of an Indenture of Mortgage and Deed of Trust dated as of April 1, 1992. Certain pollution control facilities are subject to an additional mortgage lien.
On December 3, 1999, Duquesne Light completed the power station exchange with FirstEnergy Corporation, acquiring ownership of three fossil-powered plants (located in Avon Lake and Niles, Ohio, and in New Castle, Pennsylvania) in exchange for its ownership interests in two nuclear-powered plants (located in Beaver Valley, Pennsylvania and Perry, Ohio) and three fossil-powered plants (located in Bruce Mansfield, Pennsylvania and Sammis and Eastlake, Ohio). Duquesne Light plans to complete the divestiture of its generation assets (including the three newly-acquired plants) through the pending sale of generation assets to Orion Power Holdings Inc. These properties have been used in the electricity supply business segment.
(1) Amounts represent Duquesne Light's share of the unit which was owned by Duquesne Light in common with one or more other electric utilities (or, in the case of Beaver Valley Unit 2, leased by Duquesne Light). Plant output shown is from January 1, 1999 through December 3, 1999, the date of the power station exchange. These plants were transferred to FirstEnergy in the power station exchange.
(2) Plant output shown is from December 4, 1999 through December 31, 1999. These plants were acquired from FirstEnergy in the power station exchange.
Duquesne Light owns 17 transmission substations (including two acquired in the power station exchange) and 557 distribution substations. Duquesne Light has 67 circuit-miles of transmission lines, comprised of 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 cable. These properties are used in the electricity delivery business segment.
Duquesne Light owns, but does not operate, 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. This property has been used in the electricity supply business segment.
We own Duquesne Light's headquarters at 411 Seventh Avenue in Pittsburgh and six E-Fuel(R) plants located in Kentucky, North Carolina, Ohio, Pennsylvania, South Carolina and Virginia.
AquaSource owns, in the states in which it operates, approximately 840 water systems and approximately 340 wastewater systems. These systems are comprised of distribution and collection lines, pump stations, treatment plants, storage tanks, reservoirs and related facilities. Properties are adequately maintained and units of property are replaced as and when necessary. AquaSource owns a substantial acreage of land, the greater part of which is located in watershed areas and used for the discharge of treated effluent, with the balance being principally sites of pumping and treatment plants, storage reservoirs, tanks and standpipes. These properties are used in our water distribution business segment.
Additional information relating to properties is set forth in "Property, Plant and Equipment," Note C to the consolidated financial statements on page 26 of this Report. The information is incorporated here by reference.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
Eastlake Unit 5
From September 1995 until December 1999, we and a FirstEnergy subsidiary, The Cleveland Electric Illuminating Company, had been involved in litigation regarding the then jointly owned Eastlake facility. Upon closing the power station exchange, we entered into a settlement agreement (approved by the United States District Court for the Northern District of Ohio, Eastern Division) dismissing the litigation. (See "Power Station Exchange" discussion, on page 17.)
Termination of the AYE Merger
On October 5, 1998, we announced the unilateral termination of the merger agreement with Allegheny Energy, Inc. (AYE). We believe 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. AYE filed suit in the United States District Court for the Western District of Pennsylvania, seeking to compel us to proceed with the merger, or in the alternative seeking an unspecified amount of money damages. On October 28, 1998, the judge ruled in our favor regarding termination of the merger agreement. AYE appealed to the United States Court of Appeals for the Third Circuit, who on March 11, 1999, remanded the case to the District Court for further proceedings. Trial was held from October 20 through 28, 1999. On December 3, 1999, the District Court ruled that we had properly terminated the merger agreement without breach, and granted judgment in our favor on all claims and all requests for injunctive relief. On December 14, 1999, AYE appealed this decision to the United States Court of Appeals for the Third Circuit. Argument was heard by the Third Circuit on March 9, 2000, and a decision is pending. We will continue to defend ourselves vigorously against AYE's claims. The ultimate outcome of the appeal cannot be determined at this time.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS.
Information relating to the market for DQE common stock and other matters related to our holders is set forth inside of the back cover of the DQE Annual Report to Shareholders for the year ended December 31, 1999 and on page 34 in Note M and page 39 in Note Q hereto. The information is incorporated here by reference. During 1999 and 1998, DQE declared quarterly dividends on our common stock totaling $1.54 per share and $1.46 per share, respectively. (See "Dividends" discussion on page 9.) At February 29, 2000, there were approximately 61,000 holders of record of our common stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data for each year of the eleven-year period ended December 31, 1999, are set forth on pages 20 and 21 of the DQE Annual Report to Shareholders for the year ended December 31, 1999. 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
In the second quarter of 1998, the PUC issued an order related to our plan to recover our transition costs from electric utility customers. As a result of the order, we recorded an extraordinary charge against earnings of $82.5 million, or $1.06 per share. The following discussion of results of operations excludes the impact of that charge.
1999 Compared to 1998
Our basic earnings per share were $2.65 in 1999 compared to $2.52 in 1998, an increase of 5.2 percent. Earnings available for common shareholders increased by $4.0 million, or 2.1 percent, due to additional acquisitions at AquaSource, gains on the disposition of certain non-strategic investments, and higher sales of electricity. Additionally, the average shares of outstanding common stock declined by 2.2 million, or 2.9 percent. The lower average shares outstanding reflect the 5.7 million shares of common stock we repurchased in 1999 for approximately $217 million.
1998 Compared to 1997
Our basic earnings per share were $2.52 in 1998 compared to $2.57 in 1997, a decrease of 1.9 percent. Earnings available for common shareholders decreased by $3.3 million, or 1.6 percent, due to gains recorded on the disposition of Chester Engineers and of Exide Electronics Group stock in 1997.
Dividends
Once all dividends on our Preferred Stock, Series A (Convertible), $100 liquidation preference per share (DQE Preferred Stock), have been paid, dividends may be paid on our common stock as permitted by law and as declared by the board of directors. However, payments of dividends on Duquesne Light's common stock may be restricted by Duquesne Light's obligations to holders of preferred and preference stock pursuant to Duquesne Light's Restated Articles of Incorporation and by obligations of Duquesne Light's subsidiaries to holders of their preferred securities. No dividends or distributions may be made on Duquesne Light's common stock if Duquesne Light has not paid dividends or sinking fund obligations on its preferred or preference stock. Further, the aggregate amount of Duquesne Light'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. Because we own all of Duquesne Light's common stock, if Duquesne Light cannot pay common dividends, we may not be able to pay dividends on our common stock or DQE Preferred Stock.
We have continuously paid dividends on common stock since 1953. Our annualized dividends per share were $1.60, $1.52 and $1.44 at December 31, 1999, 1998 and 1997. During 1999, we paid a quarterly dividend of $0.38 per share on each of January 1, April 1, July 1 and October 1. We increased the quarterly dividend declared in the fourth quarter of 1999 from $0.38 to $0.40 per share, payable January 1, 2000. We expect that funds generated from operations will continue to be sufficient to pay dividends. Our need for and the availability of funds will be influenced by, among other things: new investment opportunities; the economic activity within our service territories; environmental legislation; the anticipated closing of our generation asset sale to Orion; and the planned recapitalization of Duquesne Light. (See "Future Capital Requirements and Availability" discussion on page 15 and "Rate Matters" on page 16.)
Results of Operations by Business Segment
Historically, Duquesne Light was 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, that was (1) cost-based, (2) designed to recover operating expenses and investment in electric utility assets, and (3) designed to provide a return on the investment. As a result of the Customer Choice Act, supply of electricity is deregulated and charged at a separate rate from the delivery of electricity. For the purposes of complying with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, we are required to disclose information about our business segments separately. Accordingly, we have used the PUC-approved separate rates for 1999 to develop the financial information of the business segments for the periods ended December 31, 1999, 1998 and 1997.
We report our results by the following four principal business segments, determined by products, services and regulatory environment: (1) the transmission and distribution by Duquesne Light of electricity (electricity delivery business segment), (2) the supply by Duquesne Light of electricity (electricity supply business segment), (3) the collection by Duquesne Light of transition costs (CTC business segment), and (4) the distribution by AquaSource of water (water distribution business segment). Upon the anticipated completion of the sale of our generation assets, the electricity supply business segment will be comprised solely of provider of last resort service. We also report an "all other" category, which includes our expanded business lines and Duquesne Light investments below the quantitative
threshold for separate disclosure. Revenues in the "all other" category are comprised of approximately one-third energy facility operations, one-third landfill gas operations and one-third propane and other operating investments. Income from financial investments is included in other income. Assets in the "all other" category are comprised of approximately two-thirds financial investments. The remaining one-third includes an equal portion of energy facility assets, landfill gas recovery and processing assets and propane distribution assets. Intercompany eliminations primarily relate to intercompany sales of electricity, property rental, management fees and dividends.
We have changed the composition of our business segments, separately reporting water distribution for the first time. We have provided the corresponding information for earlier periods. Note O, "Business Segments and Related Information," in the Notes to the Consolidated Financial Statements on page 37 shows the financial results of each principal business segment in tabular form. These results are discussed below.
