[CONFORMED]

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 September 30, 1996
------------------

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

For the Transition Period From to
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Commission File Number
----------------------
1-10290

DQE, Inc.
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(Exact name of registrant as specified in its charter)

Pennsylvania 25-1598483
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)

Cherrington Corporate Center, Suite 100
500 Cherrington Parkway, Coraopolis, Pennsylvania 15108-3184
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(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (412) 262-4700

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 Common Stock, no par value - 77,195,881 shares outstanding as of September
30, 1996 and 77,206,010 shares outstanding as of October 31, 1996.

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

DQE
CONDENSED STATEMENT OF CONSOLIDATED INCOME
(Thousands of Dollars, Except Per Share Amounts)
(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1996 1995 1996 1995
-------- -------- -------- --------

Operating Revenues
Sales of Electricity:
Customers - net $294,470 $312,562 $818,536 $827,143
Utilities 14,599 15,356 45,641 39,872
-------- -------- -------- --------
Total Sales of Electricity 309,069 327,918 864,177 867,015
Other 26,361 19,346 65,128 61,898
-------- -------- -------- --------
Total Operating Revenues 335,430 347,264 929,305 928,913
-------- -------- -------- --------

Operating Expenses
Fuel and purchased power 61,126 66,466 178,986 174,391
Other operating 73,708 77,081 215,883 221,028
Maintenance 19,554 21,185 58,922 61,044
Depreciation and amortization 53,709 53,486 166,517 152,687
Taxes other than income taxes 22,442 23,518 65,405 66,758
-------- -------- -------- --------
Total Operating Expenses 230,539 241,736 685,713 675,908
-------- -------- -------- --------

OPERATING INCOME 104,891 105,528 243,592 253,005
-------- -------- -------- --------

OTHER INCOME 16,978 12,714 48,618 39,049
-------- -------- -------- --------

INTEREST AND OTHER CHARGES 28,807 26,258 81,183 81,462
-------- -------- -------- --------

INCOME BEFORE INCOME TAXES 93,062 91,984 211,027 210,592

INCOME TAXES 35,650 36,715 72,338 78,737
-------- -------- -------- --------

NET INCOME $ 57,412 $ 55,269 $138,689 $131,855
======== ======== ======== ========

AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING
(Thousands of Shares) 77,194 77,533 77,391 77,718
======== ======== ======== ========

EARNINGS PER SHARE OF
COMMON STOCK $0.74 $0.72 $1.79 $1.70
======== ======== ======== ========

DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $0.32 $0.30 $0.96 $0.89
======== ======== ======== ========

See notes to condensed consolidated financial statements.

DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)

September 30, December 31,
1996 1995
-------------- -------------

ASSETS
Current assets:
Cash and temporary cash investments $ 245,137 $ 24,767
Receivables 150,113 125,768
Other current assets, principally
materials and supplies 96,952 86,851
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Total current assets 492,202 237,386
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Long-term investments 485,703 440,916
-------------- -------------
Property, plant and equipment 4,756,108 4,746,113
Less: Accumulated depreciation and
amortization (1,771,707) (1,685,877)
-------------- -------------
Property, plant and equipment -
net 2,984,401 3,060,236
-------------- -------------
Other non-current assets:
Regulatory assets 643,800 671,928
Other 51,936 48,377
-------------- -------------

Total other non-current assets 695,736 720,305
-------------- -------------
TOTAL ASSETS $ 4,658,042 $ 4,458,843
============== =============
LIABILITIES AND CAPITALIZATION
Current liabilities:
Notes payable $ 9,880 $ 35,098
Current maturities and sinking fund
requirements 23,819 71,379
Accounts payable 77,667 90,941
Accrued liabilities 75,283 52,063
Dividends declared 27,213 27,825
Other 7,793 9,191
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Total current liabilities 221,655 286,497
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Deferred income taxes - net 829,565 801,631
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Deferred investment tax credits 104,645 115,760
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Capital lease obligations 28,787 34,546
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Deferred income 190,127 221,740
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Other 223,014 197,973
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Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,467,050 1,400,993
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Preferred and preference stock of
subsidiaries:
Non-redeemable preferred stock 213,608 63,608
Non-redeemable preference stock,
Plan Series A 29,127 29,615
-------------- -------------
Total preferred and preference
stock before deferred employee
stock ownership plan (ESOP) benefit
(involuntary liquidation values
of $242,598 and $93,086 exceed par
by $28,306 and $28,781,
respectively) 242,735 93,223
Deferred ESOP benefit (20,246) (22,257)
-------------- -------------
Total preferred and preference
stock of subsidiaries 222,489 70,966
-------------- -------------
Common shareholders' equity:
Common stock - no par value
(authorized - 187,500,000 shares;
issued - 109,679,154 shares) 985,244 997,461
Retained earnings 763,420 698,986
Less treasury stock (at cost)
(32,483,273 and 32,123,601
shares, respectively) (377,954) (367,710)
-------------- -------------
Total common shareholders' equity 1,370,710 1,328,737
-------------- -------------
Total capitalization 3,060,249 2,800,696
-------------- -------------
TOTAL LIABILITIES AND
CAPITALIZATION $ 4,658,042 $ 4,458,843
============== =============

See notes to condensed consolidated financial statements.

DQE
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)

Nine Months Ended
September 30,
----------------------
1996 1995
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Cash Flows from Operating Activities
Operations $ 320,144 $ 275,540
Changes in working capital other than
cash (26,510) 33,207
Other - net (1,724) 40,944
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Net Cash Provided by Operating
Activities 291,910 349,691
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Cash Flows Used in Investing Activities
Capital expenditures (62,730) (57,871)
Long-term investments - net (39,809) (113,379)
Other - net (3,587) (2,428)
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Net Cash Used in Investing
Activities (106,126) (173,678)
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Cash Flows Provided by (Used in)
Financing Activities
Decrease in notes payable - net (25,218) (2,157)
Issuance (redemption) of preferred
and preference stock 150,000 (26,732)
Dividends on common stock (74,255) (68,833)
Increase (reductions) of long-term
obligations - net 2,130 (81,236)
Repurchase of common stock (11,717) (21,271)
Other - net (6,354) (642)
---------- ----------
Net Cash Provided by (Used in)
Financing Activities 34,586 (200,871)
---------- ----------

Net increase (decrease) in cash and
temporary cash investments 220,370 (24,858)
Cash and temporary cash investments at
beginning of period 24,767 50,058
---------- ----------
Cash and temporary cash investments at
end of period $ 245,137 $ 25,200
========== ==========

Non-Cash Investing Activities
Equity funding obligations recorded $ 23,046 $ 10,123
========== ==========

See notes to condensed consolidated financial statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve
risks and uncertainties including, but not limited to, economic, competitive,
governmental and technological factors affecting DQE and its subsidiaries' (the
Company's) operations, markets, products, services and prices, and other factors
discussed in the Company's filings with the Securities and Exchange Commission
(SEC).

1. CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES

DQE is an energy services holding company formed in 1989. Its subsidiaries
are Duquesne Light Company (Duquesne), Duquesne Enterprises (DE), DQE Energy
Services (DES) and Montauk. DQE and its subsidiaries are collectively referred
to as "the Company."

Duquesne is an electric utility engaged in the production, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. DE makes strategic investments related to DQE's core energy
business. These investments enhance DQE's capabilities as an energy provider,
increase asset utilization, and act as a hedge against changing business
conditions. DES is a diversified energy services company offering a wide range
of energy solutions for industrial, utility and consumer markets worldwide. DES
initiatives include energy facility development and operations, independent
power production, gas and electric energy/fuel management and utility management
services. Montauk is a financial services company that makes long-term
investments and provides financing for the Company's market-driven business
activities.

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-period financial statements were reclassified to
conform with the 1996 presentation.

These statements should be read with the financial statements and notes
included in the Annual Report on Form 10-K filed with the SEC for the year ended
December 31, 1995. The results of operations for the three and nine months
ended September 30, 1996 are not necessarily indicative of the results that may
be expected for the full year. The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements. The reported amounts of revenues and expenses during
the reporting period may also be affected by the estimates and assumptions
management is required to make. Actual results could differ from those
estimates.

The Company is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to the
regulation of the Pennsylvania Public Utility Commission (PUC) and the Federal
Energy Regulatory Commission (FERC). As a result, the consolidated financial
statements contain regulatory assets and

liabilities in accordance with Statement of Financial Accounting Standards No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71), and
reflect the effects of the ratemaking process. Such effects concern mainly the
time at which various items enter into the determination of net income in
accordance with the principle of matching costs and revenues. (See "Rate
Matters," Note 3, below.)

The Company's long-term investments include certain investments in marketable
securities. In accordance with Statement of Financial Accounting Standards 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 losses on investments at September 30, 1996
and December 31, 1995 are $8.6 million and $4.4 million. Reduced for deferred
income taxes, net unrealized holding losses on investments are $5.0 million and
$2.6 million at September 30, 1996 and December 31, 1995.

2. RECEIVABLES

Components of receivables for the periods indicated are as follows:

September 30, September 30, December 31,
1996 1995 1995
(Amounts in Thousands of Dollars)
- -------------------------------------------------------------------------------------------

Direct customer accounts receivable $107,419 $110,963 $103,821
Other utility receivables 36,626 17,216 22,441
Other receivables 25,585 35,149 25,164
Less: Allowance for uncollectible
accounts (19,517) (20,082) (18,658)
- -------------------------------------------------------------------------------------------
Receivables less allowance for
uncollectible accounts 150,113 143,246 132,768
Less: Receivables sold - - (7,000)
- -------------------------------------------------------------------------------------------
Total Receivables $150,113 $143,246 $125,768
===========================================================================================

The Company and an unaffiliated corporation have an agreement that entitles
the Company to sell, and the corporation to purchase, on an ongoing basis, up to
$50.0 million of accounts receivable. At September 30, 1996 and 1995, the
Company had not sold any receivables to the unaffiliated corporation. At
December 31, 1995, the Company had sold $7.0 million of receivables to the
unaffiliated corporation. The accounts receivable sales agreement, which expires
in June 1997, is one of many sources of funds available to the Company. The
Company may attempt to extend the agreement or to replace the facility with a
similar arrangement or to eliminate it upon expiration.

3. RATE MATTERS

On October 31, 1996 the sale of the Company's ownership interest in the Ft.
Martin Power Station (Ft. Martin) was completed. In accordance with the PUC
order approving the Company's plan for the sale of its ownership interest in Ft.
Martin, the Company will not increase its base rates for a five-year period
through the year 2000. In addition, the Company will record a five-year annual
$5.0 million credit to the Energy Cost Rate Adjustment Clause (ECR) and cap
energy costs beginning April 1, 1997 through the remainder of the plan period.
(See "Ft. Martin Plan" discussion on page 8.)

Regulatory Assets

As a result of the application of SFAS No. 71, the Company records regulatory
assets on its consolidated balance sheet. The regulatory assets represent
probable future revenue to the Company because provisions for these costs are
currently included, or are expected to be included, in charges to electric
utility customers through the ratemaking process.

The Company's electric utility operations currently satisfy the SFAS No. 71
criteria. However, a company's electric utility operations or a portion of such
operations could cease to meet these criteria for various reasons, including a
change in the PUC or the FERC regulations. Should the Company's electric utility
operations cease to meet the SFAS No. 71 criteria, the Company would be required
to write off any regulatory assets or liabilities for those operations that no
longer meet these requirements. Management will continue to evaluate
significant changes in the regulatory and competitive environment in order to
assess the Company's overall compliance with the criteria of SFAS No. 71.

The components of regulatory assets for the periods presented are as follows:

September 30, December 31,
1996 1995

(Amounts in Thousands of Dollars)
- -------------------------------------------------------------------------------------
Regulatory tax receivable $404,409 $414,543
Unamortized debt costs (a) 94,656 98,776
Deferred rate synchronization costs (see below) 42,149 51,149
Beaver Valley Unit 2 sale/leaseback premium (b) 30,435 31,564
Deferred employee costs (c) 29,194 31,218
Extraordinary property loss 0 8,300
Deferred nuclear maintenance outage costs 16,002 6,776
DOE decontamination and decommissioning receivable 10,010 10,687
Deferred coal costs 11,303 12,753
Other 5,642 6,162
- -------------------------------------------------------------------------------------
Total Regulatory Assets $643,800 $671,928
=====================================================================================

(a) The premiums paid to reacquire debt prior to scheduled maturity dates are
deferred for amortization over the life of the debt issued to finance the
reacquisitions.
(b) The premium paid to refinance the Beaver Valley Unit 2 lease was deferred
for amortization over the life of the lease.
(c) Includes amounts for recovery of accrued compensated absences and accrued
claims for workers' compensation.

