ITEM 1. BUSINESS.
CORPORATE STRUCTURE
Part I of this Annual Report on Form 10-K should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations, set forth in Part II, Item 7, and with our audited consolidated financial statements, set forth in Part II, Item 8.
Duquesne Light was formed in 1912 by the consolidation and merger of three constituent companies. We are engaged in the transmission and distribution of electric energy. We have been a wholly owned subsidiary of DQE, Inc. since its formation in 1989.
Our subsidiaries are primarily involved in operating our automated meter reading technology and providing financing to certain affiliates.
Service Area
Our operations provide service to approximately 587,000 direct customers in southwestern Pennsylvania (including in the City of Pittsburgh), a territory of approximately 800 square miles.
Regulation
We are subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). Our electric delivery business is also subject to regulation by the Pennsylvania Public Utility Commission (PUC) and the Federal Energy Regulatory Commission (FERC) with respect to rates for delivery of electric power, accounting and other matters.
Business Segments
This information is set forth in Item 7 under “Results of Operations” and in Note 18 to our consolidated financial statements.
FORWARD-LOOKING STATEMENTS
We use forward-looking statements in this report. Statements that are not historical facts are forward-looking statements, and are based on beliefs and assumptions of our management, and on information currently available to management. Forward-looking statements include statements preceded by, followed by or using such words as “believe,” “expect,” “anticipate,” “plan,” “estimate” or similar expressions. Such statements speak only as of the date they are made, and we undertake no obligation to update publicly any of them in light of new information or future events. Actual results may materially differ from those implied by forward-looking statements due to known and unknown risks and uncertainties, some of which are discussed below.
• Our earnings will be affected by the number of customers who choose to receive electric generation through POLR II, by final PUC approval of POLR III and by the continued performance of the generation supplier.
• Demand for electricity, changing market conditions and weather conditions could affect earnings levels.
• DQE’s cash flows, earnings, earnings growth, and board policy, as well as the effectiveness of its divestiture of non-core businesses and assets, could affect our earnings, financial position and cash flows.
• The ultimate structure of POLR III will be subject to PUC review and approval, as well as our ability to contract with suitable third-party suppliers.
• The final resolution of proposed adjustments regarding income tax liabilities could affect financial position, earnings and cash flows.
• The credit ratings we receive from the rating agencies will affect our cost of borrowing, our access to capital markets and liquidity.
• Overall performance could be affected by economic, competitive, regulatory, governmental and technological factors affecting operations, markets, products, services and prices, as well as the factors discussed in our SEC filings made to date.
EMPLOYEES
At December 31, 2002, we had 1,297 employees. We are party to a labor contract with the International Brotherhood of Electrical Workers, which represents 943 of our employees. The contract expires September 30, 2003.
ENVIRONMENTAL MATTERS
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. Following the generation asset divestiture,
we retained certain facilities which remain subject to these regulations. We have assessed our residual waste management sites, and the DEP has approved our compliance strategies. We expect the costs of compliance to be approximately $7.4 million with respect to sites we will continue to own. These costs are being recovered in the CTC, and the corresponding liability has been recorded for current and future obligations.
We own the closed Warwick Mine, located along the Monongahela River in Greene County, Pennsylvania. This property had been used in the electricity supply business segment. We have been selling unused portions of the property and will continue to do so. Our current estimated liability for closing the Warwick Mine, including final site reclamation, mine water treatment and certain labor liabilities, is approximately $30 million. We have recorded a liability for this amount on the consolidated balance sheets.
OTHER
Recent Accounting Pronouncements
In June 2001 the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Specifically, this standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The entity is required to capitalize the cost by increasing the carrying amount of the related long-lived asset. The capitalized cost is then depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. The standard is effective for fiscal years beginning after June 15, 2002. We do not believe that the adoption of SFAS No. 143 will have a significant impact on our financial statements.
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Task Force Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring).” SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred, rather than at the time of the commitment to a disposal or exit plan. This statement also establishes that the initial measurement of the liability should be at fair market value. This statement is effective for exit or disposal activities initiated after December 31, 2002. Initial adoption of this statement should have no impact on our financial statements, but SFAS No. 146 may affect the accounting treatment of any future disposal or exit activities.
Available Information
Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to these reports are available free of charge through the DQE website (www.dqe.com) when they become available on the SEC website.
EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below are the names, ages as of March 10, 2003, and positions during the past five years of our executive officers.
Victor A. Roque, age 56. President since October 2001. Previously Senior Vice President from November 1998 to April 2000; Vice President from April 1995 to October 1998; and General Counsel from November 1994 to April 2000. Executive Vice President of DQE since November 1998. Vice President of DQE from April 1995 until November 1998. General Counsel of DQE from November 1994 to October 2001. Secretary of DQE from May 2000 to October 2001.
Joseph G. Belechak, age 43. Senior Vice President - Operations and Customer Service since October 2001. Vice President, Asset Management & Operations from August 2000 to October 2001; General Manager, Asset Management and Best in Class Change Program Leader from 1999 to 2000; and Manager, Substations & Telecommunications from 1996 to 1999. Vice President - Operations and Customer Service of DQE since December 2002.
Maureen L. Hogel, age 42. Senior Vice President and Chief Administrative Officer since December 2002. Senior Vice President - Human Resources and Administration from October 2001 through November 2002; Vice President - Development, Legal and Administrative Affairs from January 2001 through October 2001; Vice President - Legal from September 1999 through December 2000 and Assistant General Counsel from February 1996 to September 1999. Senior Vice President and Chief Administrative Officer of DQE since December 2002.
William F. Fields, age 52. Vice President and Treasurer since December 2002. Assistant Treasurer from June 1991 to November 1998. At DQE Financial Corp.: President from April 2000; Vice President and Treasurer from August 1999 to March 2000; Treasurer from December 1997 to June 2001. At DQE: Vice President and Treasurer since December 2002.
Stevan R. Schott, age 40. Vice President and Controller since October 2001. Vice President - Finance and Customer Service from August 2000 to October 2001. Vice President and Controller from August 1999 to August 2000. Controller of DQE Financial from September 1998 to August 1999. Senior Manager, Public Utilities Specialist at Deloitte & Touche LLP from September 1993 to September 1998. Vice President and Controller of DQE since October 2001.
James E. Wilson, age 37. Vice President - Corporate Development and Rates since December 2002. Vice President - Corporate Development since October 2001. Vice President and Chief Accounting Officer from August 2000 to October 2001. Previously Controller from November 1998 to August 1999, and Assistant Controller from September 1996 to November 1998. At DQE: Vice President - Corporate Development and Rates since December 2002. Vice President - Corporate Development from October 2001 to December 2002. Controller from July 1999 to October 2001.
ITEM 2.
ITEM 2. PROPERTIES.
Our principal properties consist of electric transmission and distribution facilities and supplemental properties and appurtenances, located substantially in Allegheny and Beaver counties in southwestern Pennsylvania. Substantially all of the electric utility properties are subject to a lien under the Indenture of Mortgage and Deed of Trust, dated as of April 1, 1992.
In April 2000, we sold our generation assets. We own 9 transmission substations and 561 distribution substations (367 of which are located on customer-owned land and are used to service only that customer). We have 592 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 16,420 circuit-miles of lines and cable. These properties are used in the electricity delivery business segment.
Our total investment in property, plant and equipment (PP&E) and the related accumulated depreciation balances for major classes of property at December 31, 2002 and 2001 are as follows:
PP&E and Related Accumulated Depreciation
Electric delivery PP&E includes: (1) distribution poles and equipment; (2) lower voltage distribution wires used in delivering electricity to customers; (3) substations and transformers; (4) high voltage transmission wires used in delivering electricity from generating stations to substations; (5) internal telecommunication equipment, vehicles and office equipment; and (6) meters and automated meter reading assets, all used in our electricity delivery business segment.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
None.
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.
Our common stock is not publicly traded; DQE owns all 10 shares outstanding. We declared quarterly common stock dividends totaling $75.0 million in 2002 and $52.7 million in 2001.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(a) Total operating revenues have declined in 2002 due to the full collection of the allocated CTC balance for substantially all rate classes.
(b) Results have been negatively impacted by restructuring charges recorded in both 2001 and 2002. (See Note 4.)
(c) Adoption of unbilled revenues in 2000. (See Note 1.)
(d) Generation-related stranded costs not recoverable from customers.
(e) Total assets in 2000 were impacted by the sale of the generation assets.
(f) Net generation asset sale proceeds were used to reduce long-term debt in 2000.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
RESULTS OF OPERATIONS
Overall Performance
During 2002, over 550,000 of our residential, commercial and industrial customers experienced a reduction in their overall electric bills due to the elimination of the Competitive Transition Charge (CTC). Duquesne Light is the first electric utility in Pennsylvania to eliminate the CTC from customer bills. Following the collection of the CTC, we began operating under our extended provider of last resort arrangement (POLR II), which permits us to earn a margin per megawatt-hour (MWh) supplied, which enhances the long-term earnings stream from our core electric business.
During 2002, Pittsburgh experienced hotter than normal weather in the summer months, due to the third warmest summer on record in our nation’s history. This resulted in higher demand for cooling.
2002 Compared to 2001
Our earnings available for common stock were $72.1 million in 2002, consisting of $74.4 million before an after-tax restructuring charge of $2.3 million. This is compared to earnings of $50.0 million in 2001, consisting of $56.7 million before an after-tax restructuring charge of $6.7 million discussed below. During the fourth quarter of 2002, as a part of DQE’s
continuing Back-to-Basics strategy, we initiated a restructuring plan that focused primarily on executive levels of management to reduce expenses and improve efficiency and we recorded an after-tax restructuring charge of $2.3 million. (See Note 4.) Excluding the restructuring charges in both years, earnings available for common stock increased $17.7 million, or 31.2%. This increase is due to a number of factors, including:
• During 2002, we began operating under our new POLR II arrangement, which contributed $13.9 million to earnings in 2002, compared to zero in 2001.
• Pittsburgh experienced hotter than normal weather in the summer months, due to the third warmest summer on record in our nation’s history. This resulted in higher demand for cooling. The earnings impact on the electricity delivery business segment was approximately $5.4 million, compared to 2001.
• During August 2002, we retired $110 million of debt, which resulted in $2.0 million of additional earnings due to the decrease in interest expense. Furthermore, the interest rates on the variable rate debt were more favorable in 2002, resulting in additional interest savings.
• Our continued focus on cost reductions, including cost savings from our fourth quarter 2001 and 2002 corporate restructurings, contributed positively to earnings in 2002.