1999 Compared to 1998
Electricity Delivery Business Segment. The electricity delivery business segment contributed $56.5 million to net income in 1999 compared to $57.2 million in 1998, a decrease of $0.7 million or 1.2 percent.
Operating revenues for this business segment are primarily derived from the 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 also are affected by regional development. Sales to industrial customers are influenced primarily by national and global economic conditions.
Operating revenues increased by $17.1 million or 5.3 percent compared to 1998 due to an increase in sales to electric utility customers of 2.7 percent in 1999. Residential and commercial sales increased as a result of warmer summer temperatures during 1999 compared to 1998. Industrial sales increased primarily due to an increase in electricity consumption by steel manufacturers. The following table sets forth kilowatt-hours (KWH) delivered to electric utility customers.
Operating expenses for the electricity delivery business segment primarily are 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 gross receipts, property and payroll taxes. Operating expenses increased by $15.0 million or 10.1 percent compared to 1998, due to higher meter reading costs, higher gross receipts taxes, and increased costs related to customer assistance programs. We have completed installation of our Customer Advanced Reliability System, which replaced the traditional meter-reading process by providing information on customer electricity consumption on a real-time basis. This direct link with customers will serve as a platform for offering additional services and products, and is expected to reduce future costs.
Interest and other charges include interest on long-term debt, other interest and preferred stock dividends of Duquesne Light. In 1999, there was $6.9 million or 18.3 percent more interest and other charges allocated to the electricity delivery business segment compared to 1998. The increase was the result of additional short-term borrowings at Duquesne Light during the fourth quarter of 1999. Given the pending generation asset sale to Orion, all remaining Duquesne Light financing costs after recapitalization will be borne by the electricity delivery business segment.
Electricity Supply and CTC Business Segments. In 1999, the electricity supply and CTC business segments reported net income of $86.6 million compared to $71.9 million in 1998, an increase of $14.7 million or 20.4 percent.
For the electricity supply and CTC business segments, operating revenues are derived primarily from the supply of electricity for delivery to retail customers, the supply of electricity to wholesale customers and, beginning in 1999, the collection of generation-related transition costs from electricity delivery customers. Under fuel cost recovery provisions effective through May 29, 1998, 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 thus did not affect net income. In 1999, due to the PUC's final restructuring order, fuel costs were expensed as incurred, which impacted net income by the amount that fuel costs exceeded amounts included in Duquesne Light's authorized supply rates. (See "Rate Matters" on page 16.)
Energy requirements for our retail electric utility customers are reduced as more customers participate in customer choice. Energy requirements for residential and commercial customers are also 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 primarily 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 customer energy requirements, the energy market and transmission conditions, and the availability of generating stations. We no longer will make short-term sales to other utilities after the generation asset sale. (See "Rate Matters" on page 16.)
Operating revenues decreased by $39.7 million or 4.6 percent compared to 1998. The decrease in revenues resulted primarily from two factors: (1) 26.4 percent less energy supplied to electric utility customers due to greater participation in customer choice, and (2) the 1998 inclusion in revenues of $23.3 million related to deferred energy costs. Partially offsetting this decrease was a 75.3 percent increase in energy supplied to other utilities in 1999, due to our decision to make 600 MW available during the first six months of 1999 to licensed generation suppliers to stimulate competition, and increased capacity available to sell as a result of participation in customer choice. The following table sets forth KWH supplied for customers who have not chosen an alternative generation supplier.
Operating expenses for the electricity supply 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 gross receipts, property and payroll taxes.
Fluctuations in energy costs generally result from changes in the cost of fuel; the mix between coal, nuclear generation and purchased power; total KWH supplied; and generating station availability.
Operating expenses decreased $64.9 million or 12.0 percent from 1998, as a result of lower energy costs and the reclassification of Beaver Valley Unit 2 lease costs to financing charges in 1999. (See "Power Station Exchange" discussion on page 17.)
In 1999, fuel and purchased power expense decreased by $37.4 million or 14.2 percent compared to 1998. This decrease was the result of reduced energy supply requirements, due to customer choice, and a favorable energy supply mix. Generating station availability was improved in 1999.
Depreciation and amortization expense includes the depreciation of the power stations' plant and equipment and accrued nuclear decommissioning costs and amortization of transition costs. There was a decrease of $36.5 million or 23.0 percent compared to 1998. During 1998, prior to the PUC's May 29 final restructuring order, we accelerated depreciation of generation assets to minimize potential transition costs. Depreciation for the remainder of 1998 and CTC amortization for 1999 were in accordance with PUC-approved rates.
Interest and other charges include interest on long-term debt, other interest and preferred stock dividends of Duquesne Light. In 1999 there was a $30.7 million or 52.4 percent increase in interest and other charges compared to 1998. The increase reflects $35.2 million of Beaver Valley Unit 2 lease-related costs reclassified as financing costs in 1999, partially offset by a reduced allocation of total financing cost to the electricity supply business segment.
Water Distribution Business Segment. The water distribution business segment contributed $4.7 million to net income in 1999, compared to $1.6 million in 1998, an increase of $3.1 million or 193.8 percent. During 1999, AquaSource acquired 46 water distribution utilities for $142 million, of which $133 million was cash and $9 million was DQE Preferred Stock. These acquisitions more than doubled the size of this business segment, and resulted in increases in operating revenues, operating expenses and depreciation.
Operating revenues for this business segment are derived from the following: billings related to water and sewer services for utilities owned by AquaSource and utilities for which AquaSource is a contract operator; bottled water delivery sales; and water-related construction and engineering projects. Operating revenues increased by $91.5 million during 1999. The increase was primarily the result of increased revenues from utility customers (approximately $43 million), increased contract operations (approximately $22 million), and bottled water delivery sales (approximately $21 million).
Operating expenses for the water distribution business segment are primarily made up of costs to operate and maintain the water distribution systems; bottled water costs; administrative expenses; and non-income taxes, such as
property and payroll taxes. Operating expenses increased by $71.2 million as a result of the 1999 acquisitions.
Depreciation and amortization expense includes depreciation of utility delivery systems and the amortization of goodwill on acquisitions. The $10.4 million increase was attributable to increases in both depreciation and amortization related to the larger size of the business.
Interest and other charges in the water delivery business segment are primarily intercompany and are eliminated in consolidation. During 1999, intercompany borrowings for acquisitions increased substantially.
All Other. The all other category contributed $56.1 million to net income in 1999 compared to $67.3 million in 1998, a decrease of $11.2 million or 16.6 percent.
Operating revenues increased in 1999 by $17.0 million or 28.1 percent compared to 1998. This increase was primarily the result of increased revenues from our propane delivery business acquisitions and other new investments through the activities of the expanded business lines.
In 1999, operating expenses increased $49.2 million or 76.3 percent over 1998. This increase was primarily the result of increased expenses from our propane delivery business acquisitions and the growth of the expanded business lines' start-up and developmental activities.
Depreciation and amortization expense primarily includes the depreciation of plant and equipment of the expanded business lines and amortization of certain investments. In 1999, depreciation and amortization expense increased by $2.8 million or 21.9 percent, primarily due to the acquisition of propane delivery companies during 1999.
Other income primarily includes gains on investment dispositions, long-term investment income, and interest and dividend income related to the expanded business lines. Other income in 1999 was $27.9 million or 22.3 percent higher than in 1998. This increase was the result of gains on the disposition of real estate investments (approximately $29.4 million), and leases and other non- strategic investments (approximately $14.6 million). The increase was also the result of new investments made by the expanded business lines during late 1998 and throughout 1999.
Interest and other charges are made up of interest on long-term debt, other interest and preferred stock dividends of the expanded business lines. An increase of $13.7 million or 100.7 percent in 1999 was the result of higher long-term debt interest expense, primarily related to the growth in our propane delivery business. This debt and interest expense is primarily intercompany, and is eliminated in consolidation.
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 7.6 percent. Operating revenues for this business segment are primarily derived from the delivery of electricity.
Operating revenues increased by $4.6 million or 1.5 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 KWH delivered to electric utility customers.
Operating expenses increased $10.1 million or 7.3 percent from 1997, primarily as a result of higher costs of maintenance of the transmission and distribution system, and costs related to start-up and installation of the Customer Advanced Reliability System. The increase in 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, which was partially offset by retirements.
A decrease in other income of $1.5 million or 22.1 percent was the result of lower interest income from a smaller amount of cash available for investing, compared to the prior year.
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.
Electricity Supply Business Segment. In 1998, the electricity supply business segment reported net income of $71.9 million compared to $60.5 million in 1997, an increase of $11.4 million or 18.8 percent.
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 initial participation in customer choice, 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 customer choice. The following table sets forth KWH supplied for customers who had not chosen an alternative generation supplier.
Operating expenses increased $14.6 million or 2.8 percent from 1997 as a result of increased energy costs, partially offset by decreased maintenance costs and reduced Beaver Valley Unit 2 lease costs.
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 us to purchase power and generate power from higher fuel cost fossil stations.
