<PAGE>

                                 UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSION
                             Washington, DC  20549


                                   FORM 10-Q


     [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
         SECURITIES EXCHANGE ACT OF 1934

     [ ] For the Quarterly Period Ended   June 30, 1999
                                        -----------------

     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)

              Pennsylvania                            25-0451600
              ------------                            ----------
     (State or other jurisdiction of      (I.R.S. Employer Identification No.)
     incorporation or organization)


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

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


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 (or for such shorter period that the registrant was
required to file such report), and (2) has been subject to such filing
requirements for the past 90 days.   Yes   X      No
                                          ---        ---

Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:

DQE, Inc. is the holder of all shares of common stock, $1 par value, of Duquesne
Light Company consisting of 10 shares as of June 30, 1999 and July 31, 1999.
<PAGE>

PART I.  FINANCIAL INFORMATION
Item 1.  Financial Statements

                             DUQUESNE LIGHT COMPANY
                   CONDENSED STATEMENT OF CONSOLIDATED INCOME
                             (Thousands of Dollars)
                                  (Unaudited)

<TABLE>
<CAPTION>
                                                         Three Months Ended                            Six Months Ended
                                                              June 30,                                     June 30,
                                                   -------------------------------             ---------------------------------
                                                      1999                1998                    1999                  1998
                                                   ------------       ------------             -------------       -------------
<S>                                                <C>                <C>                      <C>                 <C>
Operating Revenues
  Sales of Electricity:
    Customers - net                                $    239,948       $    269,477             $     494,367       $     537,840
    Utilities                                            15,478              6,970                    29,131              14,042
                                                   ------------       ------------             -------------       -------------
  Total Sales of Electricity                            255,426            276,447                   523,498             551,882
  Other                                                  17,813             10,886                    31,717              20,608
                                                   ------------       ------------             -------------       -------------
    Total Operating Revenues                            273,239            287,333                   555,215             572,490
                                                   ------------       ------------             -------------       -------------

Operating Expenses
  Fuel and purchased power                               49,669             71,575                    96,580             131,108
  Other operating                                        59,894             56,916                   121,990             125,742
  Maintenance                                            23,434             15,669                    43,771              35,952
  Depreciation and amortization                          47,058             56,104                    99,898             111,784
  Taxes other than income taxes                          22,148             19,363                    44,238              38,928
  Income taxes                                           16,558             21,888                    35,251              37,827
                                                   ------------       ------------             -------------       -------------
    Total Operating Expenses                            218,761            241,515                   441,728             481,341
                                                   ------------       ------------             -------------       -------------

OPERATING INCOME                                         54,478             45,818                   113,487              91,149
                                                   ------------       ------------             -------------       -------------

Other Income and Deductions                               6,157              7,969                    14,392              19,672

Income Before Interest and Other Charges
    and Extraordinary Item                               60,635             53,787                   127,879             110,821

Interest Charges                                         28,918             20,086                    57,154              40,535

Monthly Income Preferred Securities
    Dividend Requirements                                 3,141              3,141                     6,281               6,281
                                                   ------------       ------------             -------------       -------------
INCOME Before Extraordinary Item                         28,576             30,560                    64,444              64,005

Extraordinary Item (Net of Tax)                              --            (82,548)                       --             (82,548)
                                                   ------------       ------------             -------------       -------------

NET INCOME (LOSS) After Extraordinary Item         $     28,576       $    (51,988)            $      64,444       $     (18,543)
                                                   ============       ============             =============       =============
DIVIDENDS ON PREFERRED AND
  PREFERENCE STOCK                                          987                991                     1,980               1,989
                                                   ------------       ------------             -------------       -------------
EARNINGS (LOSS) FOR COMMON STOCK
   Before Extraordinary Item                       $     27,589       $     29,569             $      62,464       $      62,016
                                                   ============       ============             =============       =============
EARNINGS (LOSS) FOR COMMON STOCK
   After Extraordinary Item                        $     27,589       $    (52,979)            $      62,464       $     (20,532)
                                                   ============       ============             =============       =============
</TABLE>

See notes to condensed consolidated financial statements.

                                       2
<PAGE>

                             DUQUESNE LIGHT COMPANY
                      CONDENSED CONSOLIDATED BALANCE SHEET
                             (Thousands of Dollars)
                                  (Unaudited)

<TABLE>
<CAPTION>
                                                                        June 30,                 December 31,
                                                                          1999                       1998
                                                                    ----------------            ----------------
<S>                                                                 <C>                         <C>
ASSETS
Property, plant and equipment                                       $      4,606,716            $      4,589,140
Less:  Accumulated depreciation and amortization                          (3,151,225)                 (3,141,841)
                                                                    ----------------            ----------------
    Property, plant and equipment  net                                     1,455,491                   1,447,299
                                                                    ----------------            ----------------
Long-term investments                                                        189,265                     202,256
                                                                    ----------------            ----------------
Current assets:
  Cash and temporary cash investments                                          8,198                      53,151
  Receivables                                                                 80,933                     125,956
  Other current assets, principally material and supplies                    111,949                      92,119
                                                                    ----------------            ----------------
    Total current assets                                                     201,080                     271,226
                                                                    ----------------            ----------------
Other non-current assets:
  Transition costs                                                         2,040,473                   2,132,980
  Regulatory assets                                                           62,153                      64,568
  Other                                                                       68,763                      56,799
                                                                    ----------------            ----------------
    Total other non-current assets                                         2,171,389                   2,254,347
                                                                    ----------------            ----------------
        TOTAL ASSETS                                                $      4,017,225            $      4,175,128
                                                                    ================            ================
CAPITALIZATION AND LIABILITIES
Capitalization:
  Common stock - $1 par value (shares - 90,000,000
    authorized; 10 issued)                                          $             --            $             --
  Capital surplus                                                            746,330                     813,528
  Retained earnings                                                           15,440                      27,646
  Accumulated other comprehensive Income                                      22,823                      27,326
                                                                    ----------------            ----------------
    Total common stockholder's equity                                        784,593                     868,500
                                                                    ----------------            ----------------
  Preferred and preference stock                                             228,940                     227,782
                                                                    ----------------            ----------------
  Long-term debt                                                           1,060,469                   1,160,348
                                                                    ----------------            ----------------
    Total capitalization                                                   2,074,002                   2,256,630
                                                                    ----------------            ----------------
Obligations under capital leases                                              14,992                      36,596
                                                                    ----------------            ----------------
Current liabilities:
  Notes payable and current maturities                                       234,516                      96,137
  Other current liabilities                                                  196,293                     268,141
                                                                    ----------------            ----------------
    Total current liabilities                                                430,809                     364,278
                                                                    ----------------            ----------------
Deferred income taxes - net                                                  567,992                     610,272
                                                                    ----------------            ----------------
Deferred income                                                              112,625                     117,508
                                                                    ----------------            ----------------
Beaver Valley lease liability                                                475,570                     475,570
                                                                    ----------------            ----------------
Other non-current liabilities                                                341,235                     314,274
                                                                    ----------------            ----------------
Commitments and contingencies (Note 4)
                                                                    ----------------            ----------------
        TOTAL CAPITALIZATION AND LIABILITIES                        $      4,017,225            $      4,175,128
                                                                    ================            ================
</TABLE>

See notes to condensed consolidated financial statements.

                                       3
<PAGE>

                             DUQUESNE LIGHT COMPANY
                 CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
                             (Thousands of Dollars)
                                  (Unaudited)

<TABLE>
<CAPTION>
                                                                                Six Months Ended
                                                                                    June 30,
                                                                    -----------------------------------------
                                                                         1999                       1998
                                                                    --------------             --------------
<S>                                                                 <C>                        <C>
Cash Flows From Operating Activities
  Operations                                                        $      156,717             $      219,070
  Changes in working capital other than cash                                (4,471)                   (54,585)
  Increase in ECR                                                               --                    (19,219)
  Other                                                                    (15,389)                     2,507
                                                                    --------------             --------------
    Net Cash Provided By Operating Activities                              136,857                    147,773
                                                                    --------------             --------------
Cash Flows From Investing Activities
  Construction expenditures                                                (40,760)                   (34,621)
  Long-term investments                                                     (1,431)                   (11,537)
  Other                                                                     (4,931)                    (1,025)
                                                                    --------------             --------------
    Net Cash Used in Investing Activities                                  (47,122)                   (47,183)
                                                                    --------------             --------------
Cash Flows From Financing Activities
  Dividends on capital stock                                              (145,431)                   (59,451)
  Increase in notes payable                                                 19,500                         --
  Reductions of long-term obligations - net                                 (9,097)                   (36,938)
  Other                                                                        340                     (5,503)
                                                                    --------------             --------------
    Net Cash Used in Financing Activities                                 (134,688)                  (101,892)
                                                                    --------------             --------------
Net decrease in cash and temporary cash investments                        (44,953)                    (1,302)
Cash and temporary cash investments at beginning of period                  53,151                    165,169
                                                                    --------------             --------------
Cash and temporary cash investments at end of period                $        8,198             $      163,867
                                                                    ==============             ==============
Non-Cash Investing and Financing Activities
  Capital lease obligations recorded                                $        5,988             $        4,941
                                                                    ==============             ==============
</TABLE>

See notes to condensed consolidated financial statements.

                                       4
<PAGE>

                             Duquesne Light Company
                 STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
                             (Thousands of Dollars)
                                  (Unaudited)

<TABLE>
<CAPTION>
                                                          Three Months Ended                      Six Months Ended
                                                               June 30,                               June 30,
                                                        1999              1998                 1999               1998
                                                   ------------     -------------         ------------      -------------
<S>                                                <C>              <C>                   <C>               <C>
NET INCOME                                         $     28,576     $      30,560         $     64,444      $      64,005

Other Comprehensive Income:
  Unrealized holding gains (losses)
     net of tax of $1,470, $(1,083),
     $(2,198) and $1,013, respectively                    2,072            (1,527)              (3,100)             1,429
  Less:  reclassification adjustment for
     gains included in net income, net of
     tax of $0, $0, $756 and $0, respectively                --                --               (1,404)                --
                                                   ------------     -------------         ------------      -------------
        Total Other Comprehensive Income                  2,072            (1,527)              (4,504)             1,429
                                                   ------------     -------------         ------------      -------------
Comprehensive Income                               $     30,648     $      29,033         $     59,940      $      65,434
                                                   ============     =============         ============      =============
</TABLE>

See notes to condensed consolidated financial statements.


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1.   CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES

     Duquesne Light Company (Duquesne) is a wholly owned subsidiary of DQE, Inc.
(DQE), a multi-utility delivery and services company. Duquesne is engaged in the
generation, transmission, distribution and sale of electric energy. Duquesne has
one wholly owned subsidiary, Monongahela Light and Power Company, which makes
long-term investments.