Partially offsetting the above factors is the $9.4 million decline in earnings from the CTC business segment from 2001 to 2002 following the full collection of the CTC balance for most of our customers in 2002.
2001 Compared to 2000
Our earnings available for common stock were $50.0 million in 2001, consisting of $56.7 million before an after-tax restructuring charge of $6.7 million. This is compared to $89.2 million in 2000, consisting of $73.7 million before the after-tax income of $15.5 million from the cumulative effect of a change in accounting principle. This is a decrease of $39.2 million, or 43.9%. The decrease in earnings from 2000 is primarily due to the $33.3 million decline in earnings relating to the CTC business segment (see discussion below). In the fourth quarter of 2001, as part of DQE’s Back-to-Basics strategy, we initiated a restructuring plan to improve operational effectiveness and efficiency, and to reduce operational expenses, and recorded a $6.7 million after-tax restructuring charge.
On January 1, 2000, we adopted the policy of recording unbilled customer revenues to better reflect the revenues generated from the amount of energy supplied and delivered to electric utility customers in a given accounting period. Previously, revenues from electric utility customers were recorded in the accounting period for which they were billed. Revenues recorded now reflect actual customer usage in an accounting period, regardless of when billed. The effect of this new policy is reflected as a $15.5 million cumulative effect of a change in accounting principle in 2000. This amount is shown net of tax and associated expenses.
Results Of Operations by Business Segment
We report the results of our business segments, determined by products, services and regulatory environment as follows: (1) transmission and distribution of electricity (electricity delivery business segment), (2) supply of electricity (electricity supply business segment), and (3) collection of transition costs (CTC business segment).
With the completion of our generation asset sale in April 2000, the electricity supply business segment is now comprised solely of POLR service.
2002 Compared to 2001
Electricity Delivery Business Segment. The electricity delivery business segment reported earnings for common stock of $55.3 million in 2002, consisting of $57.6 million before an after-tax restructuring charge of $2.3 million, as previously discussed. This is compared to $37.7 million of earnings for common stock in 2001, consisting of $44.4 million before an after-tax restructuring charge of $6.7 million. Excluding the restructuring charges in both years, earnings from the electricity delivery business segment were $13.2 million, or 29.7%, higher in 2002, due to the hotter than normal summer weather in 2002 and lower interest and operating costs, as discussed below.
Operating revenues for this business segment are primarily derived from the delivery of electricity, including related gross receipts taxes. Sales to residential and commercial customers are primarily 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 by national and global economic and competitive conditions.
Operating revenues increased by $30.4 million, or 9.5%, compared to 2001. The increase can be primarily attributed to a $15.9 million increase in 2002 in gross receipts taxes that are collected through revenue. The largest component increase was in the Pennsylvania revenue neutral reconciliation (RNR) tax rate, which became effective January 1, 2002. Electric distribution companies such as Duquesne Light are permitted to recover this cost from consumers on a current basis. In addition, there was a 5.1% increase in MWh sales to customers compared to 2001, which caused a $9.6 million increase in revenues.
The hotter than normal summer temperatures in the Pittsburgh region contributed to residential and commercial sales increasing 9.5% and 4.6%, compared to 2001, in response to higher cooling demands. Industrial sales, which are less sensitive to weather, also increased by 1.4%, due to higher sales to industrial customers in the primary metals sector. The following table sets forth MWh delivered to electric utility customers.
Operating expenses for the electricity delivery business segment are primarily made up of costs to operate and maintain the transmission and distribution system; meter reading, billing and collection costs; customer service; administrative expenses; income taxes; and non-income taxes, such as gross receipts, property and payroll taxes. Operating expenses increased by $20.3 million or 12.6% compared to 2001, primarily due to the increase in gross receipts tax expense of approximately $14 million from the increased RNR in 2002. In addition, there was an increase of approximately $11 million in income taxes in 2002 compared to 2001 due to the increase in pre-tax income from the electricity delivery business segment in 2002. These increases were partially offset by savings from our cost reduction initiatives, which continue to generate incremental cost savings, as well as our corporate restructurings that occurred in the fourth quarters of both 2002 and 2001.
Other income consists primarily of interest income from a loan receivable and our cash pool investment with DQE. Gains or losses resulting from the disposition of certain assets are also included here. Other income decreased $6.1 million, or 25.3%, compared to 2001, primarily due to lower interest rates in 2002.
Interest and other charges include interest on long-term debt, other interest and preferred stock dividends. In 2002, there was $6.0 million, or 7.7%, less interest and other charges primarily due to debt retirements during August 2002 totaling $110 million, which reduced interest expense by $3.4 million. The remaining decrease resulted from lower interest rates on the variable rate, tax-exempt debt in 2002.
Electricity Supply Business Segment. In 2002, the electricity supply business segment reported earnings for common stock of $13.9 million, compared with earnings of zero in 2001. For the period April 28, 2000 through December 31, 2001, this segment’s financial results reflected our initial POLR arrangement (POLR I), which was designed to be income neutral to Duquesne Light. During the first quarter of 2002, Duquesne Light began operating under POLR II, which extends the POLR service (and the PUC-approved rates for the supply of electricity) beyond the final CTC collection through December 31, 2004. POLR II also permits Duquesne Light, following CTC collection for each rate class, to earn an average margin per MWh supplied. The actual margin earned during 2002 averaged $4.77 per MWh based on the mix of rate classes, and number of customers, participating in POLR II.
Operating revenues for this business segment are derived primarily from the supply of electricity for delivery to retail customers and the supply of electricity to wholesale customers. Retail energy requirements fluctuate as the number of customers participating in customer choice changes. Energy requirements for residential and commercial customers are also influenced by weather conditions; temperature extremes 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 result primarily from excess daily energy deliveries to Duquesne Light’s electricity delivery system.
Operating revenues increased $41.9 million, or 9.7%, compared to 2001. The increase is due to an increase in the average
generation rate charged to customers, partially offset by a decrease in the percentage of customers who received electricity through our POLR arrangements.
The following table sets forth MWh supplied for POLR customers.
Operating expenses for the electricity supply business segment consist of costs to obtain energy for our POLR service and gross receipts tax, both of which fluctuate in direct relation to operating revenues. In 2002, operating expenses also include income taxes. Operating expenses increased $28.0 million, or 6.5%, compared to 2001, despite a decrease in the MWh supplied. The increase in expense is due to the higher rate charged by Orion under the POLR II arrangement, as well as income taxes of $9.7 million in 2002 as a result of the margin earned under the POLR II arrangement.
CTC Business Segment. In its final restructuring order issued in the second quarter of 1998, the PUC determined that we should recover most of the above-market costs of our generation assets, including plant and regulatory assets, through the collection of the competitive transition charge (CTC) from electric utility customers. On January 18, 2001, the PUC issued an order approving our final accounting for the proceeds of our April 2000 generation asset sale, including the net recovery of sale-related transaction costs.
For the CTC business segment, operating revenues are derived by billing electric delivery customers for generation-related transition costs. We are allowed to earn an 11% pre-tax return on the net of tax CTC balance. As revenues are billed to customers on a monthly basis, we amortize the CTC balance. The resulting decrease in the CTC balance causes a decline in the return we earn.
In 2002, the CTC business segment reported earnings for common stock of $2.9 million compared to earnings of $12.3 million in 2001, a decrease of $9.4 million, or 76.4%.
Operating revenues decreased $181.3 million, or 59.7%, due to the full collection of the allocated CTC balance as of December 31, 2002 for most of our customers as well as scheduled decreases in the average CTC rate charged to customers from 2001 to 2002. As of December 31, 2002, the CTC balance has been fully collected for approximately 95% of Duquesne Light’s customers, representing approximately 87% of the MWh sales for the year.
Operating expenses consist of gross receipts tax and income taxes, which fluctuate in direct relation to operating revenues and pre-tax earnings. Operating expenses decreased $13.2 million, or 65.7%. Gross receipts tax decreased $8.1 million due to the decrease in operating revenues, while income taxes decreased $5.1 million due to the decrease in the return earned on the CTC in 2002.
Depreciation and amortization expense consists of the amortization of transition costs. There was a decrease of $158.7 million, or 58.5%, compared to 2001, primarily due to the full collection of the allocated CTC balance for most customers, as described above.
2001 Compared to 2000
Electricity Delivery Business Segment. The electricity delivery business segment reported earnings for common stock of $37.7 million in 2001, consisting of $44.4 million before an after-tax restructuring charge of $6.7 million, as previously discussed. This is compared to earnings of $43.4 million in 2000, which included $7.3 million of after-tax income related to the cumulative effect of a change in accounting principle for unbilled revenues, as previously discussed. Excluding the restructuring charge in 2001 and the cumulative effect of a change in accounting principle in 2000, earnings from the electricity delivery business segment were $8.3 million, or 23.0%, higher in 2001, primarily due to lower operating expenses resulting from the cost reduction initiatives that were begun in 2000.
Operating revenues increased by $3.5 million, or 1.1%, compared to 2000. Residential sales increased 2.1%, primarily due to warmer summer weather in 2001. Commercial sales increased 1.3%, due to an increase in the number of commercial customers, while industrial sales decreased 8.3%, due to decreased consumption by steel manufacturers, including one major customer who filed for protection under Chapter 11 of the U.S. Bankruptcy Code. The following table sets forth MWh delivered to electric utility customers.
Operating expenses decreased by $11.2 million, or 6.5%, compared to 2000, due to cost reduction initiatives that were begun in 2000, as well as a reduction to our employee pension costs. (See Note 13.)
Depreciation and amortization expense includes the depreciation of electricity delivery-related plant and equipment. There was an increase in depreciation and amortization expense of $3.3 million, or 5.9%, compared to 2000 due primarily to net additions to property, plant and equipment during 2001.
Other income increased $5.8 million, or 31.7%, compared to 2000, primarily due to increased interest income from higher cash pool balances in 2001.
In 2001, there was $8.9 million, or 12.8%, more interest and other charges allocated to the electricity delivery business segment compared to 2000. Although we used the generation asset sale proceeds to retire debt, thus reducing our overall level of interest expense, all financing costs after recapitalization are borne by the electricity delivery business segment.
Electricity Supply Business Segment. In 2001, the electricity supply business segment reported earnings for common stock of zero, compared with earnings of $0.2 million in 2000. For all of 2001, and for the period from April 29 through December 31, 2000, this segment’s financial results reflect POLR I, which is designed to be income neutral. Included in 2000 was $8.2 million of earnings related to the cumulative effect of a change in accounting principle for unbilled revenues, as previously discussed.