With respect to the financial statement presentation of Statement of
Financial Accounting Standards No. 109, Accounting for Income Taxes, the Company
reflects the amortization of the regulatory tax receivable resulting from
reversals of deferred taxes as depreciation and amortization expense. Reversals
of accumulated deferred income taxes - net are included in income taxes.

Deferred Rate Synchronization Costs

In 1987, the PUC approved the Company's petition to defer initial operating
and other costs of Perry Unit 1 and Beaver Valley Unit 2 (BV Unit 2). The
Company deferred the costs incurred from the date the units went into commercial
operation until the date a rate order was issued. In its rate order, the PUC
postponed ruling on whether these costs would be recoverable from the Company's
electric utility customers. The Company is not earning a return on the deferred
costs.

In accordance with the PUC order approving the Company's plan for the sale of
its ownership interest in Ft. Martin, the Company has expensed $9.0 million
related to the depreciation portion of deferred rate synchronization costs. The
Company's approved plan also provides for the amortization of the remaining
$42.1 million of deferred rate synchronization costs over a ten-year period.
(See "Ft. Martin Plan" discussion, below.)

Property Held for Future Use

In 1986, the PUC approved the Company's request to remove Phillips Power
Station (Phillips) and a portion of Brunot Island Power Station (BI) from
service and from rate base. The Company expects to recover its investment in BI
through future electricity sales. The Company believes its investment in BI
will be necessary in order to meet future business needs as outlined in the
Company's plans for optimizing generation resources. A portion of the proceeds
of the sale of Ft. Martin is expected to be used to fund reliability
enhancements to BI combustion turbines. The reliability enhancements are
contingent upon the projects meeting a least-cost test versus other potential
sources of peaking capacity. (See "Ft. Martin Plan" discussion below.) The
Company is analyzing the effects of retail choice on its future generating
requirements and specifically whether Phillips will be able to operate in this
new competitive marketplace. The Company is also investigating other
opportunities to recover its investment and associated costs of Phillips,
including the possible sale of the station. In the event that market demand,
transmission access or rate recovery do not support the utilization or sale of
these plants, the Company may have to write off part or all of these
investments and associated costs. At September 30, 1996, the Company's net of
tax investment in Phillips and BI held for future use was $53.2 million and
$27.6 million, respectively.

Ft. Martin Plan

On October 31, 1996 the sale of the Company's ownership interest in Ft.
Martin was completed. The sale and a plan to be funded in part by the proceeds
of the Ft. Martin transaction were approved by the PUC on May 23, 1996. Under
the approved plan, the Company will not increase its base rates for a period of
five years through the year 2000. In addition, the Company recorded in October
1996 a one-time reduction of approximately $130.0 million in the book value of
the Company's nuclear plant investment. The proceeds from the sale are expected
to be used to fund reliability enhancements to the BI combustion turbines and
to reduce the Company's capitalization. The approved plan also provides for an
increase of $25.0 million in depreciation and amortization expense in 1996,
$50.0 million in 1997 and $75.0 million in 1998 related to the Company's nuclear
investment, as well as additional annual contributions to its nuclear plant
decommissioning funds of $5.0 million, without any increase in existing electric
rates. Also, the Company will record an annual $5.0 million credit to the ECR
during the plan period to compensate the Company's electric utility customers
for lost profits from any short-term power sales foregone by the sale of its
ownership interest in Ft. Martin. In addition to the annual credit of $5.0
million to the ECR, the Company will cap energy costs beginning April 1, 1997
through the remainder of the plan period, at a historical five-year average of
1.47 cents per kilowatt hour. In accordance with the approved plan, the Company
has expensed $9.0 million related to the depreciation portion of the $51.1
million of deferred rate synchronization costs associated with BV Unit 2 and
Perry Unit 1. Upon final transfer of its ownership interest in Ft. Martin, the
Company began to amortize the remaining $42.1 million of deferred rate
synchronization costs over a ten-year period. (See "Deferred Rate
Synchronization Costs" discussion on page 7.) Finally, the

Company's approved plan also provides for annual assistance of $0.5 million to
low-income customers.

4. COMMITMENTS AND CONTINGENCIES

Construction

The Company estimates that it will spend, excluding the Allowance for Funds
Used During Construction (AFC) and nuclear fuel, approximately $90.0 million on
electric utility construction during 1996. This estimate also excludes any
potential expenditures for reliability enhancements to the BI combustion
turbines. (See "Ft. Martin Plan" discussion, Note 3, on page 8.)

Nuclear-Related Matters

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

Nuclear Decommissioning. The PUC ruled that recovery of the decommissioning
costs for Beaver Valley Unit 1 (BV Unit 1) could begin in 1977, and that
recovery for BV Unit 2 and Perry Unit 1 could begin in 1988. The Company
expects to decommission BV Unit 1, BV Unit 2 and Perry Unit 1 no earlier than
the expiration of each plant's operating license in 2016, 2027 and 2026,
respectively. BV Unit 1 will be placed in safe storage until the expiration of
the BV Unit 2 operating license, at which time the units may be decommissioned
together.

Based on site-specific studies finalized in 1992 for BV Unit 2 and in 1994
for BV Unit 1 and Perry Unit 1, the Company's share of the total estimated
decommissioning costs, including removal and decontamination costs, currently
being used to determine the Company's cost of service is $121.7 million for BV
Unit 1, $35.2 million for BV Unit 2 and $67.1 million for Perry Unit 1.

