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, 1997
----------------------

[ ] 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
----------------------
1-10290

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

Pennsylvania 25-1598483
------------ ----------
(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
-------------------------------------------------------------
(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 - 77,670,083 shares outstanding as of September
30, 1997 and October 31, 1997.

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,
------------- -------------
1997 1996 1997 1996
---- ---- ---- ----

Operating Revenues
Sales of Electricity:
Customers - net $305,754 $294,470 $820,294 $818,536
Utilities 6,212 14,599 21,232 45,641
---------- ---------- ---------- ----------
Total Sales of Electricity 311,966 309,069 841,526 864,177
Other 19,998 26,361 79,122 65,128
---------- ---------- ---------- ----------
Total Operating Revenues 331,964 335,430 920,648 929,305
---------- ---------- ---------- ----------

Operating Expenses
Fuel and purchased power 63,031 61,126 165,201 178,986
Other operating 67,527 73,708 227,140 215,883
Maintenance 21,229 19,554 61,529 58,922
Depreciation and amortization 61,397 53,709 175,117 166,517
Taxes other than income taxes 21,571 22,442 62,004 65,405
---------- ---------- ---------- ----------
Total Operating Expenses 234,755 230,539 690,991 685,713
---------- ---------- ---------- ----------

OPERATING INCOME 97,209 104,891 229,657 243,592
---------- ---------- ---------- ----------

OTHER INCOME 23,828 16,978 84,780 48,618
---------- ---------- ---------- ----------

INTEREST AND OTHER CHARGES 29,210 28,807 86,919 81,183
---------- ---------- ---------- ----------

INCOME BEFORE INCOME TAXES 91,827 93,062 227,518 211,027

INCOME TAXES 33,162 35,650 76,978 72,338
---------- ---------- ---------- ----------

NET INCOME $ 58,665 $ 57,412 $150,540 $138,689
========== ========== ========== ==========
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING
(Thousands of Shares) 77,605 77,194 77,430 77,391
========== ========== ========== ==========

EARNINGS PER SHARE OF
COMMON STOCK $0.75 $0.74 $1.94 $1.79
========== ========== ========== ==========

DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $0.34 $0.32 $1.02 $0.96
========== ========== ========== ==========

See notes to condensed consolidated financial statements.

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

September 30, December 31,
1997 1996
------------------ -----------------

ASSETS
Current assets:
Cash and temporary cash investments $ 398,312 $ 410,978
Receivables 113,112 130,125
Other current assets, principally materials and supplies 101,294 81,125
---------------- ---------------
Total current assets 612,718 622,228
---------------- ---------------
Long-term investments:
Leveraged leases 337,304 134,133
Affordable housing 139,268 150,270
Gas reserves 75,775 79,916
Other leases 73,717 85,893
Nuclear decommissioning trust 43,589 34,586
Marketable securities 34,646 16,063
Other long-term investments 20,603 17,828
---------------- ---------------
Total long-term investments 724,902 518,689
---------------- ---------------
Property, plant and equipment 4,769,364 4,787,470
Less: Accumulated depreciation and amortization (2,043,638) (1,969,945)
---------------- ---------------
Property, plant and equipment - net 2,725,726 2,817,525
---------------- ---------------
Other non-current assets:
Regulatory assets 595,940 636,816
Other 52,081 43,734
---------------- ---------------
Total other non-current assets 648,021 680,550
---------------- ---------------
TOTAL ASSETS $ 4,711,367 $ 4,638,992
================ ===============
LIABILITIES AND CAPITALIZATION
Current liabilities:
Notes payable $ 10,000 $ 749
Current maturities and sinking fund requirements 141,438 72,831
Other current liabilities 155,300 186,982
---------------- ---------------
Total current liabilities 306,738 260,562
---------------- ---------------
Deferred income taxes - net 772,618 759,089
---------------- ---------------
Deferred investment tax credits 99,887 106,201
---------------- ---------------
Capital lease obligations 30,496 28,407
---------------- ---------------
Deferred income 167,451 189,293
---------------- ---------------
Other non-current liabilities 271,019 240,763
---------------- ---------------
Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,357,989 1,439,746
---------------- ---------------
Preferred and preference stock of subsidiaries:
Preferred and preference stock before deferred employee stock
ownership plan (ESOP) benefit 242,116 242,605
Deferred ESOP benefit (17,220) (19,533)
---------------- ---------------
Total preferred and preference stock of subsidiaries 224,896 223,072
---------------- ---------------
Common shareholders' equity:
Common stock - no par value (authorized - 187,500,000 shares;
issued - 109,679,154 shares) 1,003,151 990,502
Retained earnings 849,149 777,607
Less treasury stock (at cost) (32,009,071 and 32,406,135
shares, respectively) (372,027) (376,250)
---------------- ---------------
Total common shareholders' equity 1,480,273 1,391,859
---------------- ---------------
Total capitalization 3,063,158 3,054,677
---------------- ---------------
TOTAL LIABILITIES AND CAPITALIZATION $ 4,711,367 $ 4,638,992
================ ===============