Short-term sales to other utilities are made at market rates. Prior to the April 2000 generation asset divestiture, fluctuations in such sales were related to customer energy requirements, the energy market and transmission conditions, and the availability of generating stations. Following the divestiture, fluctuations result primarily from excess daily energy deliveries to our electricity delivery system.
Operating revenues increased $4.9 million, or 1.2%, compared to 2000. The increase is due to an increase in the average generation rate charged to customers, as well as an increase in the percentage of customers who receive electricity through our POLR arrangement.
The following table sets forth MWh supplied for customers who have not chosen an alternative generation supplier.
Operating expenses for the electricity supply business segment from April 29, 2000, through 2001 consist of costs to obtain energy under our POLR I arrangement and gross receipts tax, both of which fluctuate in direct relation to operating revenues. Prior to April 29, 2000, such operating expenses included energy costs; costs to operate and maintain the power stations; administrative expenses; income taxes; and non-income taxes, such as gross receipts, property and payroll taxes.
Fluctuations in energy costs in 2001 resulted from total MWh supplied through our POLR I arrangement. Fluctuations in energy costs in 2000 generally resulted from changes in the total MWh supplied, the mix between coal generated power and purchased power, the cost of fuel, and generating station availability.
Operating expenses increased $17.5 million, or 4.2%, from 2000 as a result of an increase in the MWh supplied. This increase resulted from higher purchased power costs (related to POLR I) following the generation asset sale, as opposed to the cost of power generated by our previously owned power stations. The cost under POLR I averaged $4.00 per MWh across all rate classes.
Depreciation and amortization expense in 2000 included the depreciation of the power stations’ plant and equipment through the generation asset sale.
Other income decreased $2.8 million from 2000, because no other income has been allocated to this business segment since the generation asset sale.
In 2001, no interest expense was allocated to this business segment; in 2000, there was $21.2 million of allocated interest expense. All remaining financing costs following the generation asset sale are borne by the electricity delivery business segment.
CTC Business Segment. In 2001, the CTC business segment reported earnings for common stock of $12.3 million compared to earnings of $45.6 million in 2000, a decrease of $33.3 million, or 73.0%.
Operating revenues decreased $30.7 million, or 9.2%, from 2000, due to scheduled decreases in the average CTC rate charged to customers from 2000 to 2001.
Operating expenses decreased $19.1 million, or 48.7%, from 2000. Gross receipts tax decreased $1.2 million from 2000 due to the decrease in operating revenues, while income taxes decreased $17.9 million due to the decrease in the return earned on the CTC in 2001.
As a result of the lower average CTC balance, there was less return earned in 2001. Accordingly, there was an increase in depreciation and amortization expense of $21.7 million, or 8.7%, compared to 2000.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions with respect to values and conditions 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 we are required to make. We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates.
In preparing our financial statements and related disclosures, we have adopted the following accounting policies which management believes are particularly important to the financial statements and that require the use of estimates and assumptions in the financial preparation process.
Accounting for the Effects of Regulation. We prepare our financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which differs in certain respects from the application of accounting principles generally accepted in the United States of America by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) if it is probable that, through the rate-making process, there will be a corresponding increase in future rates. Accordingly, we defer certain costs, which will be amortized over future periods. To the extent that collection of such costs is no longer probable as a result of changes in regulation or our competitive position, the associated regulatory assets are charged to expense.
Unbilled Energy Revenues. We record revenues related to the sale of energy when delivery is made to our customers. However, the determination of such sales to individual customers is based on the reading of their meters, which we read on a systematic basis throughout the month. At the end of each month, we estimate the amounts delivered to customers since the date of the last meter reading and record the corresponding unbilled revenue. We estimate this unbilled revenue each month based on daily volumes, estimated customer usage by class, delivery losses and applicable customer rates based on regression analyses reflecting significant historical trends and experience. Customer accounts receivable as of December 31, 2002, and 2001, include unbilled revenues of $31.9 million and $36.9 million.
Pension and Other Postretirement Benefit Plan Assumptions. We provide pension benefit plans covering substantially all of our full-time employees. We also provide postretirement benefits for some retired employees. The post-retirement medical benefits terminate when retirees reach age 65. We account for these benefits in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” We record amounts related to our pension and other postretirement benefit plans based on actuarial valuations. Inherent in those valuations are key assumptions including discount rates, expected returns on plan assets, compensation increases, and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. Changes in these assumptions could have a significant effect on our noncash pension income or expense or on our postretirement benefit costs. The effect of changes in these assumptions is
generally recorded or amortized over future periods.
We discounted our future pension and other postretirement plan obligations using a rate of 6.75% as of December 31, 2002, compared to 7.25% as of December 31, 2001. We determine the discount rate by considering the yield rates on corporate high-grade bonds, including relative year-over-year changes. Both the pension and other postretirement plan obligations and related expense increase as the discount rate is reduced.
The assumed rate of return on plan assets in the pension plans is the weighted average of long-term returns forecast for the type of investments held by the plans. As the expected rate of return on plan assets decreases, the pension plan expense increases, however the postretirement plan expense is unaffected as this plan has no assets. The health care trend assumption used in the development of the fiscal 2002 postretirement benefit plan expense was 11.0% for fiscal year 2002, decreasing to an ultimate rate of 5.75% in 2013. Assumed health care cost trend rates have a significant effect on the liabilities for the postretirement plans.
We believe the assumptions used in recording obligations under the plans are reasonable based on our prior experience, market conditions, and the advice of plan actuaries. See Note 13 for information about these assumptions, actual performance, amortization of investment and other actuarial gains and losses and calculated plan costs for 2002, 2001 and 2000. As of December 31, 2002, the projected benefit obligations for our retirement plans exceeded the fair value of the plan assets in the trusts.
Primarily because of the amortization of previous years’ net investment gains, our pension expense for 2002, 2001 and 2000 was negative, resulting in an increase in net income in each year. Our expense or (credit) for actual pension benefits in future periods will depend upon actual returns on plan assets and the key assumptions we use for future periods. Our current estimate for 2003 is a reduction, compared to 2002, in the pension benefits net credit of $14.3 million pre-tax. This reduction reflects, among other factors, actual losses on the pension fund assets of $43.8 million in 2002 and $35.1 million in 2001, compared with an expected annual asset return assumption of 7.5% in each of the years. Absent a substantial recovery in the equity markets, pension costs and cash funding requirements could substantially increase in future years. Pursuant to the actuarial valuations that were performed, we were not required to make cash contributions to our pension plans in 2002, nor will we be required to do so in 2003. However, we have an obligation to contribute approximately $32.1 million to the pension plans over future years. (See Note 13.)
Income Taxes. In accordance with SFAS No. 109, “Accounting for Income Taxes,” we use the liability method in computing deferred taxes on all differences between book and tax bases of assets and liabilities. 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.
We file a consolidated U.S. federal income tax return with DQE and other companies in the affiliated group, all of whom participate in an intercompany tax sharing agreement which generally provides that taxable income for each DQE subsidiary be calculated as if it filed a separate return.
For the electricity delivery business segment, we recognize a regulatory asset for deferred tax liabilities that are expected to be recovered through rates. The difference in the provision for deferred income taxes related to depreciation of electric plant in service and the amount that otherwise would be recorded under generally accepted accounting principles is deferred and included in regulatory assets on the consolidated balance sheets. (See Note 1.)
Contingent Liabilities. We establish reserves for estimated loss contingencies when it is management’s assessment that a loss is probable and the amount can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known, or circumstances change, that affect the previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon management’s assumptions and estimates, advice of legal counsel, or other third parties regarding the probable outcomes of the matter. Should the ultimate outcome differ from the assumptions and estimates, revisions to the estimated reserves for contingent liabilities would be recognized. Such contingent liabilities include, but are not limited to, restructuring liabilities (see Note 4), income tax matters (see Note 10), and other commitments and contingencies (see Note 12).
LIQUIDITY AND CAPITAL RESOURCES
We do not currently have any off-balance sheet financing arrangements. We are not involved in any commodity contract trading activities. As a wholly owned subsidiary of DQE, we are involved in various transactions with affiliates. (See Notes 1 and 3.)
Dividends
DQE’s dividend policy requires subsidiaries to dividend their net income, if cash is available. See Notes 1 and 16 for more detailed discussion of our dividend policy.
Capital Expenditures
In 2002, 2001 and 2000, we spent approximately $72.5 million, $59.1 million and $89.8 million for electric utility construction. We estimate that during 2003, 2004 and 2005 we will spend, excluding the allowance for funds used during construction, approximately $70 million for electric utility construction in each year.
Asset Dispositions
In 2002 we received $1.3 million from the sale of a building and recognized an after-tax gain of $0.3 million. We also received $1.3 million of proceeds from the sale of securities and recognized an after-tax gain of $0.8 million.
In 2001, we sold a portion of our affordable housing portfolio, receiving proceeds of approximately $3.4 million, which approximated book value. We also sold property and recognized a gain of approximately $1.6 million.
In 2000, we completed the sale of our generation assets for approximately $1.7 billion. We also purchased the automated electronic meter-reading system, which had previously been leased, for $32 million.
Financing
In September 2002, we converted approximately $98 million of variable rate debt to fixed rate with maturities in 2011 and 2013, resulting in a weighted average interest rate of 4.20%.
On August 5, 2002, we redeemed the following: (i) $10 million aggregate principal amount of 8.20% first mortgage bonds due 2022 at a redemption price of 104.51% of the principal amount thereof, and (ii) $100 million aggregate principal amount of 7 5/8% first mortgage bonds due 2023 at a redemption price of 103.9458% of the principal amount thereof.
On April 15, 2002, we issued $200 million of 6.7% first mortgage bonds due 2012. On April 30, 2002, we issued $100 million of 6.7% first mortgage bonds due 2032. In each case we used the proceeds to call and refund existing debt, including debt scheduled to mature in 2003 and 2004.
In January 2002, we issued $125 million of commercial paper and loaned the proceeds to DQE. This debt was repaid and retired in full, leaving no outstanding balance at December 31, 2002.
Liquidity
In the first quarter of 2002, Moody’s Investor Service, Standard & Poor’s, and Fitch Ratings assessed our short and long-term credit profiles. The ratings reflect the agencies’ opinion of our overall financial strength. Ratings impact our ability to access capital markets for investment and capital requirements, as well as the relative costs related to such liquidity capability. In general, the agencies reduced our long-term credit ratings, although staying within the range considered to be investment grade. This ratings downgrade does not limit our ability to access our revolving credit facilities; it does, however, impact the cost of maintaining the credit facilities and the cost of any new debt. The agencies maintained the existing credit ratings for our short-term debt. These ratings are not a recommendation to buy, sell or hold any of our securities, may be subject to revisions or withdrawal by the agencies at any time, and should be evaluated independently of each other and any other rating that may be assigned to our securities.