     The Pennsylvania Public Utility Commission (PUC) has approved Duquesne's
plan to divest itself of its generation assets through an auction (including an
auction of its provider of last resort service), and the pending exchange of
certain power station assets with FirstEnergy Corporation (FirstEnergy). Final
agreements governing these transactions must be approved by various regulatory
agencies. Duquesne currently expects these transactions to close in late 1999 or
early 2000. (See "Rate Matters," Note 2, on page 7.)

     The condensed consolidated financial statements include the accounts of
Duquesne and its wholly owned subsidiary.  All material intercompany balances
and transactions have been eliminated in the preparation of the condensed
consolidated financial statements.

     In the opinion of management, the unaudited condensed consolidated
financial statements included in this report reflect all adjustments that are
necessary for a fair presentation of the results of interim periods and are
normal, recurring adjustments.  Prior periods have been reclassified to conform
with accounting presentations adopted during 1999.

     These statements should be read with the financial statements and notes
included in the Annual Report on Form 10-K filed with the Securities and
Exchange Commission (SEC) for the year ended December 31, 1998.  The results of
operations for the three and six months ended June 30, 1999, are not necessarily
indicative of the results that may be expected for the full year.  The

                                       5
<PAGE>

preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements.  The
reported amounts of revenues and expenses during the reporting period may also
be affected by the estimates and assumptions management is required to make.
Actual results could differ from those estimates.

     Duquesne is subject to the accounting and reporting requirements of the
SEC. In addition, Duquesne's electric utility operations are subject to
regulation by the PUC, including regulation under the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Customer Choice Act), and the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters.

     As a result of the PUC's May 29, 1998, final order regarding Duquesne's
restructuring plan under the Customer Choice Act (see "Rate Matters," Note 2, on
page 7), the electricity generation portion of Duquesne's business does not meet
the criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, fixed assets related to the generation portion of Duquesne's
business are evaluated in accordance with SFAS No. 121, Accounting for the
Impairment of Long- Lived Assets and for Long-Lived Assets to Be Disposed Of
(SFAS No. 121). Pursuant to the PUC's final restructuring order, certain of
Duquesne's generation-related regulatory assets are being recovered through a
competitive transition charge (CTC) collected in connection with providing
transmission and distribution services (the electricity delivery business
segment), and have been reclassified accordingly. Additionally, pursuant to the
PUC's final restructuring order, Duquesne is recovering its above-market
investment in generation assets through the CTC, subject to receipt of the
proceeds from the generation asset auction. The electricity delivery business
segment continues to meet SFAS No. 71 criteria and accordingly reflects
regulatory assets and liabilities consistent with cost-based ratemaking
regulations. The regulatory assets represent probable future revenue to
Duquesne, because provisions for these costs are currently included, or are
expected to be included, in charges to electric utility customers through the
ratemaking process. (See "Rate Matters," Note 2, below.)

     Through the Energy Cost Rate Adjustment Clause (ECR), Duquesne previously
recovered (to the extent that such amounts were not included in base rates)
nuclear fuel, fossil fuel and purchased power expenses. Also through the ECR,
Duquesne passed to its customers the profits from short- term power sales to
other utilities (collectively, ECR energy costs). As a consequence of the PUC's
final order regarding Duquesne's restructuring plan (see "Rate Matters," Note 2,
below), such costs are no longer recoverable through the ECR. Instead, effective
May 29, 1998 (the date of the PUC's final restructuring order), such costs are
expensed as incurred and thus impact net income. Under-recoveries from customers
prior to May 29, 1998, were recorded on the consolidated balance sheet as a
regulatory asset. At June 30, 1999 and December 31, 1998, $42.7 million was
receivable from customers. Duquesne expects to recover this amount through the
CTC. (See "Restructuring Plan" discussion, Note 2, on page 7.)

     Duquesne's long-term investments include assets of nuclear decommissioning
trusts and marketable securities accounted for in accordance with SFAS No. 115,
Accounting for Certain Investments in Debt and Equity Securities.  These
investments are classified as available-for-sale and are stated at market value.
The amounts of unrealized holding gains related to marketable securities  were
$39.0 million ($22.8 million, net of tax) at June 30, 1999, and $46.5 million
($27.3 million, net of tax) at December 31, 1998.

                                       6
<PAGE>

2.   RATE MATTERS

Competition and the Customer Choice Act

     Under historical ratemaking practice, regulated electric utilities were
granted exclusive geographic franchises to sell electricity, in exchange for
making investments and incurring obligations to serve customers under the then-
existing regulatory framework. Through the ratemaking process, those prudently
incurred costs were recovered from customers, along with a return on the
investment. Additionally, certain operating costs were approved for deferral for
future recovery from customers (regulatory assets). As a result of this process,
utilities had assets recorded on their balance sheets at above-market costs,
thus creating transition and stranded costs.

     In Pennsylvania, the Customer Choice Act went into effect on January 1,
1997. The Customer Choice Act enables Pennsylvania's electric utility customers
to purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act provides that the
existing franchised utility may recover, through a CTC, an amount of transition
costs that are determined by the PUC to be just and reasonable. Pennsylvania's
electric utility restructuring is being accomplished through a two-stage process
consisting of an initial customer choice pilot period (which ended in December
1998) and a phase-in to competition period (which began in January 1999).

Phase-In to Competition

     The phase-in to competition began in January 1999, when 66 percent of
customers became eligible to participate in customer choice (including customers
covered by the pilot program); all customers will have customer choice in
January 2000. As of June 30, 1999, approximately 14 percent of Duquesne's
customers had chosen alternative generation suppliers. Customers that have
chosen an electricity generation supplier other than Duquesne pay that supplier
for generation charges, and pay Duquesne the CTC (discussed below) and charges
for transmission and distribution. Customers that continue to buy their
generation from Duquesne pay for their service at current regulated tariff rates
divided into generation, transmission and distribution charges, and the CTC.
Under the Customer Choice Act, an electric distribution company, such as
Duquesne, remains a regulated utility and may only offer PUC-approved rates,
including generation rates. Also under the Customer Choice Act, electricity
delivery (including transmission, distribution and customer service) remains
regulated in substantially the same manner as under historical regulation.

     In an effort to "jumpstart" competition, Duquesne had made 600 megawatts
(MW) of power available through the first six months of 1999 to licensed
electric generation suppliers, to be used to supply electricity to Duquesne's
customers who had chosen alternative generation suppliers.

Rate Cap

     An overall four-and-one-half-year rate cap from January 1, 1997, has been
imposed on the transmission and distribution charges of Pennsylvania electric
utility companies under the Customer Choice Act. Additionally, electric utility
companies may not increase the generation price component of rates as long as
transition costs are being recovered, with certain exceptions.

Restructuring Plan

     In its May 29, 1998, final restructuring order, the PUC determined that
Duquesne should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The total of the transition costs to be recovered
was $1,485 million, net of tax, over a seven-year period beginning January 1,
1999, as may be adjusted to account for the proceeds of the generation asset
auction. In addition, the transition

                                       7
<PAGE>

costs as reflected on the consolidated balance sheet are being amortized over
the same period that the CTC revenues are being recognized. Duquesne is allowed
to earn an 11 percent pre-tax return on the unrecovered, net of tax balance of
transition costs, as adjusted following the generation asset auction.

     As part of its restructuring plan filing, Duquesne requested recovery of
$11.5 million ($6.7 million, net of tax) through the CTC for energy costs
previously deferred under the ECR. Recovery of this amount was approved in the
PUC's final restructuring order. Duquesne also requested recovery of an
additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On
December 18, 1998, the PUC denied recovery of this additional amount. Duquesne
has appealed the PUC's denial of recovery to the Pennsylvania Commonwealth
Court. Based upon the Customer Choice Act, which mandates recovery of all
regulatory assets, and the PUC's specific authorization for Duquesne to create a
regulatory asset for these costs, Duquesne believes that it is probable that
these costs will be recovered through retail rates. In the event that Duquesne
does not prevail in its appeal, these costs would be written off as a charge
against income.

     Restructuring Plan and Auction Plan. With respect to transition cost
recovery, the PUC's final order on the restructuring plan approved Duquesne's
proposal to auction its generation assets and use the proceeds to offset
transition costs. The remaining balance of such costs (with certain exceptions
described below) is expected to be recovered from ratepayers through the CTC.
Until the divestiture is complete, Duquesne has been ordered to use an interim
CTC and price to compare for each rate class based on the methodology approved
in its pilot program (on average, approximately 2.9 cents per kilowatt hour
(KWH) for the CTC and approximately 3.8 cents per KWH for the price to compare).

     On December 18, 1998, the PUC approved Duquesne's auction plan, including
an auction of its provider of last resort service, as well as an agreement in
principle to exchange certain generation assets with FirstEnergy. The assets to
be auctioned will include Duquesne's wholly owned Cheswick , Elrama, Phillips
and Brunot Island power stations, as well as the stations to be received from
FirstEnergy in the power station exchange described below. The auction plan
calls for a two-phase, sealed bid process similar to that used in other power
plant divestitures. The initial confidential bidding process began in April
1999, with potential buyers identified by Duquesne being asked to submit non-
binding bids. Qualified applicants have been asked to submit binding, second-
round bids, due in September 1999.  Final agreements governing the transactions
must be approved by various regulatory agencies, including the PUC, the FERC,
the NRC, and the Federal Trade Commission. Duquesne currently expects the sale
to close at the end of 1999 or the beginning of 2000.

     Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in
certain power stations. Duquesne will receive 100 percent ownership rights in
three coal-fired power plants located in Avon Lake and Niles, Ohio and New
Castle, Pennsylvania (totaling approximately 1,300 MW), which Duquesne expects
to sell as part of the auction of generation assets. FirstEnergy will acquire
Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2
(BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield
Units 1, 2 and 3 (totaling approximately 1,400 MW). In connection with the power
station exchange, Duquesne anticipates terminating the BV Unit 2 lease in
December 1999. (See "Financing" discussion on page 21.) Pursuant to the December
18, 1998, PUC order and subject to final approval, the proceeds from the sale of
the power stations received in the exchange will be used to offset the
transition costs associated with Duquesne's currently-held generation assets and
costs associated with completing the exchange. Duquesne expects this exchange to
enhance the value received from the auction, because participants will bid on
entire plants, rather than plants that are jointly owned and/or operated by
another entity. Additionally, the auction will include only coal- and oil-fired
plants, which are anticipated to have a higher market value than nuclear plants.
These value-enhancing features, along with a minimum level

                                       8
<PAGE>

of auction proceeds guaranteed by FirstEnergy, are expected to maximize auction
proceeds, minimize transition costs required to be recovered through the CTC (by
shortening the length of the CTC recovery period), and thus reduce customer
bills as rapidly as possible. Other benefits of this exchange include the
resolution of all joint ownership issues, and other risks and costs associated
with the jointly-owned units.  The Federal Trade Commission approved the
exchange on June 30, 1999.  The PUC approved the definitive exchange agreement
on July 15, 1999, having found the exchange to be in the public interest.
Certain aspects of the exchange have yet to be approved by, among other
agencies, the FERC, the NRC and, solely with respect to reliability issues,
the Public Utilities Commission of Ohio. The power station exchange is expected
to occur at the end of 1999 or in early 2000.  (See "Legal Proceedings" on
page 28.)