Maintenance expense decreased in 1998, primarily related to the reversal of fossil station maintenance outage accruals for outages scheduled after the planned divestiture of generation. (See "Rate Matters" on page 16.) A reduction in nuclear station outage cost amortization in 1998 also contributed to the decrease in maintenance expense.
A decrease in depreciation and amortization expense of $32.5 million, or 17.0 percent compared to 1997, was the result of reduced depreciation of generation assets in accordance with the PUC's final restructuring order.
Other income decreased $3.7 million or 29.1 percent as 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 decreased $5.2 million or 8.2 percent 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.
Water Distribution Business Segment. The water distribution business segment contributed $1.6 million to net income in 1998 compared to a $0.4 million net loss in 1997. During 1998, AquaSource acquired 33 water distribution utilities for $156 million, of which $122 million was cash and $34 million was DQE Preferred Stock. These acquisitions more than doubled the size of this business segment, and resulted in increases in operating revenues, operating expenses, and depreciation.
All Other. The all other category contributed $67.3 million to net income in 1998 compared to $78.6 million in 1997, a decrease of $11.3 million or 14.4 percent.
Operating revenues decreased in 1998 by $2.8 million, or 4.4 percent compared to 1997. This decrease was primarily the result of the loss of operating revenues from the sale of Chester Engineers by DQE Enterprises in the second quarter of 1997.
In 1998, operating expenses increased $3.6 million or 5.9 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 we wrote off costs related to the terminated merger with Allegheny Energy, Inc. (AYE), resulting in an increase to other operating expenses of $14.1 million. (See "Rate Matters" on page 16.) Offsetting in part the increases to operating expenses was the 1997 sale of Chester Engineers, which resulted in reduced operating costs of $7.8 million, and the recognition of the favorable resolution of certain associated contingencies in 1998.
Other income primarily includes long-term investment income, and interest and dividend income related to the expanded business lines and Duquesne Light investments. Other income in 1998 was $6.0 million or 5.0 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 Light in the fourth quarter of 1997. Other income in 1997 included the gains on the sale of Chester Engineers and of Exide Electronics 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 Engineers.
LIQUIDITY AND CAPITAL RESOURCES
During 1999, we continued our strategy of acquiring and aggregating small to mid-sized water distribution companies. Additionally, we began a similar aggregation strategy with propane delivery companies, clustering our acquisitions in three geographically diverse regions. These acquisition-related investments have grown from $8 million in 1997 to $156 million in 1998 to $205 million in 1999. This acquisition focus corresponds with a decrease in our other long-term investment level, which declined from $210 million in 1997 to $60 million in 1998 to $30 million in 1999.
Capital Expenditures
We spent approximately $147.2 million in 1999, $190.5 million in 1998 and $116.0 million in 1997 for capital expenditures, of which $100.3 million in 1999, $113.3 million in 1998 and $90.4 million in 1997 was spent for electric utility construction. Approximately $27.2 million was spent in 1999 for water utility construction. The remaining capital expenditures were related to the expanded business lines and other investments. The 1998 capital expenditure level was higher, as it included $41 million related to facility construction for the production of E-Fuel(R), a synthetic fuel. We estimate that we will spend, excluding allowance for funds used during construction (AFC), approximately $85 million (including $5 million relating to generation), $75 million and $75 million for electric utility construction in 2000, 2001 and 2002; and $45 million, $19 million and $24 million for water utility construction in 2000, 2001 and 2002.
Acquisitions and Dispositions
In 1999 we invested $205 million in the acquisition of companies and closed on the power station exchange with FirstEnergy. AquaSource acquired 46 water and water-related companies for a total investment of approximately $142 million. Of this total investment, $133 million was cash and $9 million was the issuance of 86,337 shares of DQE Preferred Stock. Also in 1999, DQE Systems acquired 18 propane delivery companies for a total investment of approximately $63 million, all of which was cash. In the power station exchange with FirstEnergy, Duquesne Light acquired three power plants and disposed of its partial interests in five power plants. (See "Power Station Exchange" discussion on page 17.) During 1999, we also disposed of several non-strategic real estate and lease investments. Proceeds from these dispositions totaled $143 million. We expect to continue to sell non-strategic investments. In early 2000 we signed a non-binding memorandum of understanding with Itron, Inc., for the potential purchase of the Itron-designed Customer Advanced Reliability System, which we currently lease.
In 1998, AquaSource acquired 33 water and water-related companies for a total investment of approximately $156 million. Of this total investment, $122 million was cash and $34 million was the issuance of 337,262 shares of DQE Preferred Stock. Dispositions in 1998 relate to assets acquired through leasehold interest investments. Dispositions in 1997 relate primarily to the sale of Chester Engineers and of Exide Electronics stock.
Long-Term Investments
We have made long-term investments in the following areas: leases, affordable housing, landfill and coal-bed methane gas reserves, and deposits in nuclear decommissioning funds. The decommissioning trust held funding for nuclear decommissioning costs related to Duquesne Light's nuclear-powered plants. During 1999, Duquesne Light invested approximately $60 million in the decommissioning trust funds, in order to fully fund the decommissioning liability, prior to transferring both the trust funds and the liability to FirstEnergy in the power station exchange. (See "Power Station Exchange" discussion on page 17.) Cash related to this funding was collected during the year through the CTC component of customer bills. Other long-term investing activities during 1999, primarily engaged in by the expanded business lines, totaled $30 million and included landfill gas reserves, a joint venture that designs, engineers and constructs landfill gas collection systems, affordable housing partnerships, and various electronic commerce investments. These electronic commerce investments include investments in securities convertible into 51 percent of the common stock of Predictive Data, Inc., which offers an insurance product to replace security deposits, and in securities convertible into 34 percent of the common stock of OnLine Choice.com, which uses the Internet to create customer pools to purchase goods and services, such as electricity, natural gas and telephone service at lower prices through volume discounts.
During 1998, Duquesne Light invested approximately $9 million in the nuclear decommissioning trust funds. Other long-term investing activities during 1998, primarily engaged in by the expanded business lines, totaled $60 million and included a joint venture in a commercial and industrial heating, ventilation and air conditioning service and energy controls company, affordable housing partnerships, landfill gas reserves, and various electronic commerce investments. These electronic commerce investments include investments in securities convertible into 26 percent of the equity of BroadPoint Communications, Inc., which offers its more than 400,000 subscribers free long- distance telephone service in exchange for listening to targeted advertisements, and in securities convertible into 23 percent of the common stock of Enermetrix.com, which provides an Internet auction-
based service for the purchase of electricity and natural gas by commercial and industrial customers from over 55 energy suppliers.
Investing activities during 1997 included approximately $9 million in the nuclear decommissioning trust funds. Other long-term investing activities during 1997, primarily engaged in by the expanded business lines, totaled $210 million, including $180 million in lease investments. We also invested in the common stock of SatCon Technologies, a provider of energy management products and components used in telecommunications, factory automation, aircraft, satellites, and the automotive and fuel cell industries. We currently hold approximately seven percent of SatCon common stock on a fully-diluted basis.
Financing
During 1999, in addition to capital provided from operations, we raised capital to continue our water and propane delivery company acquisition program, to effect the termination of the Beaver Valley Unit 2 lease, and to begin our recapitalization program in anticipation of the generation divestiture. As discussed on page 14, we invested $205 million in acquisitions, $147 million in capital expenditures, and $90 million in nuclear decommissioning and other long- term investments during 1999. Additionally, in connection with the power station exchange, we paid approximately $234 million in termination costs and $43 million in related taxes to cancel the Beaver Valley Unit 2 lease. Of this total amount, $107 million represents costs previously approved for recovery through the CTC. The remaining $170 million is included on the consolidated balance sheet as divestiture costs. As part of this transaction, the lease liability recorded on the consolidated balance sheet was eliminated; however the underlying collateralized lease bonds ($359 million upon lease termination) became obligations of Duquesne Light and are now recorded on the consolidated balance sheet as debt, $9 million of which will mature in 2000. (See "Power Station Exchange" discussion on page 17.) Prior to cancelling the Beaver Valley Unit 2 lease, we paid approximately $42 million to terminate our nuclear fuel lease (the nuclear fuel was transferred to FirstEnergy in the power station exchange). During 1999 we repurchased 5.7 million shares of DQE common stock on the open market for approximately $217 million. These purchases occurred primarily in the fourth quarter. Additional capital was required for the maturity of $75 million of mortgage bonds, the repurchase of approximately $2 million of DQE Preferred Stock and the payment of $117 million of dividends.
To meet these capital requirements, and to serve as a bridge until the anticipated receipt of our generation divestiture proceeds, we undertook several financing initiatives during 1999. At year-end, we had $343 million of commercial paper borrowings outstanding, and $469 million of current debt maturities. During 1999, the maximum amount of bank loans and commercial paper borrowings outstanding was $368.9 million, the amount of average daily borrowings was $46.3 million, and the weighted average daily interest rate was 5.6 percent. In the fourth quarter of 1999, we issued $290 million of first mortgage bonds with a one-year term, callable in May 2000. The interest rate on the bonds is 6.53 percent. This debt was used to fund the Beaver Valley Unit 2 lease termination costs. On a longer-term basis, in the third quarter we issued $100 million of 8 3/8 percent notes, due in September 2039. In addition to these financings, as previously discussed, we issued $9 million of DQE Preferred Stock in conjunction with acquisitions by AquaSource.