We maintain a 364-day, $150 million revolving credit agreement, which expires in October 2003. At December 31, 2002 no borrowings were outstanding; however, we had $9.3 million in standby letters of credit, leaving $140.7 million available under the agreement.
Decreases in our credit ratings will result in an inverse change in the fees and interest rates charged. The revolving credit agreement is subject to cross-default if we default on any payment due under any other indebtedness exceeding $50 million.
Under the credit facility, we are subject to financial covenants requiring us to maintain a maximum debt-to-capitalization ratio of 65.0%. At December 31, 2002 we were in compliance with these covenants, having a debt-to-total-capitalization ratio of approximately 57%.
None of our long-term debt is scheduled to mature before 2008.
At December 31, 2002, we had no commercial paper borrowings outstanding, and no current debt maturities. During 2002, the maximum amount of bank loans and commercial paper borrowings outstanding at any date was
$125 million, the amount of average daily borrowings was $43.7 million, and the weighted average daily interest rate was 2.34%. We paid $67.7 million in dividends on capital stock.
At December 31, 2001, we had no current debt maturities, and no commercial paper borrowings outstanding. During 2001, there were no bank loans or commercial paper borrowings outstanding. We paid $56.2 million in dividends on capital stock.
In 2000, we retired $350 million of long-term bonds and $399 million of maturing bonds, using proceeds from the sale of generation assets. We paid $285.5 million in dividends on capital stock, including a special dividend of $200.0 million.
At December 31, 2000, we had $0.8 million of current debt maturities and no commercial paper borrowings outstanding. During 2000, the maximum amount of bank loans and commercial paper borrowings outstanding at any date was $189.5 million, the amount of average daily borrowings was $7.0 million, and the weighted average daily interest rate was 6.8%.
Contractual Obligations
As of December 31, 2002, we have certain contractual obligations and commitments that extend beyond 2003, the principal amounts of which are set forth in the following tables:
(a) Revolving credit agreements and standby letters of credit are typically for a 364-day period and are renewed annually. (See Note 9.)
(b) Surety bonds are renewed annually. Some of the commercial bonds cover regulatory and contractual obligations that exceed a one-year period.
RATE MATTERS
Competitive Transition Charge
Under Customer Choice, customers must choose to receive their electric energy from an alternative generation supplier or through our POLR arrangements. Customers who select an alternative generation supplier pay for generation charges set competitively by that supplier, and pay us transmission and distribution charges and the CTC (unless the CTC has already been collected for a customer’s rate class).
We have completed the CTC collection from most of our customers. As of December 31, 2002, the CTC balance has been fully collected for approximately 95% of customers, representing approximately 87% of the MWh sales for 2002. The transition costs, as reflected on the consolidated balance sheets, are being amortized over the same period that the CTC revenues are being recognized. For regulatory purposes, the unrecovered balance of transition costs was approximately $25 million ($15 million net of tax) at December 31, 2002, and approximately $142 million ($87 million net of tax) at December 31, 2001. We are allowed to earn an 11.0% pre-tax return on the net of tax CTC balance. A lower amount is shown on the consolidated balance sheets due to the accounting for unbilled revenues.
Provider of Last Resort
Orion Power Midwest (a subsidiary of Reliant Resources, Inc.) is our supplier under POLR I and POLR II. As discussed in “Results of Operations” above, POLR II extends through December 31, 2004 and permits us a margin per MWh supplied based on the mix of rate classes, and number of customers, participating in POLR II. For 2002, the average margin was $4.77 per MWh. Except for this margin, POLR I and POLR II, in general, effectively transfer to Orion the financial risks and rewards associated with our provider of last resort obligations. As of December 31, 2002, approximately 77% of our customers measured on a MWh basis received electricity through POLR I or POLR II. The number of POLR customers will fluctuate depending on market prices and the number of alternative generation suppliers in the retail supply business.
There are certain safeguards in POLR I and POLR II designed to mitigate losses in the event that Orion defaults on its performance under the arrangement. Contractually, we have various credit enhancements to address market exposure if Orion failed to deliver the required POLR supply. We hold an irrevocable $10 million letter of credit (that can be increased based on Orion’s investment ratings and net worth). We also remit the POLR customer payments 35 days after billing the customer. We have the right not to remit these payments in the event of an Orion default.
If Orion were to fail to deliver, we would be required to procure our POLR supply requirements in the energy markets. If market prices for energy were higher than the POLR rate at the time of default, we could potentially be acquiring energy for sale to POLR customers at a loss. If that were to happen and the contractual provisions with Orion were not sufficient to cover any loss, we would seek regulatory recovery of any additional loss. While the Customer Choice Act provides generally for POLR supply costs to be borne by customers, recent litigation suggests that it may not be clear whether we could pass any costs in excess of the existing PUC-approved POLR prices on to our customers. Additionally, Orion’s parent was downgraded by the rating agencies in 2002. To date, the downgrade has not affected Orion’s performance.
We are preparing POLR III, a rate plan and related generation supply plan intended to cover the period beginning in 2005. For our larger commercial and industrial customers (fewer than 1,000 customers but approximately 50% of the electricity consumption) the rate plan proposal is likely to include a market-based pilot program comprised of a choice between auction-based, fixed-price service and variable, real-time hourly price service. For our residential and small business customers, the proposal is likely to include a multi-year, fixed-price service option to offer protection from market volatility. We are evaluating, among other options, a contracting strategy for long-term POLR supply. We are actively engaged in discussions with potential suppliers in an effort to structure an arrangement with appropriate protections in the event of supplier default. Once the supply plan is finalized, we will submit POLR III for PUC approval. We expect to make the filing in mid-2003.
We retain the risk that customers will not pay for the POLR generation supply. However, a component of our delivery rate is designed to cover the cost of a normal level of uncollectible accounts. Our goal is to mitigate such risks associated with POLR III and to enhance shareholder value through a continuing earnings stream from the core electric business.
Rate Freeze
In connection with POLR II, we negotiated a rate freeze for generation,
transmission and distribution rates. The rate freeze fixed generation rates for retail POLR II customers, and continues the transmission and distribution rates for all customers at current levels through 2003. Under certain circumstances, affected interests may file a complaint alleging that, under these frozen rates, we have exceeded reasonable earnings, in which case the PUC could make adjustments to rectify such earnings.
Regional Transmission Organization
FERC Order No. 2000, as amended, calls on transmission-owning utilities such as Duquesne Light to join regional transmission organizations by September 2004. We are committed to ensuring a stable, plentiful supply of electricity for our customers. Toward that end, we anticipate joining a regional transmission organization as part of our pending POLR III proposal.
PUC Proceedings
On October 25, 2002, we petitioned the PUC to issue a declaratory order regarding a provision in our retail tariff that affected our largest industrial customer. We and Orion had interpreted the tariff differently. On February 6, 2003 the PUC issued an order, to be effective prospectively, affirming Orion’s interpretation. The effect of this order could increase the customer’s annual billings significantly. The ultimate impact will be influenced by operational changes the customer may make to reduce its energy costs. We are responsible for paying Orion the amount billed, and retain the risk of recovering any increased billings from the customer. This risk is not included in the “normal level” of uncollectible accounts described above.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT 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 $320.1 million or 33.4% of long-term debt. 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% increase in interest rates would have affected our variable rate debt obligations by increasing interest expense by approximately $0.4 million, $0.7 million and $2.0 million for the years ended December 31, 2002, 2001 and 2000. A 10% reduction in interest rates would have increased the market value of our fixed-rate debt by approximately $37.6 million and $40.6 million as of December 31, 2002 and 2001. Such changes would not have had a significant near-term effect on our future earnings or cash flows.
See our “Provider of Last Resort” discussion in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of market risk associated with our POLR obligation.
ITEM 8.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEPENDENT AUDITORS’ REPORT
To the Directors and Shareholder of Duquesne Light Company:
We have audited the accompanying consolidated balance sheets of Duquesne Light Company (a wholly owned subsidiary of DQE, Inc.) and subsidiaries as of December 31, 2002 and 2001, 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, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of Duquesne Light Company’s management. Our responsibility is to express an opinion on the financial statements and the financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 Duquesne Light Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. 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.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2000, Duquesne Light Company changed its method of accounting for unbilled revenues.
/s/ Deloitte & Touche LLP
Pittsburgh, Pennsylvania
January 30, 2003
(February 6, 2003 as to Note 20)
Consolidated Statements of Income
See notes to consolidated financial statements.
Consolidated Balance Sheets
See notes to consolidated financial statements.
Consolidated Balance Sheets
See notes to consolidated financial statements.
Consolidated Statements of Cash Flows
See notes to consolidated financial statements
Consolidated Statements of Comprehensive Income
See notes to consolidated financial statements.
Consolidated Statements of Retained Earnings
See notes to consolidated financial statements.
Notes to Consolidated Financial Statements
1. ACCOUNTING POLICIES
Consolidation
Duquesne Light Company is a wholly owned subsidiary of DQE, Inc. We are engaged in the transmission and distribution of electric energy.
Our subsidiaries are primarily involved in operating our automated meter reading technology and providing financing to certain affiliates.
The consolidated financial statements include the accounts of Duquesne Light and our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in the consolidation.
Basis of Accounting
We are subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). Our electricity delivery business is also subject to regulation by the Pennsylvania Public Utility Commission (PUC) and the Federal Energy Regulatory Commission (FERC) with respect to rates for delivery of electric power, accounting and other matters.
As a result of our PUC-approved restructuring plan in 1998, the electricity supply segment does not meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” Pursuant to the PUC’s final restructuring order, and as provided in the Pennsylvania Electricity Generation Customer Choice and Competition Act (Customer Choice Act), generation-related transition costs 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 was adjusted by receipt of $1.7 billion of generation asset sale proceeds during the second quarter of 2000. During 2000, we incurred $78.8 million of costs related to the sale of our generation assets that were deferred as divestiture-related costs. 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 Note 2.) These regulatory assets as of December 31, 2002 and 2001 consist of regulatory tax receivables of $222.9 million and $225.6 million, unamortized debt costs of $41.6
million and $28.9 million, and deferred employee and other costs of $15.8 million and $12.7 million. These assets are currently being recovered over a period of approximately 28 years and are not earning a rate of return.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions with respect to values and conditions 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 we are required to make. We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates.
Customer Concentration
Our electric utility operations provide service to approximately 587,000 direct customers in southwestern Pennsylvania (including in the City of Pittsburgh), a territory of approximately 800 square miles.