Termination of the AYE Merger

     On October 5, 1998, DQE announced its unilateral termination of the merger
agreement between DQE and Allegheny Energy, Inc. (AYE). DQE believes that AYE
suffered a material adverse effect as a result of the PUC's final restructuring
order regarding AYE's utility subsidiary, West Penn Power Company. AYE filed
suit in the United States District Court for the Western District of
Pennsylvania, seeking to compel DQE to proceed with the merger and seeking a
temporary restraining order and preliminary injunction to prevent DQE from
certain actions pending a trial, or in the alternative seeking an unspecified
amount of money damages. DQE and AYE continue to litigate this matter. (See
"Legal Proceedings" on page 28.)  In a letter dated February 24, 1999, the PUC
informed DQE that the merger application was deemed withdrawn and the docket was
closed.

3.   RECEIVABLES

     Components of receivables for the periods indicated are as follows:

<TABLE>
<CAPTION>
                                                             June 30,         June 30,      December 31,
                                                               1999             1998            1998
                                                                   (Amounts in Thousands of Dollars)
--------------------------------------------------------------------------------------------------------
<S>                                                          <C>              <C>           <C>
Electric customer accounts receivable                         $ 86,136         $ 87,830        $ 87,262
Other utility receivables                                       22,154           20,907          25,412
Other receivables                                               32,951           31,067          22,419
Less:  Allowance for uncollectible accounts                    (10,308)         (16,784)         (9,137)
--------------------------------------------------------------------------------------------------------
Receivables less allowance for  uncollectible                  130,933          123,020         125,956
 accounts
Less:  Receivables sold                                        (50,000)              --              --
========================================================================================================
     Total Receivables                                        $ 80,933         $123,020         $125,956
========================================================================================================
</TABLE>

     Duquesne and an unaffiliated corporation have an agreement that entitles
Duquesne to sell and the corporation to purchase, on an ongoing basis, up to $50
million of accounts receivable. The accounts receivable sales agreement, the
expiration of which has been extended until late August 1999, is one of many
sources of funds available to Duquesne.  Duquesne currently anticipates further
extending the agreement or replacing it with a similar arrangement upon
expiration.  At June 30, 1999, Duquesne had sold $50 million of receivables. At
June 30 and December 31, 1998, Duquesne had not sold any receivables.

                                       9
<PAGE>

4.   COMMITMENTS AND CONTINGENCIES

     Duquesne anticipates divesting itself of its generation assets through the
auction and the power station exchange by early 2000 and, depending on the
regulatory approvals of the final agreements regarding the divestiture, expects
certain obligations related to the divested assets will be transferred to the
future owners. (See "Restructuring Plan" discussion, Note 2, on page 7.)

Construction

     Duquesne currently estimates that during 1999 it will spend, excluding the
Allowance for Funds Used During Construction and nuclear fuel, approximately
$110 million (including $30 million for generation) for electric utility
construction.

Nuclear-Related Matters

     Duquesne has an interest in three nuclear units, two of which it operates.
The operation of a nuclear facility involves special risks, potential
liabilities, and specific regulatory and safety requirements. Specific
information about risk management and potential liabilities is discussed below.

     Nuclear Decommissioning. Duquesne expects to decommission BV Unit 1, BV
Unit 2 and Perry Unit 1 no earlier than the expiration of each plant's operating
license in 2016, 2027 and 2026, respectively. At the end of its operating life,
BV Unit 1 may be placed in safe storage until BV Unit 2 is ready to be
decommissioned, at which time the units may be decommissioned together.

     Based on site-specific studies conducted in 1997 for BV Unit 1 and BV
Unit 2, and a 1997 update of the 1994 study for Perry Unit 1, Duquesne's
approximate share of the total estimated decommissioning costs, including
removal and decontamination costs, is $170 million, $55 million and $90 million,
respectively. The amount currently used to determine Duquesne's cost of service
related to decommissioning all three nuclear units is $224 million. Funding for
nuclear decommissioning costs is deposited in external, segregated trust
accounts and invested in a portfolio of corporate common stock and debt
securities, municipal bonds, certificates of deposit and United States
government securities. The market value of the aggregate trust fund balances
at June 30, 1999, totaled approximately $69.4 million.

     As part of the power station exchange, FirstEnergy has agreed to assume the
decommissioning liability for each of the nuclear plants in exchange for the
balance in the decommissioning trust funds, plus the decommissioning costs to be
collected through the CTC, as approved by the PUC.

     Nuclear Insurance. The Price-Anderson Amendments to the Atomic Energy Act
of 1954 limit public liability from a single incident at a nuclear plant to $9.7
billion. The maximum available private primary insurance of $200 million has
been purchased by Duquesne. Additional protection of $9.5 billion would be
provided by an assessment of up to $88.1 million per incident on each licensed
nuclear unit in the United States. Duquesne's maximum total possible assessment,
$66.1 million, which is based on its ownership or leasehold interests in three
nuclear generating units, would be limited to a maximum of $7.5 million per
incident per year. This assessment is subject to indexing for inflation and may
be subject to state premium taxes. If assessments from the nuclear industry
prove insufficient to pay claims, the United States Congress could impose other
revenue-raising measures on the industry.

     Duquesne's share of insurance coverage for property damage, decommissioning
and decontamination liability is $1.2 billion. Duquesne would be responsible for
its share of any damages in excess of insurance coverage. In addition, if the
property damage reserves of Nuclear Electric Insurance Limited (NEIL), an
industry mutual insurance company that provides a portion of this coverage, are
inadequate to cover claims arising from an incident at any United States nuclear
site covered by that insurer, Duquesne could be assessed retrospective premiums
totaling a maximum of $7.9 million. Duquesne also participates in a NEIL program
that provides insurance for the increased cost of generation and/or purchased
power resulting from an accidental outage of a nuclear unit.

                                       10
<PAGE>

Subject to the policy deductible, terms and limit, the coverage provides for
a weekly indemnity of the estimated incremental costs during a period of
approximately three years, starting 12 weeks after an accident, with no coverage
thereafter. If NEIL's losses for this program ever exceed its reserves, Duquesne
could be assessed retrospective premiums totaling a maximum of $2.9 million.

     Beaver Valley Power Station (BVPS). BVPS's two units are equipped with
steam generators designed and built by Westinghouse Electric Corporation
(Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter
stress corrosion cracking (ODSCC) has occurred in the steam generator tubes of
both units. BV Unit 1, which was placed in service in 1976, has removed
approximately 17 percent of its steam generator tubes from service through a
process called "plugging." However, BV Unit 1 still has the capability to
operate at 100 percent reactor power and has the ability to return tubes to
service by repairing them through a process called "sleeving." No tubes at
either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was
placed in service 11 years after BV Unit 1, has not yet exhibited the degree of
ODSCC experienced at BV Unit 1. Approximately 3 percent of BV Unit 2's tubes are
plugged; however, it is too early in the life of the unit to determine the
extent to which ODSCC may become a problem at that unit.

     Duquesne has undertaken certain measures, such as increased inspections,
water chemistry control and tube plugging, to minimize the operational impact of
and reduce susceptibility to ODSCC. Although Duquesne has taken these steps to
allay the effects of ODSCC, the inherent potential for future ODSCC in steam
generator tubes of the Westinghouse design still exists. Material acceleration
in the rate of ODSCC could lead to a loss of plant efficiency, significant
repairs or the possible replacement of the BV Unit 1 steam generators. The total
replacement cost of the BV Unit 1 steam generators is currently estimated at
$125 million. Duquesne would be responsible for $59 million of this total, which
includes the cost of equipment removal and replacement steam generators, but
excludes replacement power costs. The earliest that the BV Unit 1 steam
generators could be replaced during a currently scheduled refueling outage is
the spring of 2003.

     Duquesne continues to explore all viable means of managing ODSCC, including
new repair technologies, and plans to continue to perform 100 percent tube
inspections during future refueling outages.  BV Unit 1's next refueling outage
is currently scheduled to begin in the spring of 2000. BV Unit 2's next
refueling outage is currently scheduled for the fall of 2000. Duquesne will
continue to monitor and evaluate the condition of the BVPS steam generators.

     Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982
established a federal policy for handling and disposing of spent nuclear fuel
and a policy requiring the establishment of a final repository to accept spent
nuclear fuel. Electric utility companies have entered into contracts with the
United States Department of Energy (DOE) for the permanent disposal of spent
nuclear fuel and high-level radioactive waste in compliance with this
legislation. The DOE has indicated that its repository under these contracts
will not be available for acceptance of spent nuclear fuel before 2010. The DOE
has not yet established an interim or permanent storage facility, despite a
ruling by the United States Court of Appeals for the District of Columbia
Circuit that the DOE was legally obligated to begin acceptance of spent nuclear
fuel for disposal by January 31, 1998. Existing on-site spent nuclear fuel
storage capacities at BV Unit 1, BV Unit 2 and Perry Unit 1 are expected to be
sufficient until 2018, 2012 and 2011, respectively.

     In early 1997, Duquesne joined 35 other electric utilities and 46 states,
state agencies and regulatory commissions in filing suit in the United States
Court of Appeals for the District of Columbia Circuit against the DOE. The
parties requested the court to suspend the utilities' payments into the Nuclear
Waste Fund and to place future payments into an escrow account until the DOE
fulfills its obligation to accept spent nuclear fuel. The DOE had requested that
the court delay litigation while it pursued alternative dispute resolution under
the terms of its contracts with the utilities. The court ruling, issued November
14, 1997, and affirmed on rehearing May 5, 1998, denied the relief requested by
the utilities and states and permitted the DOE to pursue alternative dispute
resolution, but prohibited the DOE from using its lack of a spent fuel
repository as a defense. The United States Supreme Court declined to review the
decision. The utilities' remaining remedies are to

                                       11
<PAGE>

sue the DOE in federal court for money damages caused by the DOE's delay in
fulfilling its obligations, or to pursue an equitable contract adjustment before
the DOE contracting officer.