See notes to condensed consolidated financial statements.

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

Nine Months Ended
September 30,
-------------
1997 1996
-------------- --------------

Cash Flows From Operating Activities
Operations $ 329,281 $ 320,144
Changes in working capital other than cash (46,531) (26,510)
Other 2,791 2,281
------------ ------------
Net Cash Provided By Operating Activities 285,541 295,915
------------ ------------

Cash Flows From Investing Activities
Capital expenditures (67,875) (62,730)
Proceeds from the sale of property 4,124 -
Proceeds from the sale of equity securities 42,895 -
Long-term investments - net (200,283) (43,814)
Other 1,154 (3,587)
------------ ------------
Net Cash Used in Investing Activities (219,985) (110,131)
------------ ------------

Cash Flows From Financing Activities
Increase (Decrease) in notes payable - net 10,000 (25,218)
Issuance of preferred stock - 150,000
Dividends on common stock (78,996) (74,255)
(Reductions) increase of long term obligations - net (16,310) 2,130
Repurchase of common stock - (11,717)
Other 7,084 (6,354)
------------ ------------
Net Cash (Used in) Provided by Financing Activities (78,222) 34,586
------------ ------------
Net (decrease) increase in cash and temporary cash investments (12,666) 220,370
Cash and temporary cash investments at beginning of period 410,978 24,767
------------ ------------
Cash and temporary cash investments at end of period $ 398,312 $ 245,137
============ ============

Non-Cash Investing Activities
Equity funding obligations recorded $ 11,897 $ 23,046
============ ============
Equity funding obligations canceled $ 9,107 $ -
============ ============
On May 1, 1997, DQE exchanged its shares in Chester Engineers
for shares of common stock of the purchaser of Chester
Engineers which were subsequently sold at various dates
through June 5, 1997.

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, Inc. 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, Inc. (DQE), is an energy services holding company formed in 1989. Its
subsidiaries are Duquesne Light Company (Duquesne), Duquesne Enterprises, Inc.
(DE), DQE Energy Services, Inc. (DES), DQEnergy Partners, Inc. (DQEnergy) and
Montauk, Inc. (Montauk).

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 are intended to 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 operation,
domestic and international independent power production, and the production and
supply of innovative fuels. DQEnergy was formed in December 1996 to align DQE
with strategic partners to capitalize on opportunities in the energy services
industry. These alliances are intended to enhance the utilization and value of
DQE's strategic investments and capabilities while establishing DQE as a total
energy provider. Montauk is a financial services company that makes long-term
investments and was established to provide financing for the Company's other
market-driven businesses.