Revenues from Utility Sales
Our meters are read monthly, and electric utility customers are billed on the same basis. On January 1, 2000, we adopted the policy of recording unbilled customer revenues to better reflect the revenues generated from the amount of energy supplied and delivered to electric utility customers in a given accounting period. Previously, revenues from electric utility customers were recorded in the accounting period for which they were billed. Revenues recorded now reflect actual customer usage in an accounting period, regardless of when billed. The effect of this policy is reflected on the income statement, net of tax and associated expenses, as a $15.5 million cumulative effect of a change in accounting principle in 2000.
Electricity sales revenue includes related gross receipts taxes that are collected from ratepayers and remitted to the appropriate taxing agency. These taxes are recorded in a taxes payable account at the time of sale and as an expense in taxes other than income taxes. The payable is relieved when payment is made to the appropriate taxing agency. The gross receipts taxes were approximately $40 million, $56 million, and $53 million in 2002, 2001 and 2000.
Other Operating Revenues and Other Income
Other operating revenues include non-megawatt-hour (MWh) electric utility revenues, such as transmission fees charged to other utilities that use our transmission system. In addition, we charge rental fees to third parties who have cable or other equipment attached to our utility poles and transmission towers, or who have cable included in our underground ducts.
Following our generation asset sale, other income consists primarily of interest income from the DQE loan receivable and our investment in the DQE Capital cash pool discussed below. Our average loan and investment balance in 2002 and 2001 was $625.9 million and $474.1 million, which earned interest at an average rate of 3.4% and 6.1%. Gains or losses resulting from the disposition of certain assets are also included here.
Depreciation and Amortization
Depreciation expense of $56.5 million, $59.7 million, and $58.6 million was recorded in 2002, 2001 and 2000. Depreciation of property, plant and equipment is recorded on a straight- line basis over the estimated remaining useful lives of properties, which is approximately 29 years for both the transmission and distribution portions of electric plant in service. Amortization of transition costs represents the difference between CTC revenues billed to customers (net of gross receipts tax) and the allowed 11% pre-tax return on our unrecovered net of tax transition cost balance.
Investment in DQE Capital Cash Pool
We participate in a cash pool arrangement with our affiliate, DQE Capital Corporation, and its affiliates. Through this arrangement, available cash is invested and interest is earned daily at a market rate. The amounts shown on the consolidated balance sheets as investment in the DQE Capital cash pool reflect the amounts DQE Capital uses in its on-lending operations to affiliates. Provisions of the DQE Capital cash pool provide us immediate accessibility for our operational cash needs. Interest is paid monthly and is reflected in other income on the consolidated statements of income.
Receivables
Receivables on the consolidated balance sheets are comprised of outstanding billings for electric customers, other utilities, amounts related to unbilled revenues, and affiliates. (See Note 3.)
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.
Substantially all of the electric utility properties are subject to the lien of our first mortgage indenture.
We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.
Income Taxes
In accordance with SFAS No 109, “Accounting for Income Taxes,” we use the liability method in computing deferred taxes on all differences between book and tax bases of assets and liabilities. 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.
We file a consolidated U.S. federal income tax return with DQE and other companies in the affiliated group. DQE and its subsidiaries participate in an intercompany tax sharing agreement which generally provides the taxable income for each subsidiary be calculated as if it filed a separate return.
For the electricity delivery business segment, we recognize a regulatory asset for deferred tax liabilities that are expected to be recovered through rates. The difference in the provision for deferred income taxes related to depreciation of electric plant in service and the amount that otherwise would be recorded under generally accepted accounting principles is deferred and included in regulatory assets on the consolidated balance sheets.
Pension and Other Postretirement Benefits
See Note 13 for a discussion of the accounting for our pension and other postretirement benefits.
Contingent Liabilities
We establish reserves for estimated loss contingencies when it is management’s assessment that a loss is probable and the amount can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known, or circumstances change, that affect the previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon management’s assumptions and estimates, advice of legal counsel, or other third parties regarding probable outcomes of the matter. Should the ultimate outcome differ from the assumptions and estimates, revisions to the estimated reserves for contingent liabilities would be recognized. Such contingent liabilities include, but are not limited to, restructuring liabilities (see Note 4), income tax matters (see Note 10) and other commitments and contingencies (see Note 12).
Dividends
DQE’s dividend policy requires subsidiaries to dividend their net income, if cash is available. In addition, special dividends are declared periodically related to proceeds from asset sales and other special circumstances. During the years ended December 31, 2002, 2001 and 2000, we declared cash dividends of $75.0 million, $52.7 million, and $82.0 million to DQE as estimates of our net income for the year. Following the sale of our generation assets in 2000, we declared a special cash dividend of $200.0 million to DQE. This dividend was reflected on the consolidated balance sheets as a reduction to capital surplus.
Reclassification
The 2001 and 2000 consolidated financial statements have been reclassified to conform with the 2002 presentation.
Recent Accounting Pronouncements
Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Specifically, this standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. The entity is required to capitalize the cost by increasing the carrying amount of the related long-lived asset. The capitalized cost is then depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. The standard is effective for fiscal years beginning after June 15, 2002. We do not believe that the adoption of SFAS No. 143 will have a significant impact on our financial statements.
Exit or Disposal Activities
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Task Force Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring).” SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred, rather than at the time of the commitment to a disposal or exit plan. This statement also establishes that the initial measurement of the liability should be at fair market value. This statement is effective for exit or disposal activities initiated after December 31, 2002. Initial adoption of this statement should have no impact on our financial statements, but SFAS No. 146 may affect the accounting treatment of any future disposal or exit activities.
Stock-Based Compensation
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure, an amendment of FASB Statement No. 123,” which provides alternative methods of transition for companies that voluntarily adopt the fair value based method of accounting for stock-based employee compensation. This standard also amends the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation,” by requiring prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and prescribing a specific tabular format to show the effect of the method used on reported results. The annual disclosure provisions are effective for fiscal years ending after December 15, 2002. Interim disclosure provisions are effective for financial statements for interim periods beginning after December 15, 2002.
We continue to account for stock-based employee compensation using the intrinsic value method under the recognition and measurement principles of APB 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. The following table illustrates the effect on reported income if we had applied the fair value recognition provisions of SFAS No. 123.
Other
On January 1, 2002, we adopted SFAS No. 141, “Business Combinations,” SFAS No. 142, “Goodwill and Other Intangible Assets,” and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the impact of which was not significant to our financial statements.
2. RATE MATTERS
Competitive Transition Charge
Under Customer Choice, customers must choose to receive their electric energy from an alternative generation supplier or through our POLR arrangements. Customers who select an alternative generation supplier pay for generation charges set competitively by that supplier, and pay us transmission and distribution charges and the CTC (unless the CTC has already been collected for a customer’s rate class).
We have completed the CTC collection from most of our customers. As of December 31, 2002, the CTC balance has been fully collected for approximately 95% of customers, representing approximately 87% of the MWh sales for 2002. The transition costs, as reflected on the consolidated balance sheets, are being amortized over the same period that the CTC revenues are being recognized. For regulatory purposes, the unrecovered balance of transition costs was approximately $25 million ($15 million net of tax) at December 31, 2002, and approximately $142 million ($87 million net of tax) at December 31, 2001. We are allowed to earn an 11.0% pre-tax return on the net of tax CTC balance. A lower amount is shown on the consolidated balance sheets due to the accounting for unbilled revenues.
Provider of Last Resort
Orion Power Midwest (a subsidiary of Reliant Resources, Inc.) is our supplier under POLR I and POLR II. POLR II extends through December 31, 2004 and permits us a margin per MWh supplied based on the mix of rate classes, and number of customers, participating in POLR II. For 2002, the average margin was $4.77 per MWh. Except for this margin, POLR I and POLR II, in general, effectively transfer to Orion the financial risks and rewards associated with our provider of last resort obligations. As of December 31, 2002, approximately 77% of our customers measured on a MWh basis received electricity through POLR I or POLR II. The number of POLR customers will fluctuate depending on market prices and the number of alternative generation suppliers in the retail supply business.
There are certain safeguards in POLR I and POLR II designed to mitigate losses in the event that Orion defaults on its performance under the arrangement. Contractually, we have various credit enhancements to address market exposure if Orion failed to deliver the required POLR supply. We hold an irrevocable $10 million letter of credit (that can be increased based on Orion’s investment ratings and net worth). We also remit the POLR customer payments 35 days after billing the customer. We have the right not to remit these payments in the event of an Orion default .
If Orion were to fail to deliver, we would be required to procure our POLR supply requirements in the energy markets. If market prices for energy were higher than the POLR rate at the time of default, we could potentially be acquiring energy for sale to POLR customers at a loss. If that were to happen and the contractual provisions with Orion were not sufficient to cover any loss, we would seek regulatory recovery of any additional loss. While the Customer Choice Act provides generally for POLR supply costs to be borne by customers, recent litigation suggests that it may not be clear whether we could pass any costs in excess of the existing PUC-approved POLR prices on to our customers. Additionally, Orion’s parent was downgraded by the rating agencies in 2002. To date, the downgrade has not affected Orion’s performance.
We retain the risk that customers will not pay for the POLR generation supply. However, a component of our delivery rate is designed to cover the cost of a normal level of uncollectible accounts.
Rate Freeze
In connection with POLR II, we negotiated a rate freeze for generation, transmission and distribution rates. The rate freeze fixed generation rates for retail POLR II customers, and continues the transmission and distribution rates for all customers at current levels through 2003. Under certain circumstances, affected interests may file a complaint alleging that, under these frozen rates, we have exceeded reasonable earnings, in which case the PUC could make adjustments to rectify such earnings.
3. TRANSACTIONS WITH AFFILIATES
As a wholly owned subsidiary of DQE, we have various transactions with our parent company and its subsidiaries, including the following items.
We generally pay quarterly dividends to DQE that approximate our net income. (See Note 1.) As a holder of DQE common stock, we receive dividend income from DQE. (See Note 8.)
We participate in a cash pool arrangement with our affiliate, DQE Capital, and its affiliates. (See Note 1.) Following the sale of our generation assets in 2000, we loaned $250.0 million of the sale proceeds to DQE, which remains outstanding as of December 31,
2002. The demand note bears a market rate of interest and is reflected on the consolidated balance sheets as DQE loan receivable.
In 2002, we charged an administrative fee to our affiliates based on an allocation method that considers the cost of actual or estimated services performed and other expenses incurred on behalf of the affiliated subsidiaries or parent company.