During 1998, our requirement to access new sources of funding was much more modest. While we invested $122 million in acquisitions, $191 million in capital expenditures, and $69 million in nuclear decommissioning and other long-term investments, our cash balance of $356 million at the beginning of the year allowed us to minimize new financing activities. Additional capital was required during the year for the retirement of approximately $200 million of current maturities, the payment of $114 million of dividends, and common stock repurchases of $14 million. During 1998, we issued $140 million of first mortgage bonds to accomplish these debt retirements. Additionally, we issued $34 million of DQE Preferred Stock and assumed approximately $22 million in long-term debt in conjunction with acquisitions by AquaSource. We also issued a $25 million note, maturing in 2019 with an annual interest rate of 8.0 percent, in connection with an investment in landfill gas property and equipment.
During 1997, we invested $219 million in nuclear decommissioning and other long-term investments, $116 million in capital expenditures and $8 million as we began our water delivery acquisition program. These expenditures were all funded with available capital and capital from internal sources. We also retired approximately $50 million of maturing debt and paid $107 million of dividends.
Future Capital Requirements and Availability
We have entered into an agreement to sell Duquesne Light's generation assets to Orion for $1.71 billion. (See "Auction Plan" discussion on page 17.) We anticipate using the proceeds from this sale (currently estimated to be $1.1 billion, net of tax and transaction costs) to recapitalize Duquesne Light. This process will include the retirement of short-term debt, the redemption of long- term debt and the continued aggressive repurchase of outstanding common stock. Through February 29, 2000 we have repurchased 1.4 million shares of DQE common stock for approximately $61 million. In conjunction with the generation asset sale to Orion, Duquesne Light expects to acquire the $359 million of 8.7 percent collateralized lease bonds, previously assumed as part of the Beaver Valley Unit 2 lease termination. Additionally, maturing during 2000 will be $390
million of first mortgage bonds ($290 million of which were issued in November 1999), $65 million of term loans, and $9 million of collateralized lease bonds.
We expect to meet our current obligations and debt maturities through 2004 with funds generated from operations, through new financings and short-term borrowings, and through the proceeds from the sale of generation assets to Orion. During January 2000, we issued $150 million of floating rate two-year notes, callable in July 2000. The proceeds of this issuance were used to reduce the amount of outstanding commercial paper.
We maintain two separate revolving credit agreements, one for $250 million expiring in June 2000 and one for $225 million expiring in September 2000. We have the option to convert each revolver into a term loan facility for a period of one or two years, respectively, for any amounts then outstanding upon expiration of the revolving credit period. Interest rates can, in accordance with the option selected at the time of the borrowing, be based on one of several indicators, including prime, Eurodollar, or certificate of deposit rates. Facility fees are based on the unborrowed amount of the commitment. At December 31, 1999 and 1998, no borrowings were outstanding. Related to these and other credit facilities, we are subject to financial covenants requiring certain cash coverage and debt-to-capital ratios. At December 31, 1999, we were in compliance with all of our financial covenants.
Duquesne Light and an unaffiliated corporation have an agreement that entitles Duquesne Light to sell, and the corporation to purchase, on an ongoing basis, up to $50 million of accounts receivable. At various times during 1999 and in the first quarter of 2000, Duquesne Light had sold receivables under the facility. No amounts were outstanding at December 31, 1999 and 1998. The accounts receivable sales agreement, which expires in February 2001, is one of many sources of funds available to us. We may elect to extend the agreement upon expiration, replace it with a similar facility, or terminate it.
In connection with customer choice, customer revenues from Duquesne Light's operations are reduced by an amount equal to the generation rate applicable to those customers choosing alternative generation suppliers. This reduction is expected to be offset by lower generation and purchased power costs. An additional impact is anticipated when the provider of last resort service agreement with Orion takes effect, and all customers will be buying generation either directly from alternative suppliers or indirectly from Orion. A further impact on customer revenues is expected to occur when the CTC has been fully collected, which is currently expected to occur in 2001 for most major rate classes; elimination of the CTC will reduce customer rates, on average, by 25 percent for those rate classes. The foregoing statements are forward-looking regarding the impact on cash flows of customer choice and Duquesne Light's divestiture. 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 timing of the generation asset sale closing and the receipt of sale proceeds. (See "Restructuring Plan" on page 17.)
RATE MATTERS
Competition and the Customer Choice Act
Under Pennsylvania 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 process, utilities had assets recorded on their balance sheets at above-market costs, thus creating transition costs.
The Customer Choice Act (effective January 1, 1997) enables Pennsylvania's electric utility customers to purchase electricity at market prices from a variety of electric generation suppliers (customer choice). As of January 2000, all customers have customer choice. As of February 29, 2000, approximately 23 percent of Duquesne Light's customers had chosen alternative generation suppliers, representing approximately 30 percent of Duquesne Light's non- coincident peak load. Customers who have chosen an electricity generation supplier other than Duquesne Light pay that supplier for generation charges, and pay Duquesne Light the CTC (discussed below) and charges for transmission and distribution. Customers who continue to buy their generation from Duquesne Light pay for their service at current regulated tariff rates divided into generation, transmission and distribution charges, and the CTC. Electricity delivery (including transmission, distribution and customer service) remains regulated in substantially the same manner as under historical regulation.
Rate Cap An overall four-and-one-half-year rate cap from January 1, 1997, was originally imposed on the transmission and distribution charges of Pennsylvania electric utility companies under the Customer Choice Act. As part of a settlement regarding recovery of deferred fuel costs (discussed below), we have agreed to extend this rate cap for an additional six months through the end of 2001.
Provider of Last Resort
Duquesne Light is required not only to deliver electricity, but also to serve as the provider of last resort for all customers in its service territory. As the provider of last resort, Duquesne Light must provide electricity for any customer who cannot or does not choose an alternative electric generation supplier, or whose supplier fails to deliver. While collecting the CTC, Duquesne Light may charge only PUC-approved rates for the supply of electricity as the provider of last resort. As part of the pending generation asset sale, Orion has agreed to supply Duquesne Light, under a provider of last resort service agreement, with all of the electric energy necessary to satisfy Duquesne Light's provider of last resort obligations during the CTC collection period. Under the Customer Choice Act, after the CTC collection period Duquesne Light anticipates that it will supply electricity at market prices to fulfill its provider of last resort obligations.
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that Duquesne Light should recover most of the above-market costs of its generation assets, including plant and regulatory assets, through the collection of the CTC from electric utility customers. The $1.49 billion of transition costs, net of tax, was originally to be recovered over a seven-year period ending in 2005. However, by applying expected net proceeds of the pending generation asset sale to Orion to reduce transition costs, we currently anticipate early termination of the CTC collection period in 2001 for most major rate classes. In addition, the transition costs as reflected on the consolidated balance sheet are being amortized over the same period that the CTC revenues are being recognized. Duquesne Light is allowed to earn an 11 percent pre-tax return on the unrecovered, net of tax balance of transition costs, as adjusted following the generation asset sale.
As part of our restructuring plan filing, we 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. We also requested recovery of an additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. Although the PUC initially denied recovery of this additional amount, on October 26, 1999, Duquesne Light and the Pennsylvania Office of the Consumer Advocate reached a settlement on this issue which would permit recovery of the entire $42.7 million ($24.9 million, net of tax) in deferred fuel costs. The PUC approved this settlement on February 11, 2000.
On December 18, 1998, the PUC approved Duquesne Light's auction plan, which included an auction of its provider of last resort service obligations, as well as an agreement to carry out the power station exchange with FirstEnergy.
Power Station Exchange. On December 3, 1999, Duquesne Light completed the exchange of its partial interests in five power plants for three wholly owned power plants of subsidiaries of FirstEnergy. Duquesne Light received three fossil-powered plants (located in Avon Lake and Niles, Ohio, and in New Castle, Pennsylvania) having an aggregate net demonstrated capacity of 1,323 MW. The ownership interests transferred by Duquesne Light included its interests in the nuclear-powered Beaver Valley, Pennsylvania and Perry, Ohio plants, and the fossil-powered Bruce Mansfield, Pennsylvania and Sammis and Eastlake, Ohio plants, having an aggregate net demonstrated capacity of 1,435 MW. Along with ownership of the nuclear-powered plants, FirstEnergy assumed the decommissioning liability for Beaver Valley and Perry, in exchange for the fully funded balance in decommissioning trust funds previously maintained by Duquesne Light. During 1999, we funded approximately $60 million into the decommissioning trusts. These amounts, which were collected through the CTC during the year, brought the fund balances to approximately $122 million. In connection with the power station exchange, we terminated the Beaver Valley Unit 2 lease in the fourth quarter of 1999. (See "Financing" discussion on page 15.)