In conjunction with an August 18, 1994 PUC Accounting Order, the Company has
increased the annual contribution to its decommissioning trusts by approximately
$2.0 million, to bring the total annual funding to approximately $4.0 million
per year. On July 18, 1996, the PUC issued a Proposed Policy Statement Regarding
Nuclear Decommissioning Cost Estimation and Cost Recovery for the purpose of
obtaining comments from the public. The proposed policy includes guidelines for
a site-specific study to estimate the cost of decommissioning. These studies
need to be performed at least every five years addressing radiological and non-
radiological costs and include a contingency factor of not more than 10 percent.
Under the proposed policy, annual decommissioning funding levels are based on an
annuity calculation recognizing inflation in the cost estimates and earnings on
fund assets. Utilities may be permitted to update their annual decommissioning
trust fund payments through accounting petitions, a change in base rates, or a
non-earnings related change in base rates under the proposed policy. With
respect to the transition to a competitive generation market, the proposed
policy recommends that utilities include a plan to mitigate any shortfall in
decommissioning trust fund payments for the life of the facility with any future
decommissioning filings. In response to this recommendation, the Company has
taken steps to currently fund its nuclear decommissioning obligation. The PUC
approved the Company's plan for the sale of its

ownership interest in Ft. Martin, which provides for additional annual
contributions to its nuclear decommissioning funds of $5.0 million without any
increase in existing electric utility rates. (See "Ft. Martin Plan" discussion,
Note 3, on page 8.) Also, on October 17, 1996 the PUC adopted an Accounting
Order filed by the Company to recognize the increased funding as part of
the Company's cost of service. The Company is currently seeking approval from
the Internal Revenue Service to allow for this additional funding of its
decommissioning trusts.

The Company records decommissioning expense under the category of
depreciation and amortization and accrues a liability equal to that amount for
nuclear decommissioning expense. Such nuclear decommissioning funds are
deposited in external, segregated trust accounts. The funds are invested in a
portfolio of municipal bonds, certificates of deposit and United States
government securities having a weighted average duration of four to seven years.
Trust fund earnings increase the fund balance and the recorded liability. The
market value of the aggregate trust fund balances at September 30, 1996 totaled
approximately $32.0 million. On the Company's consolidated balance sheet, the
decommissioning trusts have been reflected in long-term investments, and the
related liability has been recorded as other non-current liabilities.

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 $8.9
billion. The maximum available private primary insurance of $200.0 million has
been purchased by the Company. Additional protection of $8.7 billion would be
provided by an assessment of up to $79.3 million per incident on each nuclear
unit in the United States. The Company's maximum total assessment, $59.4
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 funds prove insufficient to pay claims, the United
States Congress could impose other revenue-raising measures on the nuclear
industry.

The Company's share of insurance coverage for property damage,
decommissioning and decontamination liability is $1.2 billion. The Company
would be responsible for its share of any damages in excess of insurance
coverage. In addition, if the property damage reserves of Nuclear Electric
Insurance Limited (NEIL), an industry mutual insurance company that provides a
portion of this coverage, are inadequate to cover claims arising from an
incident at any United States nuclear site covered by that insurer, effective
November 15, 1996, the Company could be assessed retrospective premiums
totaling a maximum of $7.3 million.

In addition, the Company participates in a NEIL program that provides
insurance for the increased cost of generation and/or purchased power resulting
from an accidental outage of a nuclear unit. Subject to the policy limit, the
coverage provides for 100 percent of the estimated incremental costs per week
during the 52-week period starting 21 weeks after an accident and 80 percent of
such estimate per week for the following 104 weeks with no coverage thereafter.
If NEIL's losses for this program ever exceed its reserves, the Company could be
assessed retrospective premiums totaling a maximum of $3.5 million.

Beaver Valley Power Station (BVPS) Steam Generators. 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 required removal of approximately 15 percent of its steam generator tubes
from service through a process called plugging. However, BV Unit 1 continues to
operate at 100 percent reactor power and has the ability to return tubes to
service by repairing them through a process called sleeving. To date, no tubes
at either BV Unit 1 or BV Unit 2 have been sleeved. BV Unit 2, which was placed
in service eleven years after BV Unit 1, has not yet exhibited the

degree of ODSCC experienced at BV Unit 1. Approximately 2 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.

The Company has undertaken certain measures, such as increased inspections,
water chemistry control and tube plugging, to minimize the operational impact of
and to reduce susceptibility to ODSCC. Although the Company has taken these
steps to allay the effects of ODSCC, the inherent potential for future ODSCC in
steam generator tubes of the Westinghouse design still exists. Material
acceleration in the rate of ODSCC could lead to a loss of plant efficiency,
significant repairs or the possible replacement of BV Unit 1's steam generators.
The total replacement cost of BV Unit 1's steam generators is currently
estimated at approximately $125.0 million. The Company would be responsible for
$59.0 million of this total, which includes the cost of equipment removal and
replacement steam generators but excludes replacement power costs. The earliest
that BV Unit 1's steam generators could be replaced is 1999.

BV Unit 1 completed its 11th refueling outage on May 11, 1996. The outage
lasted 49 days and was the shortest refueling outage in the history of the unit.
During the outage, various inspections of the unit's steam generators were made,
including examinations using a new "Plus Point" probe. As a result of these
inspections, the Company returned to service tubes that had previously been
plugged. Following the refueling outage, 85 percent of the steam generator tubes
were in service, approximately 1 percent more than at the beginning of the
outage.

BV Unit 2 began its 6th refueling outage on August 30, 1996. Various
inspections of the unit's steam generators, including inspections using the
"Plus Point" probe, have been completed. Upon completion of the outage,
approximately 98 percent of the unit's steam generator tubes will be in service.
Unanticipated repairs to two residual heat removal pumps will extend the outage
by approximately six weeks. The unit is expected to return to service in late
November.

The Company continues to explore all viable means of managing ODSCC,
including new repair technologies, and plans to continue to perform 100 percent
tube inspections during future refueling outages, which occur at approximately
18 month intervals for each unit. The Company 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 policy for handling and disposing of spent nuclear fuel and a
policy requiring the established final repository to accept spent fuel.
Electric utility companies have entered into contracts with the 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 fuel before 2010 at the earliest. On July 23, 1996, the U. S. Court of
Appeals for the District of Columbia Circuit, in response to a suit brought by
25 electric utilities and 18 states and state agencies, unanimously ruled that
the DOE has a legal obligation to begin taking spent fuel by January 31, 1998.
The DOE has not yet established an interim or permanent storage facility, and it
is uncertain whether the DOE will be able to accept spent nuclear fuel by
January 31, 1998. Further, Congress is considering amendments to the Nuclear
Waste Policy Act of 1982 that could give the DOE authority to proceed with the
development of a federal interim storage facility. In the event the DOE does not
begin accepting fuel, existing on-site fuel storage capacities at BV Unit 1, BV
Unit 2 and Perry Unit 1 are expected to be sufficient until 2016, 2010 and 2011,
respectively.