In 2001 and 2000, DQE charged its subsidiaries a fee for administrative and other expenses based on an allocation method that considers, among other things, the subsidiaries’ assets, revenues and employees.
We participate in a tax sharing agreement with DQE to provide, among other things, for the payment of taxes for periods during which DQE and we are included in the same consolidated group for federal tax purposes. We share in the consolidated tax liability to the extent of our income or loss for the year. (See Note 10.) At December 31, 2002, our tax liability to DQE under this arrangement was $46.7 million and is included in payable to affiliates on the consolidated balance sheets.
Certain of our revenues and expenses relate to transactions with DQE and its subsidiaries, including the following:
4. RESTRUCTURING CHARGE
During the fourth quarter of 2001, we recorded a pre-tax restructuring charge of $10.8 million related to (1) the consolidation and reduction of certain administrative and back-office functions through an involuntary termination plan; (2) the abandonment of certain office facilities; and (3) other lease costs related to abandoned office facilities. Approximately 96 employees were terminated in connection with this restructuring.
During the fourth quarter of 2002, we recorded a pre-tax restructuring charge of $3.7 million related to further consolidation and centralization of certain administrative functions. The 2002 restructuring charge primarily includes severance costs for 13 terminated executive, management, professional and administrative personnel.
In 2002, we increased our restructuring liability and restructuring expense by approximately $0.2 million for revisions to our 2001 restructuring plan. This increase was due to revised estimates of certain severance-related benefits to be paid.
The following table summarizes the restructuring activities for both the 2001 and 2002 restructuring plans for the two-year period ended December 31, 2002.
Restructuring Liability
The combined remaining restructuring liability at December 31, 2002 was $6.8 million and is included in other liabilities on the consolidated balance sheets. We believe that the remaining provision is adequate to complete the restructuring plan. We expect that the remaining restructuring liability will be paid on a monthly basis throughout 2006.
5. EQUITY
In July 1989, we became a wholly owned subsidiary of DQE, whose common stock replaced the outstanding shares of our common stock, except for the 10 shares DQE holds.
Payments of dividends on our common stock may be restricted by obligations to holders of our preferred and preference stock, pursuant to our Restated Articles of Incorporation, and by obligations of a subsidiary to holders of its preferred securities. No dividends or distributions may be made on our common stock if we have not paid dividends or sinking fund obligations on our preferred or preference stock. Dividends may also be effectively limited by the terms of certain financing agreements. Further,
the aggregate amount of our 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 DQE owns all of our common stock, if we cannot pay common dividends, DQE may not be able to pay dividends on its common or preferred stock. No part of our retained earnings was restricted at December 31, 2002.
Accumulated other comprehensive income consists of unrealized losses on available for sale investments.
6. ACQUISITIONS AND DISPOSITIONS
In 2002, we received $1.3 million from the sale of a building and recognized an after-tax gain of $0.3 million. We also received $1.3 million of proceeds from the sale of securities and recognized an after-tax gain of $0.8 million.
In 2001 we sold a significant portion of our remaining affordable housing portfolio, receiving proceeds of approximately $3.4 million, which approximated book value. We also sold property and recognized a gain of approximately $1.6 million.
In 2000, we completed the sale of our generation assets for approximately $1.7 billion. We also purchased the Customer Advanced Reliability System for $32 million from Itron, Inc., which had developed this automated electronic meter reading system for use with our electric utility customers. We had previously leased these assets.
7. PROPERTY, PLANT AND EQUIPMENT
In April 2000, we sold our generation assets. We own 9 transmission substations and 561 distribution substations (367 of which are located on customer-owned land and are used to service only those customers). We have 592 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 16,420 circuit-miles of lines and cable. These properties are used in the electricity delivery business segment.
8. LONG - TERM INVESTMENTS
As of December 31, 2002 and 2001, the fair market value of our investment in DQE common stock was $18.9 million and $23.7 million, and the cost of our investment was $25.2 million and $25.4 million.
9. SHORT-TERM BORROWING AND REVOLVING CREDIT ARRANGEMENTS
We maintain a 364-day, $150 million revolving credit agreement which expires in October 2003. At December 31, 2002 and 2001, no borrowings were outstanding. As of December 31, 2002, we had $9.3 million in standby letters of credit, leaving $140.7 million available under the revolver.
Decreases in our credit ratings will result in an inverse change in the fees and interest rates charged. The revolver is subject to cross-default if we default on any payment due under any other indebtedness exceeding $50 million.
Under our credit facility, we are subject to financial covenants requiring us to maintain a maximum debt-to-capitalization ratio of 65%. At December 31, 2002 we were in compliance with these covenants, having a debt-to-capitalization ratio of approximately 57%.
During 2002, the maximum amount of bank loans and commercial paper borrowings outstanding at any date was $125 million, the amount of average daily borrowings was $43.7 million, and the weighted average daily interest rate was 2.34%.
During 2001, there were no bank loans or commercial paper borrowings outstanding.
During 2000, the maximum amount of bank loans and commercial paper borrowings outstanding at any date was $189.5 million, the amount of average daily borrowings was $7.0 million, and the weighted average daily interest rate was 6.8%.
10. INCOME TAXES
We file consolidated tax returns with DQE and other companies in the affiliated group. The annual federal corporate income tax returns have been audited by the Internal Revenue Service (IRS) and are closed for the tax years through 1993. The IRS examination of the 1994 tax year has been completed, and the IRS issued a notice of proposed adjustment increasing DQE’s 1994 income tax liability in the approximate amount of $22 million (including penalties and interest).
The proposed adjustment relates to an investment by another DQE subsidiary in certain structured lease transactions. DQE has paid the proposed adjustment and filed a protest, which is currently pending with the IRS Appeals Office. As part of their current audit of the 1995 through 1997 years, the IRS has indicated that it is considering proposed adjustments for these years relating to the same transactions as well as to other similar transactions. If the IRS were
to propose adjustments relating to these transactions for the years 1995 through 2002 similar to those proposed for 1994 and if those adjustments were sustained, DQE would project that the total proposed assessment of additional tax would be approximately $175 million (before interest and penalties).
In addition, a DQE subsidiary entered into other structured lease transactions from 1995 through 1997. In 1999, the IRS published a revenue ruling setting forth its official position which is to disallow deductions attributable to certain leasing transactions. In October 2002, the IRS published a revenue ruling reaffirming its position to disallow deductions attributable to certain leasing transactions. DQE believes the IRS is likely to challenge its subsidiary’s structured lease transactions by characterizing them as those described in the revenue ruling. However, the IRS has not yet proposed any adjustments with respect to these transactions, and DQE cannot predict the nature, extent or timing of any proposed adjustments.
Although DQE expects to make additional deposits of at least $80 million with the IRS with respect to any adjustments which may ultimately be proposed, such deposits have not been made. As of December 31, 2002, DQE has federal income tax credits of $63.4 million and capital losses of $32.8 million, generated in current and prior years, that are available to offset a portion of any assessment of additional tax made by the IRS. The tax years 1998 through 2002 remain subject to IRS review.
Our state income tax returns are subject to review by the Pennsylvania Department of Revenue, which has issued assessments of additional tax for 1999 and 2000 primarily to include income of an out of state subsidiary corporation in Pennsylvania taxable income. If the Department asserts the same positions for 2001 and 2002, our total exposure for all years, without interest or penalty, could approximate $85 million (net of associated federal benefit). We do not agree with the Department on this matter and intend to exercise our appeal rights, as necessary.
It is not possible to predict if, when or to what extent any income tax adjustments ultimately proposed for the period 1994 through 2002 will be sustained. We do not believe that the ultimate resolution of these federal or state tax issues for this period will have a material adverse effect on our financial position or results of operation. However, the resolution of these tax issues, depending on the extent and timing thereof, could have a material adverse effect on cash flows for the period in which they are paid.
Deferred Tax Assets (Liabilities) as of December 31,
Income Tax Expense (Benefit)
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.
Income Tax Expense Reconciliation
11. LEASES
We lease office buildings and other property and equipment.
Capital Leases at December 31,
Summary of Rental Expense
Future Minimum Lease Payments
(a) Includes $1.1 million of projected rent payments expensed as part of the 2001 restructuring charge ($0.3 million in 2003, 2004 and 2005 and $0.2 million in 2006). These future cash payments will decrease the restructuring liability.
Future minimum lease payments for operating leases are related principally to certain corporate offices. Future minimum capital lease payments relate to a building.
In 2001, we amended the existing lease at our downtown Pittsburgh offices and extended the lease term to December 2011. The lease agreement contains one five-year renewal option.
12. COMMITMENTS AND CONTINGENCIES
Construction, Investments and Acquisitions
We estimate that we will spend, excluding AFC, approximately $70.0 million for each of 2003, 2004 and 2005 for electric utility construction.
Employees
We are a party to a labor contract with the International Brotherhood of Electrical Workers, which represents 943 of our 1,297 employees. This contract expires September 30, 2003.
Pension Plans
We have an obligation to contribute approximately $32.1 million to our pension plans over future years. (See Note 13.)
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. Following the generation asset divestiture, we retained certain facilities which remain subject to these regulations. We have assessed our residual waste management sites, and the DEP has approved our compliance strategies. We expect the costs of compliance to be approximately $7.4 million with respect to sites we will continue to own. These costs are being recovered in the CTC, and the corresponding liability has been recorded for current and future obligations.
We own the closed Warwick Mine, located along the Monongahela River in Greene County, Pennsylvania. This property had been used in the electricity supply business segment. We have been selling unused portions of the property and will continue to do so. Our current estimated liability for closing the Warwick Mine, including final site reclamation, mine water treatment and certain labor liabilities, is approximately $30 million. We have recorded a liability for this amount on the consolidated balance sheets.
13. EMPLOYEE BENEFITS
Pension and Other Postretirement Benefits
We maintain several qualified retirement plans and one unqualified plan to provide pensions for all eligible full-time employees of Duquesne Light and other DQE affiliates. We bill the affiliates for their proportionate share of the plan costs. 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 (credited) to expense or construction were ($17.4) million for 2002, ($20.7) million for 2001 and ($13.1) million for 2000.
In 2001, we approved an amendment to the pension plan for a cost of living adjustment for benefits for certain retirees. This caused an increase in the Projected Benefit Obligation of $11.9 million.
In its January 18, 2001, order approving our final generation asset sale proceeds accounting, the PUC approved recovery of costs associated with the early retirement program. Although we made no cash contributions to our pension plans in either 2002 or 2001, we have an obligation, pursuant to this PUC order, to contribute approximately $32.1 million to the pension plans over future years.