On August 7, 1997, the shareholders of the Company and Allegheny Energy,
Inc. (AYE), approved a proposed tax-free, stock-for-stock merger. Upon
consummation of the merger, DQE will be a wholly owned subsidiary of AYE.
Immediately following the merger, Duquesne, DE, DES, DQEnergy and Montauk will
remain wholly owned subsidiaries of DQE. The transaction is intended to be
accounted for as a pooling of interests. Under the terms of the transaction,
the Company's shareholders will receive 1.12 shares of AYE common stock for each
share of the Company's common stock, and AYE's dividend in effect at the time of
the closing of the merger. The transaction is expected to close in the first
half of 1998, subject to approval of applicable regulatory agencies, including
the public utility commissions in Pennsylvania and Maryland, the SEC, the
Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory
Commission. Further details about the proposed merger are provided in the
Company's report on Form 8-K, filed with the SEC on April 10, 1997, and the
Joint Proxy Statement/Prospectus of the Company and AYE, dated June 25, 1997,
which has been distributed to the Company's shareholders. Unless otherwise
indicated, all information presented in this Form 10-Q relates to the Company
only and does not take into account the proposed merger between the Company and
AYE.

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 1997 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, 1996, and the Quarterly Reports on Form 10-Q filed with the SEC for
the quarters ended March 31 and June 30, 1997. The results of operations for
the three and nine months ended September 30, 1997, 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
regulation by the Pennsylvania Public Utility Commission (PUC) and the FERC
under the Federal Power Act with respect to rates for interstate sales,
transmission of electric power, accounting and other matters.

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 current ratemaking process. In accordance with
SFAS No. 71, the Company's consolidated financial statements reflect regulatory
assets and liabilities consistent with cost-based, pre-competition ratemaking
regulations. (See "Rate Matters", Note 3, on page 7.)

The Company's long-term investments include investments in assets of
nuclear decommissioning trusts and marketable securities accounted for 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 amount of
unrealized holding gains on investments at September 30, 1997, was $11.1 million
($6.5 million net of tax). The amount of unrealized holding losses on
investments at December 31, 1996, was $3.6 million ($2.1 million net of tax).

Through the Energy Cost Rate Adjustment Clause (ECR), the Company recovers
(to the extent that such amounts are not included in base rates) nuclear fuel,
fossil fuel and purchased power expenses and, also through the ECR, passes to
its customers the profits from short-term power sales to other utilities
(collectively, ECR energy costs). Under the Company's mitigation plan approved
by the PUC in June 1996, the level of energy cost recovery is capped at 1.47
cents per kilowatt-hour (KWH) through May 2001. To the extent that current fuel
and purchased power costs, in combination with previously deferred fuel and
purchased power costs, are not projected to be recoverable through this pricing
mechanism, these costs would become transition costs subject to recovery through
a competitive transition charge (CTC). (See "Customer Choice Act" discussion,
Note 3, on page 7.)

2. RECEIVABLES

The components of receivables for the periods indicated are as follows:

September 30, September 30, December 31,
1997 1996 1996
(Amounts in Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------

Electric customer accounts receivable $ 94,844 $107,419 $ 92,475
Other utility receivables 18,595 36,626 22,402
Other receivables 19,263 25,585 33,936
Less: Allowance for uncollectible accounts (19,590) (19,517) (18,688)
- -------------------------------------------------------------------------------------------------------------
Total Receivables $113,112 $150,113 $130,125
=============================================================================================================

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 million of accounts receivable. At September 30, 1997, September 30, 1996,
and December 31, 1996, the Company had not sold any receivables to the
unaffiliated corporation. The accounts receivable sales agreement, which
expires in June 1998, is one of many sources of funds available to the Company.
The Company may attempt to extend the agreement, replace it with a similar
facility, or eliminate the agreement, upon expiration.

3. RATE MATTERS

Customer Choice Act

Under the Electricity Generation Customer Choice and Competition Act
(Customer Choice Act), which went into effect on January 1, 1997, Pennsylvania
has become a leader in customer choice. The Customer Choice Act will enable
Pennsylvania's electric utility customers to purchase electricity at market
prices from a variety of electric generation suppliers (customer choice).
Electric utility restructuring will be accomplished through a two-stage process
consisting of a pilot period (running through 1998) and a phase-in period (1999
through 2001). Before the phase-in to customer choice begins in 1999, the PUC
expects utilities to take vigorous steps to mitigate transition costs as much as
possible without increasing the price they currently charge customers. The PUC
will determine what portion of a utility's remaining transition costs will be
recoverable from customers through a CTC. This charge will be paid by consumers
who choose alternative generation suppliers as well as customers who choose
their franchised utility. The CTC could last as long as 2005, providing a
utility a total of up to nine years to recover transition costs, unless extended
as part of a utility's PUC-approved transition plan. An overall four-and-one-
half year price cap will be imposed on the transmission and distribution charges
of electric utility companies. Additionally, electric utility companies may not
increase the generation charge component of prices as long as transition costs
are being recovered, with certain exceptions. If a utility ultimately is unable
to recover its transition costs within the pricing structure and timeframe
approved by the PUC, such stranded costs will be written off.