Uranium Enrichment Decontamination and Decommissioning Fund. 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 (NEPA) and are to be paid by such utilities
over a 15-year period. At September 30, 1996, the Company's liability for
contributions was approximately $9.9 million (subject to an inflation
adjustment). Contributions, when made, are recovered from electric utility
customers through the ECR.

Guarantees

The Company and the owners of Bruce Mansfield Power Station have guaranteed
certain debt and lease obligations related to a coal supply contract for the
Bruce Mansfield plant. At September 30, 1996, the Company's share of these
guarantees was $20.3 million. The prices paid for the coal by the companies
under this contract are expected to be sufficient to meet debt and lease
obligations to be satisfied in the year 2000. The minimum future payments to be
made by the Company solely in relation to these obligations total $21.0 million
at September 30, 1996.

As part of the Company's investment portfolio in affordable housing, the
Company has received fees in exchange for guaranteeing a minimum defined yield
to third party investors. A portion of the fees received has been deferred to
absorb any required payments with respect to these transactions. Based on an
evaluation of the underlying housing projects, it is management's belief that
such deferrals are ample for this purpose.

Residual Waste Management Regulations

In 1992, the Pennsylvania Department of Environmental Protection (DEP) issued
Residual Waste Management Regulations governing the generation and management of
non-hazardous residual waste, such as coal ash. The Company is assessing the
sites it utilizes and has developed compliance strategies that are now under
review by the DEP. Capital compliance costs of $3.0 million were incurred by
the Company in 1995 to comply with these DEP regulations; on the basis of
information currently available, an additional $2.5 million will be incurred in
1996. The expected additional capital cost of compliance through the year 2000
is estimated, based on current information, to be approximately $25.0 million.
This estimate is subject to the results of ground water assessments and DEP
final approval of compliance plans.

Employees

Other

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

______________________________

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 DQE and its subsidiaries' (the Company's) Annual Report on Form
10-K filed with the Securities and Exchange Commission (SEC) for the year ended
December 31, 1995 and the Company's condensed consolidated financial statements,
which are set forth on pages 2 through 13 in Part I, Item 1 of this Report.

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

The Company's Electric Operations

The Company's utility operations provide electric service to customers in
Allegheny County, including the City of Pittsburgh, and Beaver County. This
represents approximately 800 square miles in southwestern Pennsylvania, located
within a 500-mile radius of one-half of the population of the United States and
Canada. The population of the area served by the Company's electric utility
operations, based on 1990 census data, is approximately 1,510,000, of whom
370,000 reside in the City of Pittsburgh. In addition to serving approximately
580,000 direct customers, the Company's utility operations also sell electricity
to other utilities.

Regulation

The Company's electric utility operations are subject to regulation of the
Pennsylvania Public Utility Commission (PUC), as well as to regulation by 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.

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

The Company's consolidated financial statements report regulatory assets and
liabilities in accordance with Statement of Financial Accounting Standards No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71), and
reflect the effects of the ratemaking process. In accordance with SFAS No. 71,
the Company's consolidated financial statements reflect regulatory assets and
liabilities based on current cost-based ratemaking regulations. The regulatory
assets represent probable future revenue to the Company because provisions for
these costs are currently included, or are expected to be included, in charges
to electric utility customers through the ratemaking process.

The Company's electric utility operations currently satisfy the SFAS No. 71
criteria. However, a company's utility operations or a portion of such
operations could cease to meet these criteria for various reasons, including a
change in the PUC or the FERC regulations. (See "Competition" discussion on
page 19.) Should the Company's electric utility operations cease to meet the
SFAS No. 71 criteria, the Company would be required to write off any regulatory
assets or liabilities for those operations that no longer meet these
requirements. Management will continue to evaluate significant changes in the
regulatory and competitive environment in order to assess the Company's overall
compliance with the criteria of SFAS No. 71.

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

Seasonality

The quarterly results are not necessarily indicative of full-year operations
because of seasonal fluctuations. Sales of electricity to customers by the
Company's electric utility operations tend to increase during the warmer summer
and colder winter seasons because of greater customer use of electricity for
cooling and heating.

In the near term, weather conditions and the overall level of business
activity in the Company's electric utility geographic area are expected to
continue to be the primary factors affecting sales of electricity to customers.
In the long-term, the Company's electric sales may also be affected by increased
competition in the electric utility industry. (See "Competition" discussion on
page 19.)

Operating Revenues

Total operating revenues decreased $11.8 million during the third quarter of
1996 and remained constant during the first nine months of 1996 as compared to
the third quarter of 1995 and the first nine months of 1995.

Total sales of electricity decreased $18.8 million and $2.8 million during
the third quarter of 1996 and the first nine months of 1996 as compared to the
same periods in 1995. Cooler summer temperatures during 1996 resulted in lower
customer revenues in the third quarter from residential and commercial customers
of 11.8 percent and 2.8 percent. Revenue from sales of electricity to other
utilities decreased $0.8 million in the third quarter of 1996 when compared to
the corresponding quarter of 1995 due to increased price competition resulting
from additional power being marketed by other utilities. Direct customer
revenues from residential and commercial customers during the first nine months
of 1996 were 2.2 percent and 0.5 percent lower than for the same period of 1995
primarily due to cooler summer temperatures during 1996. Revenues from sales of
electricity to other utilities increased $5.8 million for the first nine

months of 1996 as compared to the same period in 1995. Scheduled outages at
Elrama, Cheswick, and Mansfield, as well as a forced outage at Ft. Martin,
reduced generation available for sales to other utilities during the first nine
months of 1995.

Other operating revenues increased $7.0 million during the third quarter of
1996 as compared to 1995 and increased $3.2 million during the first nine months
of 1996 as compared to 1995. The third quarter of 1996 increase was primarily
due to increased revenues at Chester Engineers (Chester), a wholly owned
subsidiary of DE, and due to increased billings to the other joint owners of BV
Unit 2 in connection with the 6th refueling outage. The year-to-date results
were primarily attributable to the increased revenues at Chester.

Operating Expenses

Total operating expenses decreased $11.2 million and increased $9.8 million
during the third quarter of 1996 and the first nine months of 1996 as compared
to the same periods in 1995.