In addition to pension benefits, we provide certain health care benefits and life insurance for some retired employees. The life insurance plan is non-contributory. Participating retirees make contributions, which may be adjusted annually, to the health care plan. Health care benefits terminate when retirees reach age 65. 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.
The health care trend assumption used in the development of the fiscal 2002 expense was 11.0%, decreasing 0.50% per year to an ultimate rate of 5.75% (reached in 2013). The health care trend assumption reflected in the December 31, 2002, SFAS No. 106 year-end disclosure, which will also be used in the development of fiscal 2003 expense, is 10.5%, decreasing 0.50% per year to an ultimate rate of 5.25% (reached in 2014). Consistent with previous practice, a 1.5 % spread between the discount rate (6.75 % for 2003 expense) and the ultimate health care cost trend rate will be maintained.
The following tables provide a reconciliation of the changes in the pension and postretirement plans’ benefit obligations and fair value of plan assets over the two-year period ended December 31, 2002, a statement of the funded status as of December 31, 2002 and 2001, and a summary of assumptions used in the measurement of our benefit obligations:
Funded Status of the Pension and Postretirement Benefit Plans as of December 31,
(a) The accrued benefit costs relating to the pension plans include prepaid pension costs of $16.9 million and $9.8 million as of December 31, 2002 and 2001, as reflected on the consolidated balance sheets. These prepaid pension costs relate to one of our pension plans for which the fair market value of the plan’s assets exceeded the projected benefit obligations as of those dates.
Weighted-Average Assumptions as of December 31,
All of our plans for postretirement benefits, other than pensions, have no plan assets. The aggregate benefit obligation for those plans was $48.3 million as of December 31, 2002, and $46.1 million as of December 31, 2001. The accumulated postretirement benefit obligation comprises the present value of the estimated future benefits payable to current retirees, and a pro rata portion of estimated benefits payable to active employees after retirement.
Pension assets consist primarily of common stocks (exclusive of DQE common stock), United States obligations and corporate debt securities.
Components of Net Pension Cost as of December 31,
Components of Postretirement Cost as of December 31,
Effect of a One Percent Change in Health Care Cost Trend Rates as of December 31, 2002
Retirement Savings Plan and Stock Options
DQE sponsors separate 401(k) retirement plans for management and IBEW- represented employees of its affiliates, including Duquesne Light.
The 401(k) Retirement Savings Plan provides for employer contributions which may include a participant base match and a participant incentive match. In 2002, the incentive match was not achieved. In 2001, all employees eligible for an incentive match achieved their incentive targets.
We fund our matching contributions to the 401(k) Retirement Savings Plan with payments to an ESOP established in December 1991. (See Note 16.)
The 401(k) Retirement Savings Plan for IBEW-Represented Employees provides that we will match employee contributions with a base match and an additional incentive match, if certain targets are met. In 2002, the incentive match was not achieved. In 2001, all IBEW-represented employees achieved their incentive targets.
On June 26, 2002, the DQE shareholders approved the new DQE, Inc. 2002 Long-Term Incentive Plan (the 2002 Plan). The purpose of the 2002 Plan is to encourage eligible employees of DQE and its affiliates, as well as non-employee members of the Board of Directors of DQE, to increase their efforts to make DQE and each affiliate more successful, to provide an additional inducement for such employees and non-employee directors by providing an opportunity to acquire DQE common stock on favorable terms, and to provide a means through which DQE may attract able persons to enter the employ of DQE or one of its affiliates and to serve as non-employee directors of DQE.
Under the 2002 plan, the DQE Board may grant stock option awards, alternative stock appreciation rights and dividend equivalent accounts; restricted share awards; and performance awards. Stock options awarded to eligible employees will be granted at an option price not less than 100% of the fair market value of DQE common stock on the date of grant. All stock options to directors will be granted at an option price equal to 100% of the fair market value of DQE common stock on the date of grant.
The 2002 Plan became effective as of January 1, 2002 and replaces the prior DQE, Inc. Long-Term Incentive Plan (the Prior Plan). Any stock options granted prior to January 1, 2002 shall not be affected by the adoption of the 2002 Plan, and will be administered according to the Prior Plan. A total of 1,677,007 shares of DQE common stock remain reserved for issuance in connection with awards granted under the Prior Plan. No new options shall be granted under the Prior Plan.
The aggregate number of shares of DQE common stock authorized for issuance under the 2002 Plan is 2,690,468 shares, and of this total, no more than 500,000 shares shall be issued as restricted shares. The 2002 Plan will terminate on December 31, 2011.
During December 2001, 787,300 stock options were granted to employees under the Prior Plan with an exercise price of $16.90 per share. Due to cancellations and forfeitures in 2002, only 734,600 of these options remain as of December 31, 2002. One-half of these options became exercisable, subject to the vesting provisions, in February 2002, when the closing price on the New York Stock exchange of DQE’s common stock averaged $19.56 for 30 consecutive trading days. The remainder will become exercisable under the same terms at a target price of $22.49 per share. The options vest over an 18-month period from the date of grant.
During December 2002, 774,500 stock options were granted to employees under the 2002 Plan with an exercise price of $15.015 per share. One-half of these options becomes exercisable, but remains subject to the vesting provisions, if the closing price on the New York Stock Exchange of DQE’s common stock averages $17.38 for 30 consecutive trading days, with the remainder becoming exercisable under the same terms at a target price of $19.98 per share. The options vest over an 18-month period from the date of grant.
The following tables summarize the transactions of the stock option plans for the three-year period ended December 31, 2002, and certain information about outstanding stock options as of December 31, 2002:
As of December 31, 2002, 2001 and 2000, stock appreciation rights (SARs) had been granted in connection with 726,248; 1,036,373; and 975,292 of the options outstanding. During 2002, 2001 and 2000, 54,933; 58,061; and 208,236 SARs were exercised.
The fair value of the options granted during 2002, 2001 and 1999 is estimated on the date of grant using the Black-Scholes option pricing model. The estimated weighted average assumptions used and the fair values are as follows:
14. LONG-TERM DEBT
Long-Term Debt as of December 31,
(a) Excludes first mortgage bonds issued to secure pollution control notes.
(b) Secured by an equal principal amount of first mortgage bonds.
(c) These adjustable interest rates averaged 1.5% in 2002 and 2.8% in 2001.
As of December 31, 2002, there were no sinking fund requirements or maturities of long-term debt outstanding for 2003. Sinking fund requirements and maturities of long-term debt for the next five years were $0.4 million per year.
Total interest and other charges were $56.5 million in 2002, $62.4 million in 2001, and $74.7 million in 2000. Interest costs attributable to debt were $55.2 million, $62.3 million, and $73.5 million in 2002, 2001, and 2000, respectively. Of the interest costs attributable to debt, $0.9 million in 2002, $0.6 million in 2001, and $2.0 million in 2000 were capitalized as AFC. Debt discount or premium and related issuance expenses are amortized over the lives of the applicable issues. (See Note 1.)
As of December 31, 2002, 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 $1,046.4 million. The principal amount included in the consolidated balance sheets, excluding unamortized discounts and premiums, is $960.8 million as of December 31, 2002.
At December 31, 2002 and 2001, we were in compliance with all of our debt covenants.
In September 2002, we converted approximately $98 million of variable rate debt to fixed rate with maturities in 2011 and 2013, resulting in a weighted average interest rate of 4.20%.
On August 5, 2002, we redeemed the following: (i) $10 million aggregate principal amount of 8.20% first mortgage bonds due 2022 at a redemption price of 104.51% of the principal amount thereof, and (ii) $100 million aggregate principal amount of 7 5/8% first mortgage bonds due 2023 at a redemption price of 103.9458% of the principal amount thereof.
On April 15, 2002, we issued $200 million of 6.7% first mortgage bonds due 2012. On April 30, 2002, we issued $100 million of 6.7% first mortgage bonds due 2032. In each case we used the proceeds to call and refund existing debt, including debt scheduled to mature in 2003 and 2004.
In January 2002, we issued $125 million of commercial paper, and loaned the proceeds to DQE. This debt was repaid and retired in full, leaving no outstanding balance at December 31, 2002.
In 2000, we retired $350 million of long-term bonds and $399 million of maturing bonds, using proceeds from the sale of generation assets.
15. DUQUESNE LIGHT COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES
Duquesne Capital L.P., a special-purpose limited partnership of which we are the sole general partner, has outstanding $150.0 million principal amount of 8 3/8% Monthly Income Preferred Securities, Series A (MIPS), each with a stated liquidation value of $25.00. At December 31, 2002, there were six million shares authorized and outstanding. The holders of MIPS are entitled to distributions at the annual rate of 8 3/8%, payable monthly. MIPS distributions included in interest and other charges were $12.6 million in 2002, 2001 and 2000. Duquesne Capital, at our direction, has the option to redeem the MIPS at any time, in whole or in part. The MIPS are also subject to mandatory redemption at the maturity of the Debentures referred to below.
Duquesne Capital applied the proceeds of the sale of the MIPS, together with certain other funds, to the purchase from us of $151.5 million principal amount of our 8 3/8% Subordinated Deferrable Interest Debentures, Series A, due May 31, 2044 (Debentures). The Debentures are Duquesne Capital’s sole assets, and Duquesne Capital has no business activity other than holding the Debentures. We have guaranteed the payment of distributions on, and redemption price and liquidation amount in respect of the MIPS, to the extent that Duquesne Capital has funds available for such payment from the Debentures. Upon any redemption of the MIPS, the Debentures will be mandatorily redeemed.
16. PREFERRED AND PREFERENCE STOCK
Preferred and Preference Stock as of December 31,
(a) 4,000,000 authorized shares; $50 par value; cumulative; $50 per share involuntary liquidation value.
(b) 8,000,000 authorized shares; $1 par value; cumulative; $35.50 per share liquidation value; annual dividends of $2.80 per share.
Holders of our 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 our board of directors until all dividends have been paid. Holders of our 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 our directors until all dividends have been paid. As of December 31, 2002, we had made all dividend payments. Preferred and preference dividends of subsidiaries included in interest and other charges were $3.3 million, $3.4 million, and $3.4 million in 2002, 2001, and 2000. Total preferred and preference stock had involuntary liquidation values of $78.9 million and $80.3 million, which exceeded par by $17.9 million and $19.3 million as of December 31, 2002 and 2001.
Outstanding preferred stock is generally callable on notice of not less than 30 days, at stated prices plus accrued dividends. The outstanding preference stock is callable at the liquidation price plus accrued dividends. None of the remaining preferred or preference stock issues has mandatory purchase requirements.