     Uranium Enrichment Obligations. Nuclear reactor licensees in the United
States are assessed annually for the decontamination and decommissioning of DOE
uranium enrichment facilities. Assessments are based on the amount of uranium a
utility had processed for enrichment prior to enactment of the National Energy
Policy Act of 1992, and are to be paid by such utilities over a 15-year period.
At June 30, 1999, Duquesne's liability for contributions is being recovered
through the CTC as part of transition costs.

Guarantees

     Duquesne and the other owners of Bruce Mansfield Power Station (Bruce
Mansfield) have guaranteed certain debt and lease obligations related to a coal
supply contract for Bruce Mansfield. At June 30, 1999, Duquesne's share of these
guarantees was $5.4 million.

Environmental Matters

     Various federal and state authorities regulate Duquesne with respect to air
and water quality and other environmental matters.  Duquesne believes it is in
current compliance with all material applicable environmental regulations.

Employees

     As previously reported, in connection with the anticipated divestiture,
Duquesne has developed early retirement programs and enhanced separation
packages.  To date, approximately 250 eligible employees have elected to
participate in early retirement.

Other
     Duquesne is involved in various other legal proceedings and environmental
matters. Duquesne believes that such proceedings and matters, in total, will not
have a materially adverse effect on its financial position, results of
operations or cash flows.

5.   BUSINESS SEGMENTS AND RELATED INFORMATION

     Historically, Duquesne has been treated as a single integrated business
segment due to its regulated operating environment. The PUC authorized a
combined rate for supplying and delivering electricity to customers which was
cost-based and was designed to recover Duquesne's operating expenses and
investment in electric utility assets and to provide a return on the investment.
As a result of the Customer Choice Act, generation of electricity is deregulated
and charged at a separate rate from the delivery of electricity beginning in
1999. For the purposes of complying with SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information (SFAS No. 131), Duquesne is
required to disclose information about its business segments separately.
Accordingly, Duquesne has used the PUC-approved separate rates for 1999 to
develop the financial information of the business segments for the three and six
months ended June 30, 1998 (or as of December 31, 1998, with respect to assets).

     Beginning in 1999, Duquesne has three principal business segments
(determined by products, services and regulatory environment) which consist of
the transmission and distribution by Duquesne of electricity (electricity
delivery business segment); the generation by Duquesne of electricity
(electricity generation business segment); and the collection of transition
costs (CTC business segment). To comply with SFAS No. 131, Duquesne has reported
the results for 1999 by these business segments and an "all other" category. The
all other category in the following table includes Duquesne investments below
the quantitative threshold for separate disclosure. However, as Duquesne was not
yet collecting transition costs prior to 1999, the 1998 results are reported by
the electricity delivery and electricity generation business segments.

     Financial data for business segments is provided as follows:

                                       12
<PAGE>

Business Segments for the Three Months Ended

<TABLE>
<CAPTION>

June 30, 1999                                            (Thousands of Dollars)
--------------------------------------------------------------------------------------------------------
                               Electricity    Electricity                       All
                                 Delivery     Generation           CTC         Other      Consolidated
                             ---------------------------------------------------------------------------
<S>                          <C>             <C>             <C>             <C>          <C>
Operating revenues           $    81,077     $  102,782      $   89,380       $     --     $   273,239
Operating expenses                48,689         98,178          23,858            978         171,703
Depreciation and
     amortization expense         12,821          8,807          25,430             --          47,058
--------------------------------------------------------------------------------------------------------
      Operating income (loss)     19,567         (4,203)         40,092           (978)         54,478
Other income                         648          2,045              --          3,464           6,157
Interest and other charges         9,157         11,814          12,007             68          33,046
--------------------------------------------------------------------------------------------------------
     Earnings (loss) for
          common stock       $    11,058     $  (13,972)     $   28,085       $  2,418     $    27,589
========================================================================================================
Assets                       $ 1,303,969     $  536,680      $2,040,473       $136,103     $ 4,017,225
========================================================================================================
Capital expenditures         $    15,218     $    9,127      $       --       $     --     $    24,345
========================================================================================================
</TABLE>

<TABLE>
<CAPTION>

June 30, 1998                                               (Thousands of Dollars)
---------------------------------------------------------------------------------------------------
                                            Electricity   Electricity      All
                                             Delivery      Generation     Other      Consolidated
                                           --------------------------------------------------------
<S>                                        <C>           <C>            <C>          <C>
Operating revenues                         $    76,355   $   210,681    $     297     $  287,333
Operating expenses                              45,461       139,463          487        185,411
Depreciation and
     amortization expense                       12,335        43,769           --         56,104
-------------------------------------------------------------------------------------------------
     Operating income (loss)                    18,559        27,449         (190)        45,818
Other income                                       610         1,480        5,879          7,969
Interest and other charges                       9,432        14,661          125         24,218
-------------------------------------------------------------------------------------------------
     Earnings (loss) for common stock,
          before extraordinary item        $     9,737   $    14,268    $   5,564     $   29,569
     Extraordinary item, net of tax                 --       (82,548)          --        (82,548)
-------------------------------------------------------------------------------------------------
     Earnings (loss) for common stock,
          after extraordinary item         $     9,737   $   (68,280)   $   5,564     $  (52,979)
=================================================================================================
Assets(1)                                  $ 1,314,266   $ 2,711,533    $ 149,329     $4,175,128
=================================================================================================
Capital expenditures                       $    10,173   $    11,064    $      --     $   21,237
=================================================================================================
</TABLE>

(1)  Relates to assets as of December 31, 1998.

                                       13
<PAGE>

Business Segments for the Six Months Ended

<TABLE>
<CAPTION>

June 30, 1999                                            (Thousands of Dollars)
--------------------------------------------------------------------------------------------------------
                                  Electricity   Electricity                      All
                                   Delivery     Generation         CTC          Other      Consolidated
                                ------------------------------------------------------------------------
<S>                             <C>             <C>            <C>            <C>          <C>
Operating revenues              $   163,398     $  209,413     $   182,404    $      --    $    555,215
Operating expenses                   95,479        197,280          47,701        1,370         341,830
Depreciation and
     amortization expense            27,172         17,663          55,063           --          99,898
--------------------------------------------------------------------------------------------------------
      Operating income (loss)        40,747         (5,530)         79,640       (1,370)        113,487
Other income                          1,783          3,851                        8,758          14,392
Interest and other charges           18,043         23,522          23,715          135          65,415
--------------------------------------------------------------------------------------------------------
     Earnings (loss) for
          common stock          $    24,487     $  (25,201)    $    55,925    $   7,253     $    62,464
========================================================================================================
Assets                          $ 1,303,969     $  536,680     $ 2,040,473    $ 136,103     $ 4,017,225
========================================================================================================
Capital expenditures            $    28,644     $   12,116     $        --    $      --     $    40,760
========================================================================================================
</TABLE>

<TABLE>
<CAPTION>

June 30, 1998                                               (Thousands of Dollars)
---------------------------------------------------------------------------------------------------
                                            Electricity   Electricity      All
                                             Delivery      Generation     Other      Consolidated
                                           --------------------------------------------------------
<S>                                        <C>           <C>            <C>          <C>
Operating revenues                         $   155,298   $   416,895    $     297     $   572,490
Operating expenses                              91,633       277,401          523         369,557
Depreciation and
     amortization expense                       24,504        87,280           --         111,784
---------------------------------------------------------------------------------------------------
     Operating income (loss)                    39,161        52,214         (226)         91,149
Other income                                     1,563         3,386       14,723          19,672
Interest and other charges                      19,032        29,581          192          48,805
---------------------------------------------------------------------------------------------------
     Earnings (loss) for common stock,
          before extraordinary item        $    21,692   $    26,019    $    14,305   $    62,016
     Extraordinary item, net of tax                 --       (82,548)            --       (82,548)
---------------------------------------------------------------------------------------------------
     Earnings (loss) for common stock,
          after extraordinary item         $    21,692   $   (56,529)   $    14,305   $   (20,532)
===================================================================================================
Assets(1)                                  $ 1,314,266   $ 2,711,533    $   149,329   $ 4,175,128
===================================================================================================
Capital expenditures                       $    19,111   $    15,510    $        --   $    34,621
===================================================================================================
</TABLE>

(1)  Relates to assets as of December 31, 1998.

                                       14
<PAGE>

Item 2.  Management's Discussion and Analysis of Financial Condition and Results
         of Operations

Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in
conjunction with Duquesne Light Company's Annual Report on Form 10-K filed with
the Securities and Exchange Commission (SEC) for the year ended December 31,
1998 and its condensed consolidated financial statements, which are set forth on
pages 2 through 14  in Part I, Item 1 of this Report.

General
--------------------------------------------------------------------------------

     Duquesne Light Company (Duquesne) is a wholly owned subsidiary of DQE, Inc.
(DQE), a multi-utility delivery and services company. Duquesne is engaged in the
generation, transmission, distribution and sale of electric energy. Duquesne has
one wholly owned subsidiary, Monongahela Light and Power Company, which
currently holds energy-related investments.

     The Pennsylvania Public Utility Commission (PUC) has approved Duquesne's
plan to divest itself of its generation assets through an auction (including an
auction of its provider of last resort service), and the pending exchange of
certain power station assets with FirstEnergy Corporation (FirstEnergy). Final
agreements governing these transactions must be approved by various regulatory
agencies. Duquesne currently expects these transactions to close in late 1999 or
early 2000. (See "Rate Matters" on page 22.)

Service Territory

     Duquesne provides electric service to customers in Allegheny County
(including the City of Pittsburgh), Beaver County and, to a limited extent,
Westmoreland County. (See "Rate Matters" on page 22.) This territory represents
approximately 800 square miles in southwestern Pennsylvania. In addition to
serving approximately 580,000 direct customers, Duquesne also sells electricity
to other utilities.

Regulation

     Duquesne is subject to the accounting and reporting requirements of the
SEC. In addition, Duquesne's electric utility operations are subject to
regulation by the PUC, including regulation under the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Customer Choice Act), and the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters. (See "Rate Matters" on page 22.)

     Duquesne's electric utility operations are also subject to regulation by
the Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954, as
amended, with respect to the operation of its jointly owned/leased nuclear power
plants, Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and
Perry Unit 1.