Auction Plan. On September 24, 1999, Duquesne Light and the winning auction bidder, Orion, entered into definitive agreements pursuant to which Orion will purchase Duquesne Light's wholly owned Cheswick, Elrama, Phillips and Brunot Island power stations, and the stations received from FirstEnergy in the power station exchange, for approximately $1.71 billion (estimated to be $1.1 billion, net of tax and transaction expenses). Under a provider of last resort service agreement, Orion will supply Duquesne Light with all of the electric energy necessary to satisfy Duquesne Light's obligations to its customers who have not chosen an alternative electric generation supplier. This agreement, which expires upon Duquesne Light's final collection of the CTC, in general effectively transfers to Orion the financial risks and rewards associated with Duquesne Light's provider of last resort obligations. While we retain the collection risk for the electricity sales, a component of our regulated delivery rates is designed to cover the cost of a normal level of uncollectible accounts. Duquesne Light and Orion are currently discussing an extension of this provider of last resort arrangement beyond the final CTC collection.
The Orion transactions must be approved by various regulatory agencies, including the PUC, the FERC, and the Federal Trade Commission. Duquesne Light currently expects the sale to close in the second quarter of 2000. The final
accounting for the sale proceeds remains subject to PUC approval. Through December 31, 1999, we have deferred approximately $219 million of costs related to the power station exchange and the asset sale. Additional divestiture- related costs will be deferred as incurred. We expect to fully recover these costs through the divestiture process; however, any disallowed costs will be written off.
Until the divestiture is complete, Duquesne Light is required to use an interim CTC and price to compare for each rate class (approximately 2.9 cents per KWH on average for the CTC, and approximately 3.8 cents per KWH on average for the price to compare).
Termination of the AYE Merger
On October 5, 1998, we announced our unilateral termination of our merger agreement with Allegheny Energy, Inc. (AYE). AYE filed suit in the United States District Court for the Western District of Pennsylvania, seeking to compel us to proceed with the merger, or in the alternative seeking an unspecified amount of money damages. After holding a trial from October 20 through 28, 1999, the District Court ruled on December 3, 1999, that we had properly terminated the merger agreement without breach, and granted judgment in our favor on all claims and all requests for injunctive relief. On December 14, 1999, AYE appealed this ruling to the Third Circuit. Argument was heard on March 9, 2000, and a decision is pending. We cannot determine the ultimate outcome of AYE's appeal at this time.
YEAR 2000
We took comprehensive steps to ensure a smooth transition into the Year 2000. Since 1994, we planned for the Year 2000 with an aggressive strategy to identify information needs, replace or upgrade equipment and coordinate resources to anticipate the new millennium. We experienced normal operations during the transition, and continue to do so.
The total cost of implementing our Year 2000 plan was approximately $49 million, which includes costs related to total system replacements (i.e., the Year 2000 solution comprised only a portion of the benefit resulting from such replacements). These costs were primarily incurred as a result of software and system changes and upgrades. Approximately $35 million was capital costs attributable to the licensing and installation of new software for total system replacements. The remaining $14 million was expensed as it was incurred.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The information regarding market risk required by this Item is set forth in Item 1 under the heading "Market Risk".
ITEM 8.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT AUDITORS
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, 1999 and 1998, 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, 1999. 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 DQE Inc.'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 significant 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, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 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 therein.
/s/ Deloitte & Touche LLP Pittsburgh, Pennsylvania January 28, 2000
Statement of Consolidated Income
See notes to consolidated financial statements.
Consolidated Balance Sheet
See notes to consolidated financial statements.
Consolidated Balance Sheet
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. is a multi-utility delivery and services company. Our subsidiaries are Duquesne Light Company; AquaSource, Inc.; DQE Capital Corporation; DQE Energy Services, Inc.; DQE Enterprises, Inc. (formerly Duquesne Enterprises, Inc.); DQE Financial Corp. (formerly Montauk, Inc.); and DQE Systems, Inc. (formerly DQEnergy Partners, Inc.).
Duquesne Light, our largest operating subsidiary, is an electric utility engaged in the supply, transmission, distribution and sale of electric energy. On December 3, 1999, Duquesne Light completed a power station asset exchange with FirstEnergy Corp. This was the first phase of our Pennsylvania Public Utility Commission (PUC)-approved plan to divest our generation assets. We expect to complete this divestiture through the pending sale of our remaining generation assets to Orion Power Holdings, Inc. Final sale agreements must be approved by various regulatory agencies, including the PUC. We expect the sale to close in the second quarter of 2000. After that time, we expect to meet our energy supply obligations through a provider of last resort service agreement with Orion. (See "Restructuring Plan" discussion, Note F, on page 28.)
AquaSource, our second largest operating subsidiary, is a water resource management company that acquires, develops and manages water and wastewater utilities, bottled water operations and complementary businesses.
Our expanded business lines engage in a wide range of initiatives, including: the distribution of propane; the production of landfill gas and synthetic fuels; investments in electronic commerce, energy-related technology and communications systems; energy facility development and operation; and independent power production. DQE Capital provides financing for DQE and various affiliates.
All material intercompany balances and transactions have been eliminated in the preparation of the consolidated financial statements.
Basis of Accounting
DQE and Duquesne Light are subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). In addition, Duquesne Light'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 May 29, 1998, final order regarding our restructuring plan under the Customer Choice Act (see "Rate Matters," Note F, on page 27), the electricity supply segment of our business does not meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Pursuant to the PUC's final restructuring order, our generation-related regulatory assets are being recovered through a competitive transition charge (CTC) collected in connection with providing transmission and distribution services, and these assets have been reclassified accordingly. The balance of transition costs will be adjusted by receipt of the proceeds from the pending generation asset sale. 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, 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 27.) These regulatory assets consist of a regulatory tax receivable, unamortized debt costs and deferred employee costs.
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 also may be affected by the estimates and assumptions management is required to make. Actual results could differ from those estimates.
Energy Cost Rate Adjustment Clause
Through the Energy Cost Rate Adjustment Clause (ECR), Duquesne Light previously recovered (by the amount that such expenses were not included in base rates) nuclear fuel, fossil fuel and purchased power expenses. Also through the ECR, Duquesne Light passed to its customers the profits from short-term power sales to other utilities. As a consequence of the PUC's final order regarding Duquesne Light's restructuring plan, such costs are no longer recoverable through the ECR. Instead, effective May 29, 1998 (the date of the PUC's final restructuring order), such costs are expensed as incurred and thus impact net income. (See "Restructuring Plan" discussion, Note F, on page 28.)
Revenues from Utility Sales
Duquesne Light's electric utility operations provide service to approximately 580,000 direct customers in southwestern Pennsylvania (including in the City of Pittsburgh), a territory of approximately 800 square miles. We have also historically sold electricity to other utilities, and will continue to do so until the generation asset sale is complete. (See "Restructuring Plan" discussion, Note F, on page 28.) Duquesne Light's meters are read monthly and electric 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 above.)
AquaSource's water utility operations currently provide service to approximately 430,000 water and wastewater customer connections in 18 states.
Maintenance
Effective January 1, 1999, as a result of the PUC's final restructuring order, all electric utility maintenance costs are expensed as incurred. Historically, incremental maintenance costs incurred for refueling outages at Duquesne Light's nuclear units (which all were acquired by FirstEnergy in December 1999) were deferred for amortization over the period between refueling outages (generally 18 months). Duquesne Light 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.
Depreciation and Amortization
Depreciation of property, plant and equipment 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. Amortization of gas reserve investments and depreciation of related property are calculated 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; 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. Amortization of transition costs represents the
difference between CTC revenues billed to customers and the allowed return on our unrecovered net transition cost balance (11 percent pre-tax).
In 1998 and 1997, Duquesne Light recorded nuclear decommissioning costs under the category of depreciation and amortization expense, and accrued a liability, equal to that amount, for nuclear decommissioning expense. In 1999, these costs are included in transition cost amortization. On the consolidated balance sheet, in 1998 the decommissioning trusts have been reflected in other long-term investments, and the related liability has been recorded as other non-current liabilities. Historically, trust fund earnings increased the fund balance and the recorded liability. Fully funded trust funds and decommissioning liability were transferred to FirstEnergy in the power station exchange. (See "Power Station Exchange" discussion, Note F, on page 28.)
Income Taxes
We use 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 the electricity delivery business segment, we recognize 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 27 and 29.) Reversals of accumulated deferred income taxes are included in income tax expense.
Investment tax credits (ITC) related to the electricity delivery business segment generally were deferred. These prior 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 non-kilowatt-hour (KWH) electric utility revenues and revenues from AquaSource's and the 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 our utility 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 electricity supply business segment properties were written down to market value in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, in conjunction with the PUC's final restructuring order.
Substantially all of the 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. We consider temporary cash investments to be cash equivalents.
Earnings Per Share
Basic earnings per share is computed on the basis of the weighted average number of common shares outstanding. Diluted earnings per share is computed on the basis of the weighted average number of common shares outstanding plus the effect of the outstanding Employee Stock Ownership Plan shares, DQE Preferred Stock and stock options. The treasury stock method is used in computing the dilutive effect of stock options. This method assumes any proceeds obtained upon the exercise of options would be used to purchase common stock at the average market price during the period. The following table presents the numerators and denominators used in computing the diluted earnings per share before 1998 extraordinary charge for 1999, 1998 and 1997.