conduct an investigation into certain competition issues relating to the
Restructuring Plan. Pursuant to an arrangement among Duquesne, the PUC and the
Attorney General, the Company anticipates a decision by the PUC (with respect to
the Restructuring Plan if the merger with AYE is approved, or with respect to
the Stand-Alone Plan if the merger is not approved) on or before May 29, 1998.

Both the Restructuring Plan and the Stand-Alone Plan use a market-based
valuation of generation to determine stranded costs. During each year of the
transition period, Duquesne will conduct a competitive solicitation to sell a
substantial block of generation with the resulting market values used to
determine each year's CTC. The CTCs paid by customers will therefore be known
and measurable, as required by the Customer Choice Act. Duquesne also proposes
a valuation to determine the final market value of its generation assets as of
December 31, 2005. This valuation will be performed in mid-2003 by an
independent board of experts and based on the best available market evidence.
The valuation may be triggered prior to 2003 if market prices rise to specified
levels, or if the minimum depreciation and amortization commitment is reached,
thereby ensuring that there will be no over-recovery of stranded costs.

The Company is committed to a minimum of $1.7 billion in depreciation and
amortization during the transition period while maintaining rates capped at
current levels. In addition, if revenues exceed expectations or additional cost
savings are available, the Company has proposed a return on equity "spillover"
mechanism that will ensure that the related revenues are used to further
mitigate stranded costs. Finally, both the Restructuring Plan and the Stand-
Alone Plan redesign rates to encourage more efficient electricity consumption
and to provide for additional stranded cost mitigation. The Company has long
encouraged economic development. Customers will have the opportunity to benefit
from a reduction in the cost of electricity for incremental consumption. This
rate redesign will be combined with the CTC mechanism to increase the potential
to maximize mitigation of stranded costs during the transition period.

In addition to the common elements in both plans, the Restructuring Plan
also incorporates the expected benefits of the merger with AYE, such as the
anticipated savings to Duquesne, on a nominal basis, of $365 million in
generation-related costs over 20 years, and $9 million in transmission-related
costs and $173 million in distribution-related costs over 10 years. Duquesne
plans to use the generation-related portion of its share of net operating
synergy savings to shorten the stranded cost recovery period. In addition, the
anticipated cost savings are expected to permit Duquesne to increase its minimum
depreciation and amortization commitment by an estimated $160 million, reduce
distribution rates by $25 million in 2001, and freeze distribution rates at this
reduced level until 2005. The merger-related synergies are expected to enable
Duquesne to reduce its stranded costs in 2005 by $200 million.

The foregoing paragraphs contain forward-looking statements (within the
meaning of the Private Securities Litigation Reform Act of 1995) regarding the
results and benefits of restructuring and the merger with AYE. Such forward-
looking statements involve known and unknown risks and uncertainties that may
cause the actual results and benefits to materially differ from those implied by
such statements. Such risks and uncertainties include, but are not limited to,
general economic and business conditions, industry capacity, changes in
technology, integration of the operations of AYE and Duquesne, regulatory
conditions to the merger, the loss of any significant customers, and changes in
business strategy or development plans.