We have an Employee Stock Ownership Plan (ESOP) to provide matching contributions for a 401(k) Retirement Savings Plan for Management Employees. (See Note 13.) 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 the greater of one and one-half shares of DQE common stock or $35.50 worth of DQE common stock. As of December 31, 2002, $18.4 million of preference stock issued in connection with the establishment of the ESOP had been offset, for financial statement purposes, by a $9.2 million deferred ESOP benefit. Dividends on the preference stock and our cash contributions are used to fund the repayment of the ESOP note. We made cash contributions of approximately $0.9 million, $1.5 million and $1.0 million for 2002, 2001 and 2000. These cash contributions were the difference between the ESOP debt service and the amount of dividends on ESOP shares ($1.5 million in 2002, $1.6 million in 2001 and $1.7 million in 2000). 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 $0.9 million in 2002, $1.7 million in 2001 and $2.1 million in 2000.
17. SUPPLEMENTAL CASH FLOW DISCLOSURE
Changes in Working Capital Other than Cash (a) for the Year Ended December 31,
(a) The amounts shown exclude the effects of restructuring charges.
18. BUSINESS SEGMENTS AND RELATED INFORMATION
We report the results of our business segments, determined by products, services and regulatory environment as follows: (1) transmission and distribution of electricity (electricity delivery business segment), (2) supply of electricity (electricity supply business segment), and (3) collection of transition costs (CTC business segment). With the completion of our generation asset sale in April 2000, the electricity supply business segment is now comprised solely of provider of last resort service.
Business Segments for the Twelve Months Ended December 31, 2002:
Business Segments for the Twelve Months Ended December 31, 2001:
Business Segments for the Twelve Months Ended December 31, 2000:
19. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summary of Selected Quarterly Financial Data (Millions of Dollars)
(a) The quarterly data reflect seasonal weather variations in our service territory.
(b) Restructuring charges of $2.3 million after-tax and $6.7 million after-tax are included in fourth quarter results for 2002 and 2001. (See Note 3.) These charges are related to 2002 administrative cost reductions and 2001 consolidation and relocation associated with DQE’s Back-to-Basics strategy.
20. SUBSEQUENT EVENTS
On October 25, 2002, we petitioned the PUC to issue a declaratory order regarding a provision in our retail tariff that affected our largest industrial customer. We had interpreted the tariff differently than Orion. On February 6, 2003 the PUC issued an order, to be effective prospectively, affirming Orion’s interpretation. The effect of this order could increase the customer’s annual billings significantly. The ultimate impact will be influenced by operational changes the customer may make to reduce its energy costs. We are responsible for paying Orion the amount billed, and retain the risk of recovering this increase from the customer, should the customer refuse to pay. This risk is not included in the “normal level” of uncollectible accounts as previously discussed.
In February, 2003, we received the Pennsylvania Department of Revenue’s audit findings which assert additional tax due. (See Note 10.)
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 and incorporated by reference from Exhibit 99.1 hereto. Information relating to our 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 and incorporated by reference from Exhibit 99.1 hereto.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information relating to the ownership of DQE equity securities by our directors, officers and certain beneficial owners is set forth in and incorporated by reference from Exhibit 99.1 hereto.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
PART IV
ITEM 14.
ITEM 14. CONTROLS AND PROCEDURES.
Within the 90 days prior to the date of this report, management (including our principal executive and financial officers) evaluated the effectiveness of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934, Rules 13a-14(c) and 15d-14(c)). Management concluded that, as of the evaluation date, our disclosure controls and procedures were adequate and designed to ensure that material information relating to us and our consolidated subsidiaries would be
made known to management by others within those entities. In addition, there were no significant changes in our internal controls or in other factors that could significantly affect our disclosure controls and procedures subsequent to the evaluation date, including any corrective actions with regard to significant deficiencies and material weaknesses.
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a)(1) The following information is set forth in Part II, Item 8:
Independent Auditors’ Report.
Consolidated Statements of Income for the Three Years Ended December 31, 2002.
Consolidated Balance Sheets, December 31, 2002 and 2001.
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2002.
Consolidated Statements of Comprehensive Income for the Three Years Ended December 31, 2002.
Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 2002.
Notes to Consolidated Financial Statements.
(a)(2) The following financial statement schedule and the related Independent Auditors’ Report are filed here as a part of this Report:
Schedule for the Three Years Ended December 31, 2002:
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 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. 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. 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 no reports on Form 8-K in the fourth quarter of 2002.
Exhibits Index
Exhibit No.
Description
Method of Filing
3.1
Restated Articles of Incorporation of Duquesne Light as currently in effect.
Exhibit 3.1 to the Duquesne Light Form 10-Q for the quarter ended June 30, 1999.
3.2
By-Laws of Duquesne Light, as amended through June 29, 1999, and as currently in effect.
Exhibit 3.2 to the Duquesne Light Form 10-Q for the quarter ended June 30, 1999.
4.1
Indenture dated March 1, 1960, relating to Duquesne Light Company’s 5% Sinking Fund Debentures.
Exhibit 4.3 to the DQE Form 10-K for the year ended December 31, 1989.
4.2
Indenture of Mortgage and Deed of Trust dated as of April 1, 1992, securing Duquesne Light Company’s First Collateral Trust Bonds.
Exhibit 4.3 to Registration Statement (Form S-3) No. 33-52782.
4.3
Supplemental Indentures supplementing the said Indenture of Mortgage and Deed of Trust -
Supplemental Indenture No. 1.
Exhibit 4.4 to Registration Statement (Form S-3) No. 33-52782.
Supplemental Indenture No. 2 through Supplemental Indenture No. 4.
Exhibit 4.4 to Registration Statement (Form S-3) No. 33-63602.
Supplemental Indenture No. 5 through Supplemental Indenture No. 7.
Exhibit 4.6 to the Duquesne Light Form 10-K for the year ended December 31, 1993.
Supplemental Indenture No. 8 and Supplemental Indenture No. 9.
Exhibit 4.6 to the Duquesne Light Form 10-K for the year ended December 31, 1994.
Supplemental Indenture No. 10 through Supplemental Indenture No. 12.
Exhibit 4.4 to the Duquesne Light Form 10-K for the year ended December 31, 1995.
Supplemental Indenture No. 13.
Exhibit 4.3 to the Duquesne Light Form 10-K for the year ended December 31, 1996.
Supplemental Indenture No. 14.
Exhibit 4.3 to the Duquesne Light Form 10-K for the year ended December 31, 1997.
Exhibit No.
Description
Method of Filing
Supplemental Indenture No. 15.
Exhibit 4.3 to the Duquesne Light Form 10-K for the year ended December 31, 1999.
Supplemental Indenture No. 16.
Exhibit 4.3 to the Duquesne Light Form 10-K for the year ended December 31, 1999.
Supplemental Indenture No. 17 and Supplemental Indenture No. 18.
Exhibit 4.2 to the Duquesne Light Registration Statement (Form S-3) No. 333-72408.
4.4
Amended and Restated Agreement of Limited Partnership of Duquesne Capital L.P., dated as of May 14, 1996.
Exhibit 4.4 to the Duquesne Light Form 10-K for the year ended December 31, 1996.
4.5
Payment and Guarantee Agreement, dated as of May 14, 1996, by Duquesne Light Company with respect to MIPS.
Exhibit 4.5 to the Duquesne Light Form 10-K for the year ended December 31, 1996.
4.6
Indenture, dated as of May 1, 1996, by Duquesne Light Company to the First National Bank of Chicago as Trustee.
Exhibit 4.6 to the Duquesne Light Form 10-K for the year ended December 31, 1996.
10.1
Incentive Compensation Program for Certain Executive Officers of Duquesne Light Company, as amended to date.
Exhibit 10.2 to the DQE Form 10-K for the year ended December 31, 1992.
10.2
Non-Competition and Confidentiality Agreement dated as of October 21, 1996 between DQE, Duquesne Light and Victor A. Roque.
Exhibit 10.15 to the DQE Form 10-K for the year ended December 21, 2001.
10.3
Non-Competition and Confidentiality Agreement dated as of August 1, 2000 between Duquesne Light and Joseph G. Belechak.
Exhibit 10.7 to the Duquesne Light Form 10-K for the year ended December 31, 2001.
10.4
Non-Competition and Confidentiality Agreement dated as of April 2, 1997 between Duquesne Light and Maureen L. Hogel.
Exhibit 10.8 to the Duquesne Light Form 10-K for the year ended December 31, 2001.
10.5
Schedule to Exhibit 10.2 listing substantially identical agreements with Stevan R. Schott and James E. Wilson.
Filed here.
10.6
POLR Agreement, dated as of September 24, 1999 by and between Duquesne Light Company and Orion Power Holdings, Inc.
Exhibit 2.2 to the DQE Form 8-K September 24, 1999.
Exhibit No.
Description
Method of Filing
10.7
Amended and Restated POLR II Agreement by and between Duquesne Light Company and Orion Power MidWest, L.P., dated as of December 7, 2000.
Exhibit 10.12 to the Duquesne Light Form 10-K for the year ended December 31, 2000.
12.1
Ratio of Earnings to Fixed Charges.
Filed here.
21.1
Subsidiaries of the registrant.
Filed here.
23.1
Independent Auditors’ Consent.
Filed here.
99.1
Information regarding directors, executive compensation and security ownership.
Filed here.
99.2
Certifications of Principal Executive and Financial Officers Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Filed here.
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 28, 2003, subject to payment in advance of the cost of reproducing the exhibits requested.
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2002, 2001 and
(Millions 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.
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.
Signature
Title
Date
/s/ VICTOR A. ROQUE
President and Director
(Principal Executive Officer)
March 26, 2003
Victor A. Roque
/s/ STEVAN R. SCHOTT
Vice President and Controller
(Principal Financial and Accounting Officer)
March 26, 2003
Stevan R. Schott
/s/ MORGAN K. O’BRIEN
Director
March 26, 2003
Morgan K. O’Brien
/s/ FRANK A. HOFFMANN
Director
March 26, 2003
Frank A. Hoffmann
CERTIFICATIONS
I, Victor A. Roque, President of Duquesne Light Company, certify that:
1. I have reviewed this annual report on Form 10-K of Duquesne Light Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 26, 2003
/s/ VICTOR A. ROQUE
Victor A. Roque
President
(Principal Executive Officer)
I, Stevan R. Schott, Vice President and Controller of Duquesne Light Company, certify that:
1. I have reviewed this annual report on Form 10-K of Duquesne Light Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 26, 2003
/s/ STEVAN R. SCHOTT
Stevan R. Schott
Vice President and Controller
(Principal Financial Officer)