Stock-Based Compensation
We account 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 DQE common 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 based on the quoted market price of the stock at the end of the year.
Reclassification
The 1998 and 1997 consolidated financial statements have been reclassified to conform with 1999 presentation.
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. 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. We are evaluating the impact on our financial statements and disclosures.
B. CHANGES IN WORKING CAPITAL OTHER THAN CASH
C. PROPERTY, PLANT AND EQUIPMENT
Following the power station exchange with FirstEnergy, we own the operating generating units listed in the following table. We anticipate selling all of these units to Orion in the second quarter of 2000. (See "Rate Matters," Note F, on page 27.)
(a) Acquired from FirstEnergy in the December 3, 1999 power station exchange.
Orion also will acquire our ownership interest in cold-reserved generating units at Brunot Island Unit 4 and Phillips Power Station, with a combined capacity of approximately 450 MW.
D. LONG-TERM INVESTMENTS
We have made equity investments in affordable housing and gas reserve partnerships as a limited partner. At December 31, 1999, we had investments in 11 affordable housing funds and 26 gas reserve sites. In 1999, we invested $8.2 million to acquire a 50 percent interest in a joint venture that designs, engineers and constructs landfill gas collection systems. We are the lessor in 7 leveraged lease arrangements involving mining equipment, fossil generating stations, waste-to-energy facilities, high speed service ferries and natural gas processing equipment. These leases expire in various years beginning in 2011 through 2037. The recorded residual value of the equipment at the end of the lease terms is approximately one percent of the original cost. Our 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 $944 million and $992 million at December 31, 1999 and 1998.
Our other leases include investments in fossil generating stations, a waste- to-energy facility, computers, vehicles and equipment. Our other investments are primarily in marketable securities. Deferred income, as shown on the consolidated balance sheet, primarily relates to our other lease investments and certain gas reserve investments. Deferred amounts will be recognized as income over the lives of the underlying investments for periods not exceeding 15 years from the time of investment.
E. ACQUISITIONS
Through December 31, 1999, we had invested approximately $305 million for AquaSource to acquire the stock or assets of water and water-related companies through the purchase method of accounting. Approximately $43 million was in the form of Preferred Stock, Series A (Convertible), $100 liquidation preference per share (DQE Preferred Stock).
In 1999, DQE Systems invested approximately $63 million in the acquisition of 18 propane delivery companies in five states. These companies serve approximately 71,000 customers. With respect to propane delivery company acquisitions, we are implementing an aggregation strategy similar to that used by AquaSource.
F. RATE MATTERS
Competition and the Customer Choice Act
Under Pennsylvania 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 process, utilities had assets recorded on their balance sheets at above-market costs, thus creating transition costs.
The Customer Choice Act (effective January 1, 1997) enables Pennsylvania's electric utility customers to purchase electricity at market prices from a variety of electric generation suppliers (customer choice). As of January 2000, all customers have customer choice. As of February 29, 2000, approximately 23 percent of Duquesne Light's customers had chosen alternative generation suppliers, representing approximately 30 percent of Duquesne Light's non- coincident peak load. Customers who have chosen an electricity generation supplier other than Duquesne Light pay that supplier for generation charges, and pay Duquesne Light the CTC (discussed below) and charges for transmission and distribution. Customers who continue to buy their generation from Duquesne Light pay for their service at current regulated tariff rates divided into generation, transmission and distribution charges, and the CTC. Electricity delivery (including transmission, distribution and customer service) remains regulated in substantially the same manner as under historical regulation.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, was originally imposed on the transmission and distribution charges of Pennsylvania electric utility companies under the Customer Choice Act. As part of a settlement regarding recovery of deferred fuel costs (discussed below), we have agreed to extend this rate cap for an additional six months through the end of 2001.
Provider of Last Resort
Duquesne Light is required not only to deliver electricity, but also to serve as the provider of last resort for all customers in its service territory. As the provider of last resort, Duquesne Light must provide electricity for any customer who cannot or does not choose an alternative electric generation supplier, or whose supplier fails to deliver. While collecting the CTC, Duquesne Light may charge only PUC-approved rates for the supply of electricity as the provider of last resort. As part of the pending generation asset sale, Orion has agreed to supply Duquesne Light, under a provider of last resort service agreement, with all of the electric energy necessary to satisfy Duquesne Light's provider of last resort obligations during the CTC collection period. Under the Customer Choice Act, after the CTC collection period Duquesne Light anticipates that it will supply electricity at market prices to fulfill its provider of last resort obligations.
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that Duquesne Light should recover most of the above-market costs of its generation assets, including plant and regulatory assets, through the collection of the CTC from electric utility customers. The $1.49 billion of transition costs, net of tax, was originally to be recovered over a seven-year period ending in 2005. However, by applying expected net proceeds of the pending generation asset sale to Orion (discussed below) to reduce transition costs, we currently anticipate early termination of the CTC collection period in 2001 for most major rate classes. In addition, the transition costs as reflected on the consolidated balance sheet are being amortized over the same period that the CTC revenues are being recognized. Duquesne Light is allowed to earn an 11 percent pre-tax return on the unrecovered, net of tax balance of transition costs, as adjusted following the generation asset sale.
As part of our restructuring plan filing, we 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. We also requested recovery of an additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. Although the PUC initially denied recovery of this additional amount, on October 26, 1999, Duquesne Light and the Pennsylvania Office of the Consumer Advocate reached a settlement on this issue which would permit recovery of the entire $42.7 million ($24.9 million, net of tax) in deferred fuel costs. The PUC approved this settlement on February 11, 2000.
On December 18, 1998, the PUC approved Duquesne Light's auction plan, which included an auction of its provider of last resort service obligations, as well as an agreement to carry out the power station exchange with FirstEnergy.
Power Station Exchange. On December 3, 1999, Duquesne Light completed the exchange of its partial interests in five power plants for three wholly owned power plants of subsidiaries of FirstEnergy. Duquesne Light received three fossil-powered plants (located in Avon Lake and Niles, Ohio, and in New Castle, Pennsylvania) having an aggregate net demonstrated capacity of 1,323 MW. The ownership interests transferred by Duquesne Light included its interests in the nuclear-powered Beaver Valley, Pennsylvania and Perry, Ohio plants, and the fossil-powered Bruce Mansfield, Pennsylvania and Sammis and Eastlake, Ohio plants, having an aggregate net demonstrated capacity of 1,435 MW. Along with ownership of the nuclear-powered plants, FirstEnergy assumed the decommissioning liability for Beaver Valley and Perry, in exchange for the fully funded balance in decommissioning trust funds previously maintained by Duquesne Light. During 1999, we funded approximately $60 million into the decommissioning trusts. These amounts, which were collected through the CTC during the year, brought the fund balances to approximately $122 million. In connection with the power station exchange, we terminated the Beaver Valley Unit 2 lease in the fourth quarter of 1999. (See "Leases," Note I, on page 30.)
Auction Plan. On September 24, 1999, Duquesne Light and the winning auction bidder, Orion, entered into definitive agreements pursuant to which Orion will purchase Duquesne Light's wholly owned Cheswick, Elrama, Phillips and Brunot Island power stations, and the stations received from FirstEnergy in the power station exchange, for approximately $1.71 billion (estimated to be $1.1 billion, net of tax and transaction expenses). Under a provider of last resort service agreement, Orion will supply Duquesne Light with all of the electric energy necessary to satisfy Duquesne Light's obligations to its customers who have not chosen an alternative electric generation supplier. This agreement, which expires upon Duquesne Light's final collection of the CTC, in general effectively transfers to Orion the financial risks and rewards associated with Duquesne Light's provider of last resort obligations. While we retain the collection risk for the electricity sales, a component of our regulated delivery rates is designed to cover the cost of a normal level of uncollectible accounts. Duquesne Light and Orion are currently discussing an extension of this provider of last resort arrangement beyond the final CTC collection.
The Orion transactions must be approved by various regulatory agencies, including the PUC, the FERC, and the
Federal Trade Commission. Duquesne Light currently expects the sale to close in the second quarter of 2000. The final accounting for the sale proceeds remains subject to PUC approval. Through December 31, 1999, we have deferred approximately $219 million of costs related to the power station exchange and the asset sale. Additional divestiture-related costs will be deferred as incurred. We expect to fully recover these costs through the divestiture process; however, any disallowed costs will be written off.
Until the divestiture is complete, Duquesne Light is required to use an interim CTC and price to compare for each rate class (approximately 2.9 cents per KWH on average for the CTC, and approximately 3.8 cents per KWH on average for the price to compare).