     As a result of the PUC's May 29, 1998, final order regarding Duquesne's
restructuring plan under the Customer Choice Act (see "Rate Matters" on page
22), the electricity generation portion of Duquesne's business does not meet the
criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, fixed assets related to the generation portion of Duquesne's
business are evaluated in accordance with SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of
(SFAS No. 121). Pursuant to the PUC's final restructuring order, certain of
Duquesne's generation-related regulatory assets are being recovered through a
competitive transition charge (CTC) collected in connection with providing
transmission and distribution services (the electricity delivery business
segment), and have been reclassified accordingly. Additionally, pursuant to the
PUC's final restructuring order, Duquesne is recovering its above-market
investment in generation assets through the CTC, subject to receipt of the
proceeds from the generation asset auction. The electricity delivery business
segment continues to meet SFAS No. 71 criteria, and accordingly reflects
regulatory assets and liabilities consistent with cost-based ratemaking

                                       15
<PAGE>

regulations. The regulatory assets represent probable future revenue to
Duquesne, because provisions for these costs are currently included, or are
expected to be included, in charges to electric utility customers through the
ratemaking process. (See "Rate Matters" on page 22.)

Results of Operations
--------------------------------------------------------------------------------

Overall Performance

     In the second quarter of 1998, the PUC issued an order related to
Duquesne's plan to recover its stranded costs from electric utility customers.
As a result of the order, Duquesne recorded an extraordinary charge
(Restructuring Charge) against earnings of $82.5 million, or $1.06 per share.
The following discussion of results of operations excludes the impact of that
Restructuring Charge.

     Comparison of Three Months Ended June 30, 1999, and June 30, 1998.
Duquesne's earnings available for common stock were $27.6 million in the second
quarter of 1999, a decrease of 6.7%.  This decrease was the result of costs
related to scheduled generating station maintenance and refueling outages.  In
previous periods, when the electricity generation business segment was rate
regulated, these costs were deferred for future rate recovery.

     Comparison of Six Months Ended June 30, 1999, and June 30, 1998.
Duquesne's earnings available for common stock were $62.5 million for the six
months ended June 30, 1999, which is relatively consistent with 1998 earnings.

     Subsequent Events. During the latter part of July 1999, a prolonged,
wide-spread heat wave in the eastern half of the United States led to
unprecedented market prices for purchased power, record peak demands and
regional capacity constraints. This combination of factors resulted in
unexpected net purchased power costs of approximately $24 million. Because of
these unexpected costs, July's earnings will be reduced by approximately $0.18
per share of DQE common stock. Duquesne did not default on any wholesale
supply commitments and did not curtail any firm retail load during July.
During the first 13 days of August, Duquesne has been a net seller of
wholesale power. Duquesne believes its purchased power price risk will be
eliminated in the future by the auction of its generating stations and
provider of last resort obligation. (See "Rate Matters" on page 22.) The
foregoing statements are forward-looking regarding the impact on earnings of
Duquesne's power purchases and divestiture of generation assets, and purchased
power risks. Actual results could materially differ from those implied by such
statements due to known and unknown risks and uncertainties, including, but
not limited to, weather conditions, market prices and availability of power,
availability of Duquesne's generating stations, constraints on regional
transmission facilities, and timing of divestiture closings.

Results by Business Segment

  Historically, Duquesne has been treated as a single integrated business
segment due to its regulated operating environment. The PUC authorized a
combined rate for supplying and delivering electricity to customers which was
cost-based and was designed to recover Duquesne's operating expenses and
investment in electric utility assets and to provide a return on the investment.
As a result of the Customer Choice Act, generation of electricity is deregulated
and charged at a separate rate from the delivery of electricity beginning in
1999. For the purposes of complying with SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information (SFAS No. 131), Duquesne is
required to disclose information about its business segments separately.
Accordingly, Duquesne has used the PUC-approved separate rates for 1999 to
develop the financial information of the business segments for 1998.

     Beginning in 1999, Duquesne has three principal business segments
(determined by products, services and regulatory environment): (1) the
transmission and distribution by Duquesne of electricity (electricity delivery
business segment),  (2) the generation by Duquesne of electricity (electricity
generation business segment), and (3) the collection of transition costs (CTC
business segment). Duquesne has reported the results for 1999 by these business
segments and an "all other" category. The all other category includes Duquesne
investments in leasing and gas reserve transactions.  However, as Duquesne was
not yet collecting transition costs prior to 1999, the 1998 results are reported
by the electricity delivery and electricity generation business segments.
(Additional information regarding Duquesne's business segments is set forth in
"Business Segments and Related Information," Note 5 to the consolidated
financial statements on page 12.)

Electricity Delivery Business Segment

     Comparison of Three Months Ended June 30, 1999, and June 30, 1998.  The
electricity delivery business segment contributed $11.1 million to net income in
the second quarter of 1999 compared to $9.7 million in the second quarter of
1998, an increase of 13.6 percent. Operating revenues for this business segment
are primarily derived from Duquesne's delivery of electricity and services
provided to electric generation suppliers.

     Sales to residential and commercial customers are influenced by weather
conditions. Warmer summer and colder winter seasons lead to increased customer
use of electricity for cooling and heating. Commercial sales are also affected
by regional development. Sales to industrial customers are influenced by
national and global economic conditions.

                                       16
<PAGE>

     Operating revenues increased by $4.7 million or 6.2 percent in the second
quarter of 1999 due to an increase in electricity usage by customers of 2.1
percent and to services provided to electric generation suppliers. The following
table sets forth KWH delivered to electric utility customers during the second
quarter:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                                                  KWH Delivered
                                                  --------------------------------------------
                                                                  (In Millions)
                                                  --------------------------------------------
Three Months Ended June 30,                         1999            1998              Change
----------------------------------------------------------------------------------------------
<S>                                               <C>              <C>                <C>
Residential                                         751.8            730.9              2.9%
Commercial                                        1,457.4          1,434.3              1.6%
Industrial                                          872.9            853.4              2.3%
---------------------------------------------------------------------------------
     Sales to Electric Utility Customers          3,082.1          3,018.6              2.1%
==============================================================================================
</TABLE>

     Operating expenses for the electricity delivery business segment are
primarily made up of costs to operate and maintain the transmission and
distribution system; meter reading and billing costs; customer service;
collection; administrative expenses; income taxes; and non-income taxes, such as
property and payroll taxes. Operating expenses increased $3.2 million or 7.1
percent in the second quarter of 1999, primarily due to the timing of non-
recurring charges related to meter reading in both 1999 and 1998.

     Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In the second quarter of
1999, there was $0.3 million or 2.9 percent less in interest and other charges
compared to the second quarter of 1998. The decrease was the result of the
refinancing of long-term debt at lower interest rates and the maturity of
approximately $75 million of long-term debt during 1998.

     Comparison of Six Months Ended June 30, 1999, and June 30, 1998.  The
electricity delivery business segment contributed $24.5 million to net income in
the first six months of 1999 compared to $21.7 million in the first six months
of 1998, an increase of 12.9 percent.

     Operating revenues increased by $8.1 million or 5.2 percent in the first
six months of 1999, due to a 2.0 percent increase in electricity usage by
customers and to services provided to electric generation suppliers.  Sales to
residential and commercial customers increased due to weather conditions, while
industrial sales decreased primarily due to a reduction in electricity
consumption by steel manufacturers, which experienced a decline in demand. The
following table sets forth KWH delivered to electric utility customers during
the first six months of 1999 and 1998:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                                                  KWH Delivered
                                                  --------------------------------------------
                                                                  (In Millions)
                                                  --------------------------------------------
Six Months Ended June 30,                           1999            1998              Change
----------------------------------------------------------------------------------------------
<S>                                               <C>              <C>                <C>
Residential                                       1,668.4          1,599.3              4.3%
Commercial                                        2,897.6          2,814.0              3.0%
Industrial                                        1,723.7          1,754.3             (1.7)%
---------------------------------------------------------------------------------
     Sales to Electric Utility Customers          6,289.7          6,167.6              2.0%
==============================================================================================
</TABLE>

     Operating expenses for the electricity delivery business segment increased
$3.8 million or 4.2 percent in the first six months of 1999, primarily due to
the timing of non-recurring charges related to meter reading in both 1999 and
1998.

                                       17
<PAGE>

     Depreciation and amortization expense increased $2.7 million or 10.9
percent in the first six months of 1999 due to additions to the plant and
equipment.

     In the first six months of 1999, there was $1.0 million or 5.2 percent less
in interest and other charges compared to the first six months of 1998. The
decrease was the result of the refinancing of long-term debt at lower interest
rates and the maturity of approximately $75 million of long-term debt during
1998.

Electricity Generation and CTC Business Segments

     Comparison of Three Months Ended June 30, 1999, and June 30, 1998.  In the
second quarter of 1999, the electricity generation and CTC business segments
reported net income of $14.1 million compared to $14.3 million for the second
quarter of 1998, a decrease of 1.1 percent.

     During 1998, five percent of Duquesne's electric utility customers
participated in the customer choice pilot program under the Customer Choice Act,
and purchased electricity from alternative generation suppliers.  Beginning in
1999, up to 66 percent of Duquesne's electric utility customers are eligible to
participate in customer choice.  As of June 30, 1999, approximately 14 percent
of Duquesne's customers are purchasing electricity from alternative generation
suppliers.

     For the electricity generation and CTC business segments, operating
revenues are primarily derived from Duquesne's supply of electricity for
delivery to retail customers, the supply of electricity to wholesale customers
and, beginning in 1999, the collection of generationrelated transition costs
from electricity delivery customers. Under fuel cost recovery provisions
effective through May 29, 1998, fuel revenues generally equaled fuel expense, as
costs were recoverable from customers through the Energy Cost Rate Adjustment
Clause (ECR), including the fuel component of purchased power, and did not
affect net income. In 1999, due to the PUC's final restructuring order, fuel
costs are expensed as incurred, and impact net income to the extent fuel costs
exceed amounts included in Duquesne's authorized generation rates. (See "Rate
Matters" on page 22.)

     Energy requirements for electric utility customers are reduced as more
customers participate in customer choice.  Energy requirements for residential
and commercial customers are also influenced by weather conditions. Warmer
summer and colder winter seasons lead to increased customer use of electricity
for cooling and heating. Commercial energy requirements are also affected by
regional development. Energy requirements for industrial customers are also
influenced by national and global economic conditions.

     Short-term sales to other utilities are made at market rates. Fluctuations
in electricity sales to other utilities are related to Duquesne's customer
energy requirements, the energy market and transmission conditions, and the
availability of Duquesne's generating stations. Future levels of short-term
sales to other utilities will be affected by market rates, the level of
participation in customer choice, and Duquesne's divestiture of its generation
assets. (See "Rate Matters" on page 22.)

