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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x            ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

                For the Fiscal Year Ended December 31, 2002

OR

o            TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934

                For the Transition Period From ____________ to ____________

Commission File Number
1-956

Duquesne Light Company

(Exact name of registrant as specified in its charter)

411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
(Address of principal executive offices)(Zip Code)

Registrant’s telephone number, including area code: (412) 393-6000

Securities registered pursuant to Section 12(b) of the Act:

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   (1)   Issued by Duquesne Capital, L.P., and the payments of dividends and payments on liquidation or redemption are guaranteed by Duquesne Light Company.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act.) Yes x No o

The registrant is a wholly owned subsidiary of DQE, Inc. No common stock was held by non-affiliates as of the last business day of the registrant’s most recently completed second fiscal quarter.

As of March 10, 2003, there were 10 shares of the registrant’s single class of common stock outstanding, all held by DQE, Inc.

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GLOSSARY OF TERMS

BACK-TO-BASICS – The business strategy of our parent, DQE, Inc., in 2002 featured a more concentrated focus on our core electric utility operations and on complementary businesses, such as energy services. The strategy included the divestiture by DQE of non-core businesses.

COMPETITIVE TRANSITION CHARGE (CTC) – During the electric utility restructuring from the traditional Pennsylvania regulatory framework to customer choice, electric utilities have the opportunity to recover transition costs from customers through this usage-based charge.

CUSTOMER CHOICE – The Pennsylvania Electricity Generation Customer Choice and Competition Act gives consumers the right to contract for electricity at market prices from PUC-approved electric generation suppliers.

FEDERAL ENERGY REGULATORY COMMISSION (FERC) – The FERC is an independent five-member commission within the United States Department of Energy. Among its many responsibilities, the FERC sets rates and charges for the wholesale transportation and sale of electricity.

PENNSYLVANIA PUBLIC UTILITY COMMISSION (PUC) – The governmental body that regulates all utilities (electric, gas, telephone, water, etc.) that do business in Pennsylvania.

PROVIDER OF LAST RESORT (POLR) – Under Customer Choice, the local distribution utility is required to provide electricity for customers who do not choose an alternative generation supplier, or whose supplier fails to deliver. (See “Rate Matters.”)

•         POLR I refers to the generation supply arrangement with Orion Power Midwest during the CTC collection period, under which Orion provides us the necessary electricity to satisfy our POLR obligation.

•         POLR II refers to the extended generation supply arrangement with Orion following collection of the CTC through December 31, 2004.

•         POLR III refers to our pending plans for POLR supply after POLR II expires.

REGIONAL TRANSMISSION ORGANIZATION (RTO) – Organization formed by transmission-owning utilities to put transmission facilities within a region under common control.

REGULATORY ASSETS – Pennsylvania ratemaking practices grant regulated utilities exclusive geographic franchises in exchange for the obligation to serve all customers. Under this system, certain prudently incurred costs are approved by the PUC for deferral and future recovery, with a return from customers. These deferred costs are capitalized as regulatory assets by the regulated utility.

TRANSITION COSTS – Transition costs are the net present value of a utility’s known or measurable costs related to electric generation that are recoverable through the CTC.

TRANSMISSION AND DISTRIBUTION – Transmission is the flow of electricity from generating stations over high voltage lines to substations where voltage is reduced. Distribution is the flow of electricity over lower voltage facilities to the ultimate customer (businesses and homes).

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PART I

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,

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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.

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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.

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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.          LEGAL PROCEEDINGS.

None.

ITEM 4.          SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Not applicable.

PART II

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.

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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.          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

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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.

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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

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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.

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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.

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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

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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).

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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

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$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.

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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,

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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.      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.

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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.

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Consolidated Statements of Income

See notes to consolidated financial statements.

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Consolidated Balance Sheets