Fuel and purchased power expense was $5.3 million lower in the third quarter
of 1996 when compared to the third quarter of 1995 primarily due to a 29 percent
decrease in the kilowatt hours purchased. In the first nine months of 1996, as
compared to the first nine months of 1995, fuel and purchased power expense
increased $4.6 million. This increase can be primarily attributed to a 4.4
percent increase in kilowatt hour sales which was partially offset by the
third quarter of 1996 decrease in kilowatt hours purchased.

Other operating expenses were $3.4 million and $5.1 million lower for the
third quarter of 1996 and for the first nine months of 1996 when compared to the
same periods in 1995. The decreases are primarily due to cost reductions at the
Company's utility operations. Additionally, the Company recorded operating
reserves related to discontinued environmental business units.

Maintenance expenses decreased $1.6 million when comparing the third quarters
of 1996 and 1995 and $2.1 million when comparing the first nine months of 1996
and 1995. The decreases are primarily due to lower refueling outage costs. The
lower expenses for the first nine months of 1996 also result from fewer fossil
station outages in 1996.

Depreciation and amortization expense was consistent when comparing the third
quarter of 1996 to the third quarter of 1995 and increased $13.8 million when
comparing the first nine months of 1996 to the first nine months of 1995. During
the third quarter of 1996, the Company completed recovery of its investment in
Perry Unit 2, the construction of which was abandoned by the Company in 1986.
The resultant decrease in amortization expense, combined with other lower
amortization costs, offset the Company's increase in depreciation related to the
Ft. Martin Plan. The increase for the first nine months of 1996 resulted from
the increased depreciation costs as well as $9.0 million which was expensed
related to the depreciation portion of deferred rate synchronization costs in
conjunction with the sale of its ownership interest in Ft. Martin. (See "Ft.
Martin Plan" discussion on page 18.)

Other Income

The $4.3 million and $9.6 million increases in the third quarter of 1996 and
the first nine months of 1996 in other income are primarily related to income
from long-term investments that were made since the third quarter of 1995.
During the first quarter of 1995 a pre-tax gain of approximately $7.2 million
was recorded related to the acquisition of International Power

Machines (IPM) by Exide Electronics Group (Exide).

Interest and Other Charges

Interest and other charges increased $2.5 million when comparing the third
quarter of 1996 to the third quarter of 1995 and were consistent when comparing
the first nine months of 1996 to the first nine months of 1995. The increase
in the current quarter was primarily due to the payment of $3.1 million in
dividends related to the Monthly Income Preferred Securities that were issued in
May 1996. (See Liquidity and Capital Resources, below.) The increase was
partially offset by decreased interest as the result of retirement and
refinancing of long-term debt.

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

Financing

The Company expects to meet its current obligations and debt maturities
through the year 2000 with funds generated from operations and through new
financings. At September 30, 1996, the Company was in compliance with all of
its debt covenants.

All of the Company's First Collateral Trust Bonds have been issued under a
mortgage indenture established in April 1992. All First Collateral Trust Bonds
became first mortgage bonds when the Company's 1947 first mortgage bond
indenture was retired in the third quarter of 1995 following the maturity of the
last bond series issued under that indenture.

On May 14, 1996, Duquesne Capital L.P., a Delaware special-purpose limited
partnership whose sole general partner is Duquesne, issued in aggregate $150.0
million principal amount of 8-3/8% Cumulative Monthly Income Preferred
Securities, Series A, with a stated liquidation value of $25. A portion of the
proceeds was used to retire $50.0 million of long-term debt maturing May 15,
1996. The Company intends to apply the remaining proceeds to the purchase or
redemption of outstanding securities and for general corporate purposes.

On June 24, 1996, the Company entered into a five-year bank term loan for
$10.0 million at a 7.5 percent annual rate of interest. The term loan pays
interest semi-annually.

Also on June 24, 1996, the Company extended one of its two revolving credit
agreements to June 23, 1997, and increased the facility from $100.0 million to
$125.0 million. Interest rates can, in accordance with the option selected at
the time of borrowing, be based on prime, Eurodollar or certificate of deposit
rates. Commitment fees are based on the unborrowed amount of the commitment. The
credit facility contains a two-year repayment period for any amounts outstanding
at the expiration of the revolving credit period.

In June 1996, a $50.0 million accounts receivable sales arrangement was
extended to June 25, 1997. The Company and an unaffiliated corporation have an
agreement that entitles the Company to sell, and the corporation to purchase, on
an ongoing basis, up to $50.0 million of accounts receivable. The Company may
attempt to extend the agreement or to replace the facility with a similar one or
to eliminate it upon expiration.

On July 24, 1996, the Company entered into an additional five-year bank term
loan for $50.0 million at a 7.3 percent annual rate of interest. The term loan
pays interest semi-annually.

On October 4, 1996, the Company extended its other revolving credit agreement
of $150.0 million to October 3, 1997. 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 commitment. The credit facility contains a two-year repayment period for
any amounts outstanding at the expiration of the revolving credit period.

On October 7, 1996, the Company entered into a $25.0 million, five-year term
loan at an effective interest rate of 7.02 percent.

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

The Company's market-driven long-term investments focus in five
principle areas: affordable housing, natural gas reserves, lease investments,
environmental services and energy solution investments. Investments in leases
for the nine months ended September 30, 1996 and 1995, were $47.0 million and
$60.0 million. The Company invested $3.1 million and $33.9 million in affordable
housing funds during the nine months ended September 30, 1996 and 1995. The
Company also invested $5.4 million and $21.0 million in natural gas reserve
partnerships during the nine months ended September 30, 1996 and 1995. In the
third quarter of 1996, the Company invested $3.0 million in a fuel cell company.

Outlook
- --------------------------------------------------------------------------------

Ft. Martin Plan

Martin. In addition to the annual credit of $5.0 million to the ECR, the
Company will cap energy costs beginning April 1, 1997 through the remainder of
the plan period, at a historical five-year average of 1.47 cents per kilowatt
hour. In accordance with the approved plan, the Company has expensed $9.0
million related to the depreciation portion of the $51.1 million of deferred
rate synchronization costs associated with BV Unit 2 and Perry Unit 1. Upon
final transfer of its ownership interest in Ft. Martin, the Company began to
amortize the remaining $42.1 million of deferred rate synchronization costs over
a ten-year period. Finally, the Company's approved plan also provides for
annual assistance of $0.5 million to low-income customers.