     Operating revenues decreased by $18.5 million or 8.8 percent in the second
quarter of 1999. The decrease in revenues can be attributed to a decrease in
energy supplied to electric utility customers due to increased participation in
customer choice. As of June 30, 1999, 13.6 percent of residential non-coincident
peak load, 29.4 percent of commercial load, and 5.8 percent of industrial load
have selected alternative generation suppliers.  Partially offsetting this
decrease was a 127.3 percent increase in energy supplied to other utilities in
the second quarter of 1999, due to Duquesne's decision to sell 600 MW to
licensed generation suppliers to stimulate competition, and increased capacity
available to sell as a result of participation in customer choice. The following
table sets forth KWH supplied for customers who have not chosen an alternative
generation supplier.

                                       18
<PAGE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                                  KWH Delivered
                                                  ---------------------------------------------
                                                                  (In Millions)
                                                  ---------------------------------------------
Three Months Ended June 30,                         1999             1998              Change
-----------------------------------------------------------------------------------------------
<S>                                               <C>              <C>                <C>
Residential                                         633.9            687.3              (7.8)%
Commercial                                          987.0          1,355.1             (27.2)%
Industrial                                          837.5            840.0              (0.3)%
----------------------------------------------------------------------------------
     Sales to Electric Utility Customers          2,458.4            2,882.4           (14.7)%
Sales to Other Utilities                            787.9              346.6           127.3%
----------------------------------------------------------------------------------
     Total Sales                                  3,246.3            3,229.0             0.5%
===============================================================================================
</TABLE>

     Operating expenses for the electricity generation and CTC business segments
are primarily made up of energy costs; costs to operate and maintain the power
stations; administrative expenses; and non-income taxes, such as property and
payroll taxes.

     Fluctuations in energy costs generally result from changes in the cost of
fuel, the mix between coal and nuclear generation, total KWH supplied, and
generating station availability. Because of the ECR, changes in fuel and
purchased power costs did not impact earnings for the first five months of 1998.

     Operating expenses decreased $17.4 million or 12.5 percent in the second
quarter of 1999 as a result of decreased energy costs and the reclassification
of the interest component of Beaver Valley lease costs to interest expense.
Partially offsetting these reductions were an increase in costs recognized
currently as expense related to generating station outages, as opposed to prior
accounting which deferred the expense for recovery over the subsequent 18
months.

     In the second quarter of 1999, fuel and purchased power expense decreased
by $21.9 million or 30.6 percent compared to the second quarter of 1998. This
decrease was the result of decreased energy costs due to a favorable power
supply mix. During the second quarter of 1998, reduced availability of nuclear
generating stations due to an increase in outage hours required Duquesne to
purchase power and generate power from the higher fuel cost fossil stations.

     Depreciation and amortization expense includes the depreciation of the
power stations' plant and equipment, accrued nuclear decommissioning costs and
the amortization of transition costs. A decrease of $9.5 million or 21.8 percent
in the second quarter of 1999 was the result of accelerated transition cost
reduction efforts during that period in 1998. In 1999, Duquesne began to recover
transition costs through an interim CTC.  The total of transition costs to be
recovered was $1,485 million, net of tax, over a seven-year period, as may be
adjusted to account for the proceeds of the generation asset auction.  Duquesne
records amortization expense for transition costs reflected on the consolidated
balance sheet over the same period as the CTC revenues are being recognized.

     Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In the second quarter of
1999 there was a $9.2 million or 62.5 percent increase in interest and other
charges compared second quarter of 1998. The increase reflected the
reclassification of the interest component of Beaver Valley lease costs to
interest expense, partially offset by refinancing of long-term debt at lower
interest rates and the maturity of approximately $75 million of long-term debt
during 1998.  (See "Financing" discussion on page 21.)

     Comparison of Six Months Ended June 30, 1999, and June 30, 1998.  In the
first six months of 1999, the electricity generation and CTC business segments
reported net income of $30.7 million compared to $26.0 million for the first six
months of 1998, an increase of 18.1 percent.

                                       19
<PAGE>

     Operating revenues decreased by $25.1 million or 6.0 percent in the first
six months of 1999. The decrease in revenues can be attributed to a decrease in
energy supplied to electric utility customers due to increased participation in
customer choice. Partially offsetting this decrease was a 99.8 percent increase
in energy supplied to other utilities in the first six months of 1999, due to
Duquesne's decision to sell 600 MW to licensed generation suppliers to stimulate
competition, and increased capacity available to sell as a result of
participation in customer choice. The following table sets forth KWH supplied
for customers who have not chosen an alternative generation supplier.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                                                  KWH Delivered
                                                  --------------------------------------------
                                                                  (In Millions)
                                                  --------------------------------------------
Six Months Ended June 30,                           1999            1998              Change
----------------------------------------------------------------------------------------------
<S>                                               <C>              <C>                <C>
Residential                                       1,456.6          1,513.6             (3.8)%
Commercial                                        2,139.4          2,665.6            (19.7)%
Industrial                                        1,660.2          1,728.9             (4.0)%
----------------------------------------------------------------------------------
     Sales to Electric Utility Customers          5,256.2          5,908.1            (11.0)%
----------------------------------------------------------------------------------
Sales to Other Utilities                          1,450.4            726.0             99.8%
----------------------------------------------------------------------------------
     Total Sales                                  6,706.6          6,634.1              1.1%
==============================================================================================
</TABLE>

     Operating expenses decreased $32.4 million or 11.7 percent in the first six
months of 1999 as a result of decreased energy costs and the reclassification of
the interest component of Beaver Valley lease costs to interest expense.
Partially offsetting these reductions was an increase in costs now recognized as
expense related to generating station outages.

     In the first six months of 1999, fuel and purchased power expense decreased
by $34.5 million or 26.3 percent compared to the first six months of 1998. This
decrease was the result of decreased energy costs due to a favorable power
supply mix. During the first six months of 1998, reduced availability of nuclear
generating stations due to an increase in outage hours required Duquesne to
purchase power and generate power from the higher fuel cost fossil stations.

     A decrease in depreciation and amortization expense of $14.6 million or
16.7 percent in the first six months of 1999 was the result of accelerated
transition cost reduction efforts during that period. In 1999, Duquesne began to
recover transition costs through an interim CTC.  The total of transition costs
to be recovered was $1,485 million, net of tax, over a seven-year period, as may
be adjusted to account for the proceeds of the generation asset auction.
Duquesne records amortization expense for transition costs reflected on the
consolidated balance sheet over the same period as the CTC revenues are being
recognized.

     In the first six months of 1999 there was a $17.7 million or 59.7 percent
increase in interest and other charges compared to the first six months of 1998.
The increase reflected the reclassification of the interest component of Beaver
Valley lease costs to interest expense, partially offset by the refinancing of
long-term debt at lower interest rates and the maturity of approximately $75
million of long-term debt during 1998.

All Other

     Comparison of Three Months Ended June 30, 1999, and June 30, 1998. The all
other category contributed $2.4 million to net income in the second quarter of
1999 compared to $5.6 million in the second quarter of 1998, a decrease of 56.5
percent.

     Comparison of Six Months Ended June 30, 1999, and June 30, 1998. The all
other category contributed $7.3 million to net income in the first six months of
1999 compared to $14.3 million in the first six months of 1998, a decrease of
49.3 percent.

                                       20
<PAGE>

Liquidity and Capital Resources
--------------------------------------------------------------------------------

Financing

     Duquesne expects to meet its current obligations and debt maturities
through the year 2003 with funds generated from operations, through new
financings and short-term borrowings, and through the proceeds from the auction
of generation assets.  At June 30, 1999, Duquesne was in compliance with all of
its debt covenants.

     Mortgage bonds in the amount of $75 million matured in July 1999, and were
retired using available cash and short term borrowings.

     In connection with the power station exchange with FirstEnergy, Duquesne
anticipates terminating the BV Unit 2 lease in December 1999, in which case the
lease liability recorded on the consolidated balance sheet would no longer be an
obligation of Duquesne. The underlying collateralized lease bonds ($370.7
million at June 30, 1999) would become obligations of Duquesne and be recorded
on the consolidated balance sheet. Duquesne anticipates redeeming the bonds on
December 1, 2002 (the first redemption date), using funds generated from
operations, the generation asset auction proceeds, the CTC, and/or through new
financings. Duquesne would also pay approximately $230 million in termination
costs, which Duquesne expects to recover through the proceeds of the generation
asset auction and the CTC. (See "Power Station Exchange" discussion on page 23.)

     In connection with customer choice,  Duquesne's customer revenues from
operations will be reduced by an amount equal to the generation rate applicable
to those customers choosing alternative generation suppliers (currently
approximately 14 percent of customers).  This reduction is expected to be offset
by reduced cash requirements associated with supplying energy. A further impact
on customer revenues is anticipated to occur when, as part of the divestiture,
Duquesne auctions its provider of last resort service and all customers will be
buying generation, either directly from alternative suppliers or indirectly from
the provider of last resort.  An additional  impact on customer revenues is
expected to occur when the CTC has been fully collected.  The length of the CTC
collection period will depend on the level of auction proceeds and future retail
sales  The foregoing statements are forward-looking regarding the impact on cash
flows of customer choice and Duquesne's divestiture. Actual results could
materially differ from those implied by such statements due to known and unknown
risks and uncertainties, including, but not limited to, the amount and timing of
the receipt of auction proceeds.  (See "Restructuring Plan" on page 23.)

     Duquesne and an unaffiliated corporation have an agreement that entitles
Duquesne to sell, and the corporation to purchase, on an ongoing basis, up to
$50 million of accounts receivable. Duquesne currently anticipates extending or
replacing the accounts receivable sale arrangement upon its expiration in late
August 1999.  At June 30, 1999, Duquesne had sold $50 million of receivables.

     Duquesne maintains a $150 million revolving credit facility which expires
in October 1999.  Interest rates can, in accordance with the option selected at
the time of the borrowing, be based on prime, Eurodollar or certificate of
deposit rates.  Commitment fees are based on the unborrowed amount of the
commitments.  The revolving credit facility contains a two-year repayment period
for any amounts outstanding at the expiration of the revolving credit period.
No amounts were outstanding at June 30, 1999.

     At June 30, 1999, Duquesne had $19.5 million of commercial paper borrowings
outstanding.  During the second quarter the maximum amount of such borrowings
was $40 million, the average daily borrowings was $25.6 million and the weighted
average daily interest rate was 5.13 percent.

                                       21
<PAGE>

Investing
--------------------------------------------------------------------------------

    Duquesne's long-term investments consist of Duquesne's holdings of DQE
common stock, investments in affordable housing, lease investments, alternative
energy investments and nuclear decommissioning trust funds.  $5 million was
invested in nuclear decommissioning trust funds during the six months ended June
30, 1999, and June 30, 1998.