Any estimate of the ultimate level of transition costs depends on, among
other things, the extent to which such costs are deemed recoverable by the PUC,
the ongoing level of Duquesne's costs of operations, regional and national
economic conditions, and growth of Duquesne's sales. The Company believes,
based upon prior rulings of the PUC, that it is entitled to recover
substantially all of its transition costs, but cannot predict the outcome of
this regulatory process. In the event the PUC rules that any or all of these
transition costs cannot be recovered through a CTC mechanism or the Company
fails to satisfy the requirements of SFAS No. 71, these stranded costs will be
written off. (See "Regulatory Assets and Emerging Issues Task Force" discussion
below.) As the Company has substantial exposure to transition costs relative to
its size, significant stranded cost write-offs could have a materially adverse
effect on the Company's financial position, results of operations and cash
flows. Various financial covenants and restrictions could be violated if
substantial write-off of assets or recognition of liabilities occurs.

Regulatory Assets and Emerging Issues Task Force

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.

A company's electric utility operations or a portion of such operations
could cease to meet the SFAS No. 71 criteria for various reasons, including a
change in the FERC regulations or the competition-related changes in the PUC
regulations. (See "Customer Choice Act" discussion on page 7.) Members of the
Emerging Issues Task Force of the Financial Accounting Standards Board (Task
Force) have discussed issues related to the impact of changes in the regulatory
environment for electric utilities. These changes have resulted from
initiatives which are intended to ultimately change the pricing of the
generation of electricity (but not of its transmission or distribution) to
competitive pricing. Although the arrangements vary from state to state, the
regulators are expected to provide (or are providing, such as in the Customer
Choice Act) for a transition period for the generation of electricity from a
fully regulated to a competitive environment. During these transition periods,
mechanisms are being provided for a utility to recover certain assets and
transition costs prior to (and, in some cases, subsequent to) the change to
competition, while at the same time the price of electricity generated after the
change to competition will be based on market rates. During this transition
period and thereafter, for the foreseeable future, the transmission and
distribution portions of a utility's operations are expected to continue to be
cost of service based rate regulated.

The Task Force has determined that once a transition plan has been
approved, application of SFAS No. 71 to the generation portion of a utility must
be discontinued and replaced by the application of Statement of Financial
Accounting Standards No. 101, Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71 (SFAS No. 101). The
consensus reached by the Task Force provides further guidance that the
regulatory assets and liabilities of the generation portion of a utility to
which SFAS No. 101 is being applied should be determined on the basis of the
source from which the regulated cash flows to realize such regulatory assets and
settle such liabilities will be derived. Under the Customer Choice Act the
Company believes that its generation-related regulatory assets will be recovered
through a CTC collected in connection with providing transmission and
distribution services and the Company will continue to apply SFAS No. 71. Fixed
assets related to the generation portion of a utility will be evaluated on the
cash flows provided by the CTC, in accordance with Statement of Financial
Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be

Disposed Of (SFAS No. 121). The Company believes that all of its regulatory
assets continue to satisfy the SFAS No. 71 criteria in light of the transition
to competitive generation under the Customer Choice Act and the ability to
recover these regulatory assets through a CTC. Once any portion of the
Company's electric utility operations is deemed to no longer meet the SFAS No.
71 criteria, or is not recovered through a CTC, the Company will be required to
write off any above-market cost assets, the recovery of which is uncertain, and
any regulatory assets or liabilities for those operations that no longer meet
these requirements. Any such write off of assets could be materially adverse to
the financial position of the Company.

The Company's regulatory assets related to generation, transmission, and
distribution as of September 30, 1997, were $463.1 million, $37.9 million and
$94.9 million, respectively. The components of all regulatory assets for the
periods presented are as follows:

September 30, December 31,
1997) 1996)
(Amounts in Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------

Regulatory tax receivable (a) $356,869 $394,131
Unamortized debt costs (b) 89,229 93,299
Deferred rate synchronization costs (c) 38,285 41,446
Beaver Valley Unit 2 sale/leaseback premium (d) 28,930 30,059
Deferred employee costs (e) 26,949 29,589
Deferred coal costs (see below) 14,563 12,191
DOE decontamination and decommissioning receivable (Note 4) 9,083 9,779
Deferred nuclear maintenance outage costs (f) 4,758 13,462
Other (g) 27,274 12,860
- -----------------------------------------------------------------------------------------------------
Total Regulatory Assets $595,940 $636,816
=====================================================================================================