Termination of the AYE Merger
On October 5, 1998, we announced our unilateral termination of our merger agreement with Allegheny Energy, Inc. (AYE). AYE filed suit in the United States District Court for the Western District of Pennsylvania, seeking to compel us to proceed with the merger, or in the alternative seeking an unspecified amount of money damages. After holding a trial from October 20 through 28, 1999, the District Court ruled on December 3, 1999, that we had properly terminated the merger agreement without breach, and granted judgment in our favor on all claims and all requests for injunctive relief. On December 14, 1999, AYE appealed this ruling to the Third Circuit. Argument was heard on March 9, 2000, and a decision is pending. We cannot determine the ultimate outcome of AYE's appeal at this time.
G. SHORT-TERM BORROWING AND REVOLVING CREDIT ARRANGEMENTS
We maintain two separate revolving credit agreements, one for $250 million expiring in June 2000 and one for $225 million expiring in September 2000. We have the option to convert each revolver into a term loan facility for a period of one or two years, respectively, for any amounts then outstanding upon expiration of the revolving credit period. Interest rates can, in accordance with the option selected at the time of the borrowing, be based on one of several indicators, including prime, Eurodollar, or certificate of deposit rates. Facility fees are based on the unborrowed amount of the commitment. At December 31, 1999 and 1998, no borrowings were outstanding. Related to these and other credit facilities, we are subject to financial covenants requiring certain cash coverage and debt-to-capital ratios to use these facilities. At year-end, we had $343 million of commercial paper borrowings outstanding. During 1999, the maximum amount of bank loans and commercial paper borrowings outstanding was $368.9 million, the amount of average daily borrowings was $46.3 million, and the weighted average daily interest rate was 5.6 percent. In the fourth quarter of 1999, we issued $290 million of first mortgage bonds with a one-year term, callable in May 2000. The interest rate on the bonds is 6.53 percent.
H. INCOME TAXES
The annual federal corporate income tax returns have been audited by the Internal Revenue Service (IRS) and are closed for the tax years through 1992. The IRS is auditing our 1993 through 1997 returns, and the tax years 1998 and 1999 remain subject to IRS review. We do not believe that final settlement of the federal income tax returns for the years 1993 through 1999 will have a materially adverse effect on our financial position, results of operations or cash flows.
Total income taxes differ from the amount computed by applying the statutory federal income tax rate to income before income taxes, as set forth in the following table.
I. LEASES
We lease office buildings, computer equipment, and other property and equipment. For most of 1999, we also leased nuclear fuel and a portion of Beaver Valley Unit 2.
(a) Includes $1,746 in 1999 and $2,037 in 1998 of capital leases with associated obligations retired.
In 1987, Duquesne Light sold and leased back its 13.74 percent interest in Beaver Valley Unit 2; the sale was exclusive of transmission and common facilities. In conjunction with the PUC restructuring order, it was determined that costs related to the lease were transition costs to be recovered through the CTC. Duquesne Light terminated the lease in connection with the power station exchange with FirstEnergy. The lease liability recorded on the consolidated balance sheet was eliminated; however, the underlying collateralized lease bonds ($359.2 million upon lease termination) became obligations of Duquesne Light, and are now recorded as debt on the consolidated balance sheet. (See "Power Station Exchange" discussion, Note F, on page 28.)
(a) Includes current obligations of $.07 million at December 31, 1999.
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 building leases.
Future payments due to us as of December 31, 1999, under subleases of certain corporate office space, are approximately $6.1 million in 2000, $6.1 million in 2001 and $6.6 million thereafter.
J. COMMITMENTS AND CONTINGENCIES
We anticipate completing the divestiture of our generation assets through the pending generation asset sale to Orion in the second quarter of 2000. Certain obligations related to the divested assets will be transferred to Orion upon completion of that sale. (See "Restructuring Plan" discussion, Note F, on page 28.)
Construction, Investments and Acquisitions
We estimate that we will spend, excluding AFC, approximately $85 million (including $5 million for generation), $75 million and $75 million in 2000, 2001 and 2002 for electric utility construction; and $45 million, $19 million and $24 million for water utility construction in 2000, 2001 and 2002.
Guarantees
As part of our investment portfolio in affordable housing, we have 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, we believe that such deferrals are ample for this purpose.
Employees
Duquesne Light is party to a labor contract expiring in September 2001 with the International Brotherhood of Electrical Workers (IBEW), which represents the majority of Duquesne Light's employees. The contract provides, among other things, employment security, income protection and, in September 2000, a 3 percent wage increase. Duquesne Light and the IBEW have agreed on a package of additional benefits and protections for union employees affected by the divestiture of generation assets.
In connection with the power station exchange with FirstEnergy and the pending generation asset sale to Orion, Duquesne Light developed early retirement programs and enhanced available separation packages for eligible IBEW and management employees. Duquesne Light expects to recover related costs through the sale proceeds.
Other
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. We have assessed our residual waste management sites, and the DEP has approved our compliance strategies. We incurred capital costs of $0.5 million in 1999 to comply with these DEP regulations. We expect the capital cost of compliance to be approximately $5.0 million over the next two years with respect to sites we will continue to own after the generation asset sale. We are seeking to recover these costs through the generation asset sale proceeds.
Duquesne Light's current estimated liability for closing Warwick Mine, including final site reclamation, mine water treatment and certain labor liabilities, is $49.3 million. Duquesne Light has recorded a liability for this amount on the consolidated balance sheet.
We are involved in various other legal proceedings and environmental matters. We believe that such proceedings and matters, in total, will not have a materially adverse effect on our financial position, results of operations or cash flows.
K. LONG-TERM DEBT
(a) Includes $100 million of first mortgage bonds not callable until 2003. Redemption prices for 2000 range from par to a premium of 4.92%.
(b) Excludes $390 million related to current maturities during 2000, of which $290 million are first mortgage bonds issued in November 1999.
(c) Excludes $75.0 million related to current maturities during 1999.
(d) The pollution control notes have adjustable interest rates. The interest rates at year-end averaged 3.8 percent in 1999 and 3.9 percent in 1998.
(e) Excludes $9.1 million related to current maturities during 2000.
(f) Excludes $65 million related to current maturities during 2000.
At December 31, 1999, sinking fund requirements and maturities of long-term debt outstanding for the next five years were $175.1 million in 2000, $95.3 million in 2001, $11.8 million in 2002, $116.2 million in 2003, and $118.3 million in 2004.
Total interest and other charges were $158.7 million in 1999, $109.5 million in 1998 and $115.6 million in 1997. Interest costs attributable to debt were $107.7 million, $95.0 million and $101.2 million in 1999, 1998 and 1997, respectively. Of these amounts, $0.8 million in 1999, $2.2 million in 1998 and $2.3 million in 1997 were capitalized as AFC. Debt discount or premium and related issuance expenses are amortized over the lives of the applicable issues. Interest and other charges in 1999 also includes $35.2 million related to the Beaver Valley Unit 2 lease expense, previously classified as other operating expenses.
At December 31, 1999, the fair value of 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 for debt of the same remaining maturities, was $2,089.3 million. The principal amount included in the consolidated balance sheet is $2,108.2 million.
At December 31, 1999 and 1998, we were in compliance with all of our debt covenants.
L. PREFERRED AND PREFERENCE STOCK
(a) 1,000,000 authorized shares; no par value; convertible; $100 liquidation preference per share; annual dividends range from 3.4 percent to 4.4 percent
(b) 4,000,000 authorized shares; $50 par value; cumulative; $50 per share involuntary liquidation value
(c) 500 authorized shares; $300,000 par value; these shares were redeemed at par value on March 2, 2000
(d) Cumulative Monthly Income Preferred Securities, Series A (MIPS); 6,000,000 authorized shares; $25 involuntary liquidation value
(e) 1,500 authorized shares; $100,000 par value; $100,000 involuntary liquidation value; holders entitled to 6.5 percent annual dividend each September
(f) Preferred stock: 100 authorized shares; $50,000 par value; $50,000 per share involuntary liquidation value; holders entitled to 6.5 percent annual dividend each September
(g) Preference stock: 8,000,000 authorized shares; $1 par value; cumulative $35.50 per share involuntary liquidation value; non-redeemable
As of December 31, 1999, 421,702 shares of DQE Preferred Stock had been issued and were outstanding. No additional shares have been issued in 2000. The DQE Preferred Stock ranks senior to DQE's common stock as to the payment of dividends and the distribution of assets on liquidations, dissolution or winding-up of DQE. Dividends are paid quarterly on each January 1, April 1, July 1 and October 1. 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 our 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.
In May 1996, Duquesne Capital L.P. (Duquesne Capital), a special-purpose limited partnership of which Duquesne Light 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 Light's 8 3/8 percent debentures. These debt securities may be redeemed at Duquesne Light's option on or after May 31, 2001. Duquesne Light has guaranteed the payment of distributions on, and redemption price and liquidation amount in respect of the MIPS, if 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.
Holders of Duquesne Light'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 Light's board of directors until all dividends have been paid. Holders of Duquesne Light'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 Light's directors until all dividends have been paid. At December 31, 1999, Duquesne Light had made all dividend payments. Preferred and preference dividends of subsidiaries included in interest and other charges were $16.6 million, $16.7 million and $16.7 million in 1999, 1998 and 1997. Total preferred and preference stock had involuntary liquidation values of $285.3 million and $278.4 million, which exceeded par by $26.9 million at December 31, 1999 and 1998.