Rate Matters
--------------------------------------------------------------------------------

Competition and the Customer Choice Act

    Under historical ratemaking practice, regulated electric utilities were
granted exclusive geographic franchises to sell electricity, in exchange for
making investments and incurring obligations to serve customers under the then-
existing regulatory framework. Through the ratemaking process, those prudently
incurred costs were recovered from customers, along with a return on the
investment. Additionally, certain operating costs were approved for deferral for
future recovery from customers (regulatory assets). As a result of this process,
utilities had assets recorded on their balance sheets at above-market costs,
thus creating transition and stranded costs.

     In Pennsylvania, the Customer Choice Act went into effect on January 1,
1997. The Customer Choice Act enables Pennsylvania's electric utility customers
to purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act provides that the
existing franchised utility may recover, through a CTC, an amount of transition
costs that are determined by the PUC to be just and reasonable. Pennsylvania's
electric utility restructuring is being accomplished through a two-stage process
consisting of an initial customer choice pilot period (which ended in December
1998) and a phase-in to competition period (which began in January 1999).

Phase-In to Competition

     The phase-in to competition began in January 1999, when 66 percent of
customers became eligible to participate in customer choice (including customers
covered by the pilot program); all customers will have customer choice in
January 2000. As of June 30, 1999, approximately 14 percent of Duquesne's
customers had chosen alternative generation suppliers. Customers that have
chosen an electricity generation supplier other than Duquesne pay that supplier
for generation charges, and pay Duquesne the CTC (discussed below) and charges
for transmission and distribution. Customers that continue to buy their
generation from Duquesne pay for their service at current regulated tariff rates
divided into generation, transmission and distribution charges, and the CTC.
Under the Customer Choice Act, an electric distribution company, such as
Duquesne, remains a regulated utility and may only offer PUC-approved rates,
including generation rates. Also under the Customer Choice Act, electricity
delivery (including transmission, distribution and customer service) remains
regulated in substantially the same manner as under historical regulation.

     In an effort to "jumpstart" competition, Duquesne had made 600 MW of power
available through the first six months of 1999 to licensed electric generation
suppliers, to be used to supply electricity to Duquesne's customers who had
chosen alternative generation suppliers.

                                       22
<PAGE>

Rate Cap

     An overall four-and-one-half-year rate cap from January 1, 1997, has been
imposed on the transmission and distribution charges of Pennsylvania electric
utility companies under the Customer Choice Act. Additionally, electric utility
companies may not increase the generation price component of rates as long as
transition costs are being recovered, with certain exceptions.

Restructuring Plan

     In its May 29, 1998, final restructuring order, the PUC determined that
Duquesne should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The total of the transition costs to be recovered
was $1,485 million, net of tax, over a seven-year period beginning January 1,
1999, as may be adjusted to account for the proceeds of the generation asset
auction. In addition, the transition costs as reflected on the consolidated
balance sheet are being amortized over the same period that the CTC revenues are
being recognized. Duquesne is allowed to earn an 11 percent pre-tax return on
the unrecovered, net of tax balance of transition costs, as adjusted following
the generation asset auction.

     As part of its restructuring plan filing, Duquesne requested recovery of
$11.5 million ($6.7 million, net of tax) through the CTC for energy costs
previously deferred under the ECR. Recovery of this amount was approved in the
PUC's final restructuring order. Duquesne also requested recovery of an
additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On
December 18, 1998, the PUC denied recovery of this additional amount. Duquesne
has appealed the PUC's denial of recovery to the Pennsylvania Commonwealth
Court. Based upon the Customer Choice Act, which mandates recovery of all
regulatory assets, and the PUC's specific authorization for Duquesne to create a
regulatory asset for these costs, Duquesne believes that it is probable that
these costs will be recovered through retail rates. In the event that Duquesne
does not prevail in its appeal, these costs would be written off as a charge
against income.

     Restructuring Plan and Auction Plan. With respect to transition cost
recovery, the PUC's final order on the restructuring plan approved Duquesne's
proposal to auction its generation assets and use the proceeds to offset
transition costs. The remaining balance of such costs (with certain exceptions
described below) is expected to be recovered from ratepayers through the CTC.
Until the divestiture is complete, Duquesne has been ordered to use an interim
CTC and price to compare for each class rate based on the methodology approved
in its pilot program (on average, approximately 2.9 cents per KWH for the CTC
and approximately 3.8 cents per KWH for the price to compare).

     On December 18, 1998, the PUC approved Duquesne's auction plan, including
an auction of its provider of last resort service, as well as an agreement in
principle to exchange certain generation assets with FirstEnergy. The assets to
be auctioned will include Duquesne's wholly owned Cheswick, Elrama, Phillips and
Brunot Island power stations, as well as the stations to be received from
FirstEnergy in the power station exchange described below. The auction plan
calls for a two-phase, sealed bid process similar to that used in other power
plant divestitures. The initial confidential bidding process began in April
1999, with potential buyers identified by Duquesne being asked to submit non-
binding bids.  Qualified applicants have been asked to submit binding, second-
round bids, due in September 1999. Final agreements governing the transactions
must be approved by various regulatory agencies, including the PUC, the FERC,
the NRC, and the Federal Trade Commission. Duquesne currently expects the sale
to close at the end of 1999 or the beginning of 2000.

     Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in
certain power stations. Duquesne will receive 100 percent ownership rights in
three coal-fired power plants located in Avon Lake and Niles, Ohio and New
Castle, Pennsylvania (totaling approximately 1,300 MW), which Duquesne expects
to sell as part of the auction of generation assets. FirstEnergy will acquire
Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2
(BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield
Units 1, 2 and 3 (totaling

                                       23
<PAGE>

approximately 1,400 MW). In connection with the power station exchange, Duquesne
anticipates terminating the BV Unit 2 lease in December 1999. (See "Financing"
discussion on page 21.) Pursuant to the December 18, 1998, PUC order and subject
to final approval, the proceeds from the sale of the power stations received in
the exchange will be used to offset the transition costs associated with
Duquesne's currently-held generation assets and costs associated with completing
the exchange. Duquesne expects this exchange to enhance the value received from
the auction, because participants will bid on entire plants, rather than plants
that are jointly owned and/or operated by another entity. Additionally, the
auction will include only coal- and oil-fired plants, which are anticipated to
have a higher market value than nuclear plants. These value-enhancing features,
along with a minimum level of auction proceeds guaranteed by FirstEnergy, are
expected to maximize auction proceeds, minimize transition costs required to be
recovered through the CTC (by shortening the length of the CTC recovery period),
and thus reduce customer bills as rapidly as possible. Other benefits of this
exchange include the resolution of all joint ownership issues, and other risks
and costs associated with the jointly-owned units.  The Federal Trade Commission
approved the exchange on June 30, 1999.  The PUC approved the definitive
exchange agreement on July 15, 1999, having found the exchange to be in the
public interest.  Certain aspects of the exchange have yet to be approved by,
among other agencies, the FERC, the NRC and, solely with respect to reliability
issues, the Public Utilities Commission of Ohio. The power station exchange is
expected to occur at the end of 1999 or in early 2000. (See "Legal Proceedings"
on page 28.)

Termination of the AYE Merger

     On October 5, 1998, DQE announced its unilateral termination of the merger
agreement between DQE and Allegheny Energy, Inc. (AYE). DQE believes that AYE
suffered a material adverse effect as a result of the PUC's final restructuring
order regarding AYE's utility subsidiary, West Penn Power Company.  AYE filed
suit in the United States District Court for the Western District of
Pennsylvania, seeking to compel DQE to proceed with the merger and seeking a
temporary restraining order and preliminary injunction to prevent DQE from
certain actions pending a trial, or in the alternative seeking an unspecified
amount of money damages. DQE and AYE continue to litigate this matter. (See
"Legal Proceedings" on page 28.)  In a letter dated February 24, 1999, the PUC
informed DQE that the merger application was deemed withdrawn and the docket was
closed.

Year 2000
--------------------------------------------------------------------------------

    Duquesne has taken extensive and systematic steps to ensure a smooth
transition into the Year  2000.  The transition to the Year 2000 became an issue
because many existing computer programs and embedded microprocessors use only
two digits to identify a year (for example, "99" is used to represent "1999").
Such programs read "00" as the year 1900, and thus may not recognize dates
beginning with the year 2000, or may otherwise produce erroneous results or
cease processing when dates after 1999 are encountered.

    Year 2000 Plan. Since 1994, Duquesne has been planning for the Year 2000
with an aggressive strategy to identify information needs, replace or upgrade
equipment and coordinate resources to anticipate the new millennium. Based on
the success to date of the Year 2000 program, Duquesne fully expects normal
operations into the Year 2000 and beyond.  Duquesne assembled a Year 2000 team,
comprised of management representatives from all functional areas of Duquesne.
The goal of Duquesne's Year 2000 program is that all components and services
that in any material manner contribute to the operational reliability, customer
relations, safety, revenue, regulatory compliance and reputation of Duquesne be
Year 2000 ready.  On June 30, 1999, Duquesne reported to the PUC, the NRC and
the North American Electric Reliability Council (NERC) that all of its mission
critical systems are Year 2000 ready.  Duquesne has defined mission critical as
any system that supports the generation of electricity as well as transmission
and delivery of power to customers.

                                       24
<PAGE>

Duquesne's Year 2000 program also addresses all of the its business critical
systems, such as billings, processing orders, and various accounting and
business management functions. Many of these systems also have been declared
ready as of June 30, 1999.  The remainder are expected to be completed by
September 30, 1999. The Year 2000 team has focused on all three aspects of the
issue: computer software and hardware systems used to support day-to-day
operations; embedded microprocessors which are small electronic devices found in
a wide range of equipment and devices (such as plant components, substation
equipment, elevators, and heating and cooling systems); and potential related
issues that may originate with third parties with whom Duquesne does business.
To support the planning, organization and management of its efforts, the team
has retained Year 2000 consultants.

     In general, Duquesne's overall strategy to address the Year 2000 issue is
comprised of four phases that, in some cases, are performed simultaneously.
These phases are inventory, assessment, remediation, and testing and
implementation.

     Inventory consisted of identifying the various components, equipment,
hardware, and software used in Duquesne's operations that may potentially be
faced with Year 2000 issues. The inventory process, completed in 1998, involved
reviewing existing listings and subsequent verification through physical
inspections and walk-downs.

     Assessment, completed in January 1999, consisted of evaluating all
inventoried items for Year 2000 compliance or readiness.  This was accomplished
by contacting the vendors and manufacturers, inspecting software and code,
researching the results of other companies' assessment of like components, and
various other means.