(a) The deferred tax liabilities that were recorded in accordance with Statement
of Financial Accounting Standards No. 109, Accounting for Income Taxes are
expected to be recovered from customers through rates. The amortization of
the regulatory tax receivable results from reversals of deferred taxes as
depreciation and amortization expense.
(b) 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.
(c) The deferral of costs incurred from November 1987, when BV Unit 2 and Perry
Unit 1 went into commercial operation, until March 1988, when a rate order
was issued.
(d) The premium paid to refinance the Beaver Valley Unit 2 lease was deferred
for amortization over the life of the lease.
(e) Includes amounts for recovery of accrued compensated absences and accrued
claims for workers' compensation.
(f) Incremental maintenance expense incurred for refueling outages at the
Company's nuclear units is deferred for amortization over the period between
refueling outages (generally 18 months).
(g) Includes $7.7 million of costs to achieve the merger savings.

Deferred Coal Costs

The PUC has established two market price coal cost standards for the
Company. One applies only to coal delivered at the Bruce Mansfield Power
Station (Bruce Mansfield). The other, the system-wide coal cost standard,
applies to coal delivered to the remainder of the Company's system. Both
standards are updated monthly to reflect prevailing market prices of similar
coal. The PUC has directed the Company to defer recovery of the delivered cost
of coal to the extent that such cost exceeds generally prevailing market prices
for similar coal, as determined by the PUC. The PUC allows deferred amounts to
be recovered from customers when the delivered costs of coal fall below such
PUC-determined prevailing market prices.

In 1990, the PUC approved a joint petition for settlement that clarified
certain aspects of the system-wide coal cost standard. The Company has exercised
options to extend the coal cost standard through March 2000. The unrecovered
cost of Bruce Mansfield coal was $12.0 million and $9.6 million at September 30,
1997, and December 31, 1996. The unrecovered cost of the remainder of the
system-wide coal was $2.6 million at both September 30, 1997, and December 31,
1996. The Company believes that all deferred coal costs will be recovered.

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 (BI) from service and from
rate base. In accordance with the Company's Mitigation Plan, 112 megawatts
related to BI Units 2a and 2b were moved from property held for future use to
electric plant in service in 1996. Reliability enhancements at BI are
contingent upon the projects meeting a least-cost test versus other potential
sources of peaking capacity. As part of both the Restructuring Plan and the
Stand-Alone Plan, the Company is seeking recovery of its investment and
associated costs of Phillips and BI through a CTC. (See "Customer Choice Act"
discussion, Note 3, on page 7.) In the event that market demand, transmission
access or rate recovery do not support the utilization of these plants, the
Company may have to write off part or all of these investments and associated
costs. At September 30, 1997, the Company's net of tax investment in Phillips
and BI held for future use was $51.6 million and $18.3 million.

4. COMMITMENTS AND CONTINGENCIES

Construction

The Company estimates that it will spend, excluding the Allowance for Funds
Used During Construction and nuclear fuel, approximately $110 million for
electric utility construction during 1997. This estimate also excludes any
potential expenditures for reliability enhancements to the BI combustion
turbines.

Nuclear-Related Matters

The Company has an ownership or leasehold 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. The PUC ruled that recovery of the
decommissioning costs for Beaver Valley Unit 1 (BV Unit 1) could begin in 1977,
and that recovery of the decommissioning costs for Beaver Valley Unit 2 (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. 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 preliminary site-specific studies conducted in 1997 for BV Unit 1
and BV Unit 2, and an update of the 1994 study for Perry Unit 1, the Company'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 being used to determine the Company's cost
of service related to decommissioning all three nuclear units is $224 million.
The Company is seeking recovery of any potential shortfall in decommissioning
funding as part of either its Restructuring Plan or its Stand-Alone Plan. (See
"Customer Choice Act" discussion, Note 3, on page 7.)