Deferred Coal Costs

The Company's regulatory assets include deferred coal costs of $11.3 million
and $12.8 million at September 30, 1996 and December 31, 1995. The Company
believes these deferred costs continue to represent probable future revenues
recoverable under all existing energy caps. The Company will continue to monitor
significant changes in the regulatory and competitive climate that would affect
its ability to recover these costs from electric utility customers. (See
"Regulation" discussion on page 14.)

Competition

The electric utility industry is undergoing fundamental change in response to
the open transmission access and increased availability of energy alternatives
fostered by the National Energy Policy Act of 1992 (NEPA), which has served to
increase competition in the industry. These competitive pressures require
utilities to offer competitive pricing and terms to retain customers and to
develop new markets for the optimal utilization of their generation capacity.

At the national level, on April 24, 1996, the FERC issued two related final
rules that address the terms on which electric utilities will be required to
provide wholesale suppliers of electric energy with non-discriminatory access to
the utility's wholesale transmission system. The first rule, Order No. 888,
addresses both open access and stranded cost issues. Each public utility that
owns, controls or operates interstate transmission facilities was required to
file, no later than July 9, 1996, a tariff that offers unbundled transmission
services containing non-rate terms that conform to the FERC's Order No. 888 pro
forma tariff and to propose rates for these services. The Company's tariff was
timely filed. Order No. 888 also provides for full recovery of those costs that
were prudently incurred to serve wholesale (and retail-turned wholesale)
customers that subsequently leave a utility's system. These costs will be
recovered from the departing customers. However, the FERC will not be the forum
for recovery of stranded costs arising when retail customers leave a utility's
system, even if their new suppliers rely on FERC-jurisdiction transmission
services, unless state regulators lack authority under state law to provide for
recovery. The rule indicates FERC's willingness to defer to state regulators
with respect to retail access, recovery of retail stranded costs and the scope
of state regulatory jurisdiction.

The second rule, Order No. 889, is the Open Access Same Time Information rule
(OASIS). This rule prohibits transmission owners and their affiliates from
gaining preferential access to information concerning transmission and
establishes a code of conduct to ensure the complete separation of a utility's
wholesale power marketing and transmission operation functions.

Finally, the FERC simultaneously issued a new Notice of Proposed Rulemaking
(NOPR) on Capacity Reservation Open Access Transmission Tariffs (CRT), which
would require all market participants to reserve firm capacity rights between
designated receipt and delivery points. If adopted, the CRT would replace the
open access pro forma tariff implemented in Order No. 888. On July 12, 1996,
the Company filed with the FERC a request for acceptance of

a CRT to replace the FERC pro forma tariff filed on July 9, 1996. (See
"Transmission Access" discussion on page 21.)

In Pennsylvania, the PUC has completed its investigation concerning
regulatory reform and has issued a report recommending to the governor and the
Pennsylvania General Assembly that retail customers be given a choice of their
electric supplier (retail choice). The report also recommends that existing
transmission and distribution franchises continue to be regulated by the PUC. In
addition, hearings have been held and legislation has been introduced in the
Pennsylvania state legislature. A broad group of interested parties led by the
Chairman of the PUC has reached a consensus on proposed amendments to previously
introduced legislation. This group included legislators, customer groups,
consumer advocates, small business advocates, environmental groups, labor
representatives, and utility representatives. First, the proposed amendments
provide for a transition period of two years, subject to two six-month
extensions at the discretion of the PUC, and a two-year phase-in period.
Utilities would be required to file transition plans between April 1, 1997 and
September 30, 1997. The transition plans would be subject to approval by the PUC
and would include the utilities' plans for the recovery and mitigation of
stranded costs. Second, excluding the effects of possible extensions, retail
choice would be open to 33 percent of all customer classes beginning January 1,
1999, 66 percent of all customer classes beginning January 1, 2000 and 100
percent of all customer classes beginning January 1, 2001. Finally, utilities
would have an opportunity to recover stranded costs, as determined by the PUC to
be just and reasonable, for recovery from customers through a competitive
transition charge for a period not to exceed nine years, unless a longer period
is approved by the PUC. The PUC may allow for all or a portion of the stranded
costs to be securitized by the issuance of bonds. Cost savings, if any,
associated with securitization of stranded costs would reduce prices to
customers. An overall 4.5 year price cap would be imposed on electric utility
companies. Additionally, an electric utility company may not increase the
generation price component as long as stranded costs are being recovered, with
certain limited exceptions. The proposed consensus amendments to the legislation
are expected to be presented to the legislature in November 1996. The Company
cannot predict what legislation, if any, may ultimately be enacted.

The Company is aware of the foregoing federal and state regulatory,
legislative and business uncertainties and is attempting to position itself to
operate in a more competitive environment. Because of the Company's current
electric generating configuration, some of its baseload capacity is used less
than optimally. The Company is currently considering ways to align its
generating capabilities more closely with customer demand. Its current rate
structure allows some flexibility in setting rates to retain its customer base
and attract new business. In addition, despite the fact that sales to wholesale
customers do not account for a significant portion of the Company's revenues,
open access transmission offers the Company the opportunity to sell power on a
market basis to customers outside of its geographic area.

Open access transmission requirements implicitly create the potential for
stranded costs. The Company implemented a $25.0 million annual increase to
depreciation and amortization expense in 1995 related to the Company's nuclear
investment and continues to further evaluate the accelerated depreciation of its
generating assets as one method to guard against the competitive risks of
stranded investments. On October 31, 1996 the sale of the Company's ownership
interest in Ft. Martin was completed. The PUC approved plan, including the sale
of Ft. Martin, provides for an increase of $25.0 million in depreciation and
amortization expense in 1996, $50.0 million in 1997 and $75.0 million in 1998
related to the Company's nuclear investment, as well as a one-time write-down in
the book value of the Company's nuclear plant investment of approximately $130.0
million. In addition, the Company's plan recognized an immediate expense of $9.0
million of deferred rate synchronization costs and, upon final

transfer of the Company's ownership interest in Ft. Martin, the Company began to
amortize the remaining $42.1 million balance over a ten-year period. (See "Ft.
Martin Plan" discussion on page 18.) These current and proposed accelerated
investment cost recovery measures will be absorbed by the Company without an
increase in base rates. Although the Company believes the initiatives will
enable it to mitigate these issues, the Company could face the risk of reduced
rates of return if unforeseen costs arise and if revenues from sales or if
sources of other income prove inadequate to fund those costs.