In December 1991, we 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 34.) We issued and sold 845,070 shares of preference stock, plan series A, to the trustee of the ESOP. As consideration for the stock, we 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, 1999, $10.9 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 DQE are used to fund the repayment of the ESOP note. We were not required to make a cash contribution for 1998. We made cash contributions of approximately $0.2 million for 1999 and $1.1 million for 1997. These cash contributions were the difference between the ESOP debt service and the amount of dividends on ESOP shares ($2.1 million in 1999, $2.2 million in 1998 and $2.3 million in 1997). As shares of preference stock are allocated to the accounts of participants in the ESOP, we recognize compensation expense, and the amount of the deferred compensation benefit is amortized. We recognized compensation expense related to the 401(k) plans of $3.6 million in 1999, $1.6 million in 1998 and $3.2 million in 1997. 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 Light preferred or preference stock issues has mandatory purchase requirements.
M. EQUITY
We have continuously paid dividends on common stock since 1953. Our annualized dividends per share were $1.60, $1.52 and $1.44 at December 31, 1999, 1998 and 1997. During 1999, we paid a quarterly dividend of $0.38 per share on January 1, April 1, July 1 and October 1. We increased the quarterly dividend declared in the fourth quarter of 1999 from $0.38 to $0.40 per share, payable January 1, 2000. During 1998, we paid a quarterly dividend of $0.36.
Once all dividends on DQE Preferred Stock have been paid, dividends may be paid on our common stock as permitted by law and as declared by the board of directors. However, payments of dividends on Duquesne Light's common stock may be restricted by Duquesne Light's obligations to holders of preferred and preference stock, pursuant to Duquesne Light's Restated Articles of Incorporation, and by obligations of Duquesne Light's subsidiaries to holders of their preferred securities. No dividends or distributions may be made on Duquesne Light's common stock if Duquesne Light has not paid dividends or sinking fund obligations on its preferred or preference stock. Further, the aggregate amount of Duquesne Light'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. Because we own all of Duquesne Light's common stock, if Duquesne Light cannot pay common dividends, we may not be able to pay dividends on our common stock or DQE Preferred Stock. No part of the retained earnings of DQE was restricted at December 31, 1999.
Effective December 31, 1998, DQE adopted SFAS No. 130, Reporting Comprehensive Income. 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).
N. EMPLOYEE BENEFITS
Pension and Postretirement Benefits
We maintain retirement plans to provide pensions for all eligible employees. Upon retirement, an eligible 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. Our 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 $12.8 million for 1999, $12.0 million for 1998 and $12.7 million for 1997.
In 1999, we offered an early retirement program for certain employees affected by the generation asset divestiture. The total increase in the projected benefit obligation to the retirement plans is estimated to be $29.4 million. Of this amount, $17.4 million is recognized as special termination benefits in the table on page 35. The remaining $12.0 million is reflected in the unrecognized actuarial gain/loss account in the table.
In addition to pension benefits, we provide 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. Health care benefits terminate when covered individuals become eligible for Medicare benefits or reach age 65, whichever comes first. We fund actual expenditures for obligations under the plans on a "pay-as-you-go" basis. We have the right to modify or terminate the plans.
We accrue 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. We have elected to amortize the transition obligation over a 20-year period.
We sponsor several qualified and nonqualified pension plans and other postretirement benefit plans for our 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, 1999, a statement of the funded status as of December 31, 1999 and 1998, and summary of assumptions used in the measurement of our benefit obligation:
All of our plans for postretirement benefits, other than pensions, have no plan assets. The aggregate benefit obligation for those plans was $58.2 million as of December 31, 1999, and $46.4 million as of December 31, 1998. 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.
In 1999, we offered an early retirement program for certain employees affected by the generation asset divestiture. The total increase in the projected benefit obligation of the postretirement benefits is estimated to be $4 million. This increase is reflected in the unrecognized actuarial gain/loss account in the above table.
Pension assets consist primarily of common stocks exclusive of DQE common stock, United States obligations and corporate debt securities.
Retirement Savings Plan and Other Benefit Options
We sponsor separate 401(k) retirement plans for our management and IBEW- represented employees.
The 401(k) Retirement Savings Plan for Management Employees provides that we match employee contributions to a 401(k) account up to a maximum of six percent of an employee's eligible salary. Our 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. In 1999, more than 60 percent of management employees achieved their incentive targets. We are funding our 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 32.)
The 401(k) Retirement Savings Plan for IBEW-Represented Employees provides that we will match employee contributions to a 401(k) account up to a maximum of four percent of an employee's eligible salary. Our 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 1999, all IBEW-represented employees achieved their incentive targets.
Our shareholders have approved a long-term incentive plan through which we may grant management employees options to purchase, during the years 1987 through 2006, up to a total of 9.9 million shares of DQE common stock at prices equal to the fair market value of such stock on the dates the options were granted. At December 31, 1999, approximately 3.7 million of these shares were available for future grants.
As of December 31, 1999, 1998 and 1997, active grants totaled 1,031,434; 1,230,946 and 1,084,041 shares. Exercise prices of these options ranged from $17.5834 to $43.4375 at December 31, 1999; from $15.8334 to $43.4375 at December 31, 1998; and from $15.8334 to $33.7813 at December 31, 1997. Expiration dates of these grants ranged from 2001 to 2009 at December 31, 1999; from 2000 to 2008 at December 31, 1998; and from 2000 to 2007 at December 31, 1997. As of December 31, 1999, 1998 and 1997, stock appreciation rights (SARs) had been granted in connection with 933,014; 867,104 and 635,995 of the options outstanding. During 1999, 45,265 SARs were exercised; 254,225 options were exercised at prices ranging from $17.5834 to $35.0625; and 33,000 options were cancelled. 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. Of the active grants at December 31, 1999, 1998 and 1997, 132,105; 750,463; and 402,816 were not exercisable.
O. BUSINESS SEGMENTS AND RELATED INFORMATION
We report our results by the following four principal business segments, determined by products, services and regulatory environment: (1) the transmission and distribution by Duquesne Light of electricity (electricity delivery business segment), (2) the supply by Duquesne Light of electricity (electricity supply business segment), (3) the collection by Duquesne Light of transition costs (CTC business segment), and (4) the distribution by AquaSource of water (water distribution business segment). We also report an "all other" category, which includes our expanded business lines and Duquesne Light investments below the quantitative threshold for separate disclosure.
P. NON-CASH INVESTING AND FINANCING ACTIVITIES
Q. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The earnings in the following table include per share gains in 1999 of $.04 on a leveraged lease investment in the first quarter, and $.06, $.16 and $.06 from real estate sales in the second, third and fourth quarters, respectively. Additionally, included in the fourth quarter of 1999 is $.20 per share in earnings related to accounting for transition cost recovery. This earnings increase primarily relates to synchronizing the beginning of the transition cost recovery period with the functional unbundling of customer bills and the application of specific customer rates to the collection of transition cost. The final PUC approval of Duquesne Light's transition cost accounting is anticipated during the third quarter of 2000.
(a) Restated to conform with 1999 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 our Directors is set forth in the Proxy Statement for the DQE Annual Meeting of Shareholders to be held May 25, 2000. The information is incorporated here by reference. 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 May 25, 2000. 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 our 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 May 25, 2000. Information is incorporated here by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a)(1) The following information is set forth here in Item 8 (Consolidated Financial Statements and Supplementary Data) on pages 18 through 39 of this Report. The following financial statements and Report of Independent Auditors are incorporated here by reference:
Report of Independent Auditors.
Statement of Consolidated Income for the Three Years Ended December 31, 1999.
Consolidated Balance Sheet, December 31, 1998 and 1999.
Statement of Consolidated Cash Flows for the Three Years Ended December 31, 1999.
Statement of Consolidated Comprehensive Income for the Three Years Ended December 31, 1999.
Statement of Consolidated Retained Earnings for the Three Years Ended December 31, 1999.
Notes to Consolidated Financial Statements.
(a)(2) The following financial statement schedule and the related Report of Independent Auditors are filed here as a part of this Report:
Schedule for the Three Years Ended December 31, 1999:
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) We filed three reports on Form 8-K during the fiscal quarter ended December 31, 1999, and one to date in 2000.
A report was filed December 8, 1999, to report the judge's decision in favor of DQE in the AYE lawsuit regarding termination of the merger agreement. No financial statements were filed with this report.
A report was filed December 20, 1999, to report the power station exchange between Duquesne Light and FirstEnergy Corporation. No financial statements were filed with this report.
A report was filed December 27, 1999, to report certain earnings adjustments. No financial statements were filed with this report.
A report was filed February 1, 2000, to disclose information regarding DQE Enterprise's investments. No financial statements were filed with this report.
Exhibits Index
Copies of the exhibits listed above will be furnished, upon request, to holders or beneficial owners of any class of our stock as of February 29, 2000, 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, 1999, 1998 and 1997 (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 29, 2000 By: /s/ David D. Marshall -------------------------- (Signature) David D. Marshall Chairman, 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.