     Remediation, the third step in the process, addressed the activities
necessary to fix or replace those components that have Year 2000 issues that
will adversely affect the Company's operations.  Remediation of all mission
critical systems was complete as of June 30, 1999.  Remediation is in addition
to previously planned improvements to the Company's systems with benefits beyond
Year 2000 solutions, such as total system replacements discussed below.

     Testing and implementation, the final step, consists of placing renovated
processes, systems, equipment, and other items into use within the Company's
operations.  Testing has been performed on all mission critical processes,
whether or not remediation activities were involved in the process.

    Regulatory Review.  Throughout the execution of its Year 2000 plan, the
Company has been providing and will continue to provide information on its
activities to regulatory agencies including the PUC, the NRC and the NERC.

    .   Following eight months of formal proceedings by the PUC during which all
        Pennsylvania utilities, including Duquesne, were required to demonstrate
        that they were ready for the Year 2000, the PUC "investigation concludes
        that the lights will stay on..." (Motion of PUC Chairman John M. Quain
        on Docket No. I-00980076, March 31, 1999)

    .   Duquesne has complied with the NRC's compliance guidelines and has
        verified with the NRC that all systems related to power production,
        safety and security are ready for Year 2000. In addition, the NRC
        conducted a Year 2000 audit of the nuclear power station safety and
        operations systems in May 1999.

    .   NERC, which coordinates the interconnection of all utilities across the
        country, has been requested by the DOE to conduct a detailed review of
        the national electric power production and delivery infrastructure to
        ensure a reliable power supply during the Year 2000 transition period.
        Duquesne has provided monthly status reports to NERC. Duquesne's June
        30, 1999, report confirmed the Year 2000 readiness of all its
        generation, transmission, and distribution systems. In addition,
        Duquesne participated in the industry-wide NERC communication drill that
        was conducted on April 9, 1999. All of Duquesne's communications systems
        exercised in this drill performed as expected. Duquesne will also be
        participating in the NERC Year 2000 readiness drill to be conducted on
        September 9, 1999.

                                       25
<PAGE>

    Risks and Contingency Plans.  Duquesne currently believes that
implementation of its plan will minimize the Year 2000 issues relating to its
systems and equipment.  Duquesne understands that many variables outside the
control of Duquesne may have an adverse affect on the ability of Duquesne to
perform its mission critical processes.  Management believes that the most
reasonably likely worst case scenario would be a temporary disruption of service
to customers caused by potential disruptions in the operations of critical
suppliers, such as fuel supply or telecommunications.  In the event such a
scenario occurs, it is not anticipated that Duquesne would incur a material
adverse impact on its financial position or the consolidated results of
operations.

     In the normal course of business Duquesne has developed contingency plans
to minimize the risk of interrupted operations.  As part of the Year 2000
program, Duquesne has reviewed these plans in terms of Year 2000 related risks,
and either refined the existing plans or developed new contingency plans for all
mission critical and business critical processes. These contingency plans
incorporate numerous mitigation strategies, such as the most appropriate
allocation of staffing resources, the need for additional equipment and
facilities, and special operating procedures, including manual operations and
use of non-computer dependent back-up equipment and procedures.

     Duquesne continues to review its operations and its critical external
suppliers and service providers, in order to determine any adverse scenarios it
could face as a result of Year 2000 problems. To date, nothing has been found
that would prevent Duquesne from generating or providing electricity to the
public.

     Costs.   The estimated total cost of implementing Duquesne's Year 2000 plan
is approximately $49 million, which includes costs related to total system
replacements (i.e., the Year 2000 solution comprises only a portion of the
benefit resulting from such replacements). These costs to date, primarily
incurred as a result of software and system changes and upgrades by Duquesne,
have been approximately $39 million. Of this amount, approximately $35 million
are capital costs attributable to the licensing and installation of new software
for total system replacements. The remaining $4 million has been expensed as
incurred. Funds for Duquesne's Year 2000 plan have come from Duquesne's
operating and capital budgets. Approximately $10 million has been budgeted for
1999 to address Year 2000 issues. Duquesne does not anticipate that Year 2000
issues and related costs will be material to Duquesne's operations, financial
condition and results of operations.

     The foregoing paragraphs contain forward-looking statements regarding the
timetable, effectiveness and ultimate cost of Duquesne's Year 2000 strategy.
Actual results could materially differ from those implied by such statements due
to known and unknown risks and uncertainties, including, but not limited to, the
possibility that changes and upgrades are not timely completed, that corrections
to the systems of other companies on which Duquesne's systems rely may not be
timely completed, and that such changes and upgrades may be incompatible with
Duquesne's systems; the availability and cost of trained personnel; and the
ability to locate and correct all relevant computer code and microprocessors.

                                       26
<PAGE>

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

     Funding for nuclear decommissioning costs is deposited by Duquesne in
external, segregated trust accounts and invested in a portfolio of corporate
common stock and debt securities, municipal bonds, certificates of deposit and
United States government securities. The market value of the aggregate trust
fund balances at June 30, 1999, totaled approximately $69.4 million. The amount
funded into the trusts is based on estimated returns which, if not achieved as
projected, could require additional unanticipated funding requirements.

                         ______________________________

Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve
known and unknown risks, uncertainties and other factors that may cause the
actual results, performance or achievements of Duquesne to be materially
different from any future results, performance or achievements expressed or
implied by such forward-looking statements.  Such factors may affect Duquesne's
operations, markets, products, services and prices, and include, among others,
the following: DQE's decision not to consummate the merger with AYE; the related
lawsuit initiated by AYE; Duquesne's plan to auction its generating assets; the
power station exchange; general and economic and business conditions; industry
capacity; changes in technology; changes in political, social and economic
conditions; pending regulatory decisions regarding industry restructuring in
Pennsylvania; the loss of any significant customers; and changes in business
strategy or development plans.

                                       27
<PAGE>

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

Eastlake Unit 5

     In September 1995, Duquesne commenced arbitration against The Cleveland
Electric Illuminating Company (CEI), seeking damages, termination of the
operating agreement for Eastlake Unit 5 (Eastlake) and partition of the parties'
interests in Eastlake through a sale and division of the proceeds. The
arbitration demand alleged, among other things, the improper allocation by CEI
of fuel and related costs; the mismanagement of the administration of the
Saginaw coal contract in connection with the closing of the Saginaw mine, which
historically supplied coal to Eastlake; and the concealment by CEI of material
information. CEI also seeks monetary damages from Duquesne for alleged unpaid
joint costs in connection with the operation of Eastlake. Duquesne removed the
action to the United States District Court for the Northern District of Ohio,
Eastern Division, where it is now pending. Pursuant to the agreement regarding
the power station exchange between Duquesne and FirstEnergy, the parties have
jointly sought and received a court order staying all proceedings pending the
closing of the exchange. (See "Power Station Exchange" discussion on page 23.)

Termination of the AYE Merger

     On October 5, 1998, DQE announced its unilateral termination of the merger
agreement with AYE. More information regarding this termination is set forth in
Duquesne's Current Report on Form 8-K dated October 5, 1998. AYE promptly filed
suit in the United States District Court for the Western District of
Pennsylvania, seeking to compel DQE to proceed with the merger and seeking a
temporary restraining order and preliminary injunction to prevent DQE from
certain actions pending a trial, or in the alternative seeking an unspecified
amount of money damages. On October 28, 1998, the judge denied AYE's motion for
the temporary restraining order and preliminary injunction. AYE appealed to the
United States Court of Appeals for the Third Circuit, asking for an injunction
pending the appeal and expedited treatment of the appeal. On November 6, 1998,
the Third Circuit denied the motion for an injunction and granted the motion to
expedite the appeal.

     On March 11, 1999, the Third Circuit vacated the October 28 denial of a
preliminary injunction. The Third Circuit remanded the case to the District
Court for further proceedings to address certain issues, including whether AYE
could demonstrate a reasonable likelihood of success on the merits, before
determining whether any injunctive relief is warranted. On March 12, 1999, AYE
filed a motion for a temporary restraining order with the district court, and a
hearing was held that same day. On March 16, 1999, AYE and DQE entered into a
consent agreement, which was approved by the district court on March 18.
Pursuant to the consent agreement, AYE and DQE have agreed, among other things,
that pending the consolidated hearing on AYE's application for a preliminary
injunction and/or an expedited trial on the merits, both parties will give each
other 10 business days' notice before taking or omitting to take any action
which would prevent the merger from qualifying for "pooling of interests"
accounting treatment. This would not prevent either party from entering into any
agreement, but would require the 10 business days' notice prior to closing any
transaction which prevents pooling. The consent agreement shall terminate on
September 16, 1999, unless earlier terminated or extended by mutual agreement or
an order of the district court. On March 25, 1999, DQE petitioned the Third
Circuit for rehearing; this petition was denied on June 14, 1999.  On June 1,
1999, AYE informed the PUC that, given the procedural posture of the merger
litigation, it would seek a Federal court order enjoining the closing of the
power station exchange with FirstEnergy because, in its view, such a closing
would prevent the merger from qualifying for "pooling of interests" accounting.

     DQE continues to believe that AYE's claim is entirely without merit in
light of the $1 billion disallowance of its stranded costs, which constituted a
material adverse effect under the merger agreement and entitled DQE to terminate
it as of October 5, 1998. DQE will continue to defend itself vigorously against
AYE's claims and intends to pursue a prompt resolution of the litigation. The
ultimate outcome of this suit cannot be determined at this time. DQE's motion
for summary judgment, originally filed December 18, 1998, remains pending.

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<PAGE>

Item 6.  Exhibits and Reports on Form 8-K.

a.   Exhibits:

     EXHIBIT 3.1 - Restated Articles of Duquesne Light Company, as currently in
                   effect.

     EXHIBIT 3.2 - By-Laws of Duquesne Light Company, as amended through
                   June 29, 1999, and currently in effect.

     EXHIBIT 12.1 - Calculation of Ratio of Earnings to Fixed Charges

     EXHIBIT 27.1 - Financial Data Schedule

b.   No Reports on Form 8-K were filed during the fiscal quarter ended
     June 30, 1999.

                         ______________________________

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<PAGE>

                                   SIGNATURES



     Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.


                                              Duquesne Light Company
                                          ------------------------------
                                                   (Registrant)



Date      August 13, 1999                      /s/ Gary L. Schwass
          ---------------                 ------------------------------
                                                    (Signature)
                                                  Gary L. Schwass
                                             Senior Vice President and
                                              Chief Financial Officer



Date      August 13, 1999                      /s/ James E. Wilson
          ---------------                 ------------------------------
                                                    (Signature)
                                                  James E. Wilson
                                                    Controller
                                          (Principal Accounting Officer)

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