The Company believes that these and similar mitigation strategies will
strengthen its position to succeed in a more competitive environment by
eliminating the need to charge its electric utility customers in the future for
these currently recognized expenses. At this time, however, there is no
assurance as to the extent to which the Company's initiatives can or will
ultimately eliminate regulatory and other uncertainties associated with
increased competition.

In November 1996, the Company reached an agreement on a three year contract
extension with the International Brotherhood of Electrical Workers, which
represents approximately 2,000 of the Company's employees. It is the Company's
intent to provide a stable work force through the transition to a competitive
generation market with this contract, expiring September 30, 2001.

Transmission Access

In March 1994, the Company submitted, pursuant to the Federal Power Act, two
separate "good faith" requests for transmission service with Allegheny Power
System (APS) and the Pennsylvania-New Jersey-Maryland Interconnection
Association (PJM Companies), respectively. Each request is based on 20-year
firm service with flexible delivery points for 300 megawatts of transfer
capability over the APS and PJM Companies transmission networks, which together
extend from western Pennsylvania to the East Coast. Because of a lack of
progress on pricing and other issues, on August 5 and September 16, 1994, the
Company filed with the FERC applications for transmission service from the PJM
Companies and APS, respectively. The applications are authorized under Section
211 of the Federal Power Act, which requires electric utilities to provide firm
wholesale transmission service. In May 1995, the FERC issued proposed orders
instructing APS and the PJM Companies to provide transmission service to the
Company and directing the parties to negotiate specific rates, terms and
conditions. The Company was unable to agree to terms for transmission service
with either APS or the PJM Companies. Briefs were filed with the FERC outlining
the areas of disagreement among the companies. The matter is now pending before
the FERC.

On July 12, 1996, the Company filed with the FERC a request for acceptance of
a capacity reservation tariff to replace the FERC pro forma tariff filed on July
9, 1996 (previously discussed in "Competition" on page 19). The tariff is
intended to provide for the transition to retail customer choice in
Pennsylvania. The Company's tariff proposes to adopt marginal cost pricing for
transmission service on the Company transmission system. Marginal cost pricing
of transmission service will ensure that generators delivering energy to the
Company system will compete on the basis of their relative marginal costs. On
September 10, 1996, the FERC issued an order accepting the Company's tariff
filing and postponing its effectiveness for five months, or until February 11,
1997, subject to refund.

The Company is currently evaluating the impact of FERC regulatory actions on
these proceedings. The Company cannot predict the final outcome of these
proceedings.

Generation Resource Optimization

The Company's plans for optimizing generation resources are designed to
reduce underutilized generating capacity, promote competition in the wholesale
marketplace, maintain stable prices and meet customer-specified levels of
service reliability. The Company is committed to exploring firm energy sales to
wholesale customers, system power sales, system power sales with specific unit
back-up, unit power sales, generating asset sales and any other approach to
efficiently managing capacity and energy.

The sale of the Company's ownership interest in Ft. Martin demonstrates the
Company's ongoing efforts to optimize the utilization of generation resources.
(See "Ft. Martin Plan" discussion on page 18.) The sale is expected to reduce
power production costs by employing a cost-effective source of peaking capacity
through enhanced reliability of the BI combustion turbines. The reliability
enhancements are contingent upon the projects meeting a least-cost test versus
other potential sources of peaking capacity. Implementation of the plan will
better align the Company's generating capabilities with its native load
requirements.

______________________________

Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve
risks and uncertainties including, but not limited to, economic, competitive,
governmental and technological factors affecting the Company's operations,
markets, products, services and prices, and other factors discussed in the
Company's filings with the SEC.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

In September 1995, the Company commenced arbitration against Cleveland
Electric Illuminating Company (CEI), seeking damages, a declaratory judgment,
termination of the Operating Agreement for Eastlake Power Station Unit 5
(Eastlake), the appointment of a special operations advisor to oversee CEI's
operation of Eastlake, partition of the parties' interests in Eastlake through a
sale and division of the proceeds, and other equitable relief. 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,
particularly with regard to costs relating to the closing of the Powhattan No. 6
mine contract. The Powhattan No. 6 mine currently supplies coal to Eastlake.

In October 1995, CEI commenced an action against the Company in the Court of
Common Pleas, Lake County, Ohio seeking to enjoin the Company from taking any
action to effect a partition, through arbitration or otherwise, on the basis of
a waiver of partition contained in the deed to the land underlying Eastlake.
CEI also seeks monetary damages from the Company for alleged unpaid joint costs
in connection with the operation of Eastlake. It is the Company's position that
the deed covenant is unenforceable by CEI due to CEI's bad faith conduct toward
the Company, as described in the arbitration demand, and because it is
indefinite in duration, being tied to the useful life of Eastlake. The Company
removed the action to the United States District Court for the Northern District
of Ohio, Eastern Division, where it is now pending, and the parties have agreed
to litigate all of their disputes in federal court and to waive arbitration.
The Company asserted counterclaims in the action identical to the claims made in
its arbitration demand and joined CEI's parent, Centerior Energy Corporation, in
the claims. Several motions have been made by both parties, among them being
motions to dismiss, motions for summary judgment and a motion by the Company for
the appointment of a special operations advisor. The court has not ruled on any
of the motions.

Subject to these proceedings, the Company is currently soliciting offers for
its ownership interest in Eastlake, located near Cleveland, Ohio and operated by
Centerior Energy Corporation. The Company's 31.2 percent ownership interest
represents 186 megawatts of Eastlake's output capacity.

Item 6. Exhibits and Reports on Form 8-K

a. Exhibits:

EXHIBIT 10.1 - Resignation Agreement Between DQE and Duquesne Light Company
(the Companies) and Wesley W. von Schack

EXHIBIT 27.1 - Financial Data Schedule

b. No Current Report on Form 8-K was filed during the three months ended
September 30, 1996.

______________________________

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.

DQE
-----
(Registrant)

Date November 14, 1996 /s/ Gary L. Schwass
---------------------------- ----------------------------
(Signature)
Gary L. Schwass
Executive Vice President
and Chief Financial Officer

Date November 14, 1996 /s/ Morgan K. O'Brien
---------------------------- ----------------------------
(Signature)
Morgan K. O'Brien
Controller and
Principal Accounting Officer