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. The guidelines
require that decommissioning studies be performed at least every five years,
address 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. With respect to the
transition to a competitive generation market, the Customer Choice Act requires
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. The Company increased its annual funding level by approximately $5
million earlier in 1997. The annual contributions to the decommissioning funds
(as increased) are approximately $9 million. Funding for nuclear decommissioning
costs is deposited in external, segregated trust accounts and may be invested in
a portfolio of corporate common stock and debt securities, municipal bonds,
certificates of deposit and United States government securities. Trust fund
earnings increase the fund balances and the related recorded liability. The
market value of the aggregate trust fund balances at September 30, 1997, totaled
approximately $43.8 million.

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 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 possible 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, 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 during an
unscheduled outage resulting from an insured accident at a nuclear unit. Subject
to the policy deductible, terms and limit, the coverage provides for a weekly
indemnity of the estimated incremental costs during the three-year period
starting 21 weeks after an accident, 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 $3.4 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 have 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." To date, no tubes at either BV Unit 1 or BV Unit 2 have been
sleeved. BV Unit 2, which was placed in service in 1987, 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 the BV Unit 1 steam
generators. The total replacement cost of the BV Unit 1 steam generators is
currently estimated at $125 million. The Company 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 scheduled
refueling outage is the fall of 2000.

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. The most recent refueling
outage for BV Unit 1 began on September 27, 1997. The next refueling outage for
BV Unit 2 is scheduled to begin in March 1998. The Company will continue to
monitor and evaluate the condition of the BVPS steam generators. Perry Unit 1
completed a refueling outage on October 23, 1997. This outage lasted 40 days, a
record for Perry Unit 1.

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
U.S. Department of Energy (DOE) for the permanent disposal of spent nuclear fuel
and other 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. 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
nuclear fuel by January 31, 1998. The DOE has not yet established an interim or
permanent storage facility, and has indicated that it will be unable to begin
acceptance of spent nuclear fuel for disposal 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 spent
nuclear fuel, 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 2016 (end of
operating license), 2013 and 2011, respectively.

On January 31, 1997, the Company joined 35 other electric utilities in
filing a suit in the U.S. Court of Appeals for the District of Columbia against
the DOE. On March 19, 1997, a similar suit filed by 46 states, state agencies
and regulatory commissions was consolidated with the utilities' suit. The suits
request that the court suspend the utilities' payments into the Nuclear Waste
Fund and place future payments into an escrow account until the DOE fulfills its
obligation to accept spent nuclear fuel. The DOE has requested that the court
delay the litigation while it pursues alternative dispute resolution under the
terms of its contracts with the utilities, which could delay the fulfillment by
the DOE of its obligations to accept spent nuclear fuel. The Court is currently
considering arguments presented by the parties on September 25, 1997.
Significant additional expenditures for the storage of spent nuclear fuel at BV
Unit 2 and Perry Unit 1 could be required if the DOE does not fulfill its
obligation to accept spent nuclear fuel.

Uranium Enrichment Decontamination and Decommissioning. 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, 1997, the Company's liability
for contributions was approximately $9.3 million (subject to an inflation
adjustment). Contributions, when made, are currently recovered from electric
utility customers through the ECR. (See the discussion of the ECR on page 6.)

Fossil Decommissioning

In Pennsylvania, current ratemaking does not allow utilities to recover
future decommissioning costs through depreciation charges during the operating
life of fossil-fired generating stations. Based on studies conducted in 1997,
this amount for fossil decommissioning is currently estimated to be $130 million
for the Company's interest in 17 units at six sites. Each unit is expected to
be decommissioned upon the cessation of the final unit's operations. The Company
has submitted these estimates to the PUC, and is seeking to recover these costs
as part of either its Restructuring Plan or its Stand-Alone Plan. (See
"Competition Act" discussion, Note 3, on page 7.)

Guarantees

The Company and the other owners of Bruce Mansfield have guaranteed certain
debt and lease obligations related to a coal supply contract for Bruce
Mansfield. At September 30, 1997, the Company's share of these guarantees was
$15.1 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 are $16.6 million at September 30, 1997.

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, the Company believes 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
currently under review by the DEP. Capital costs of $2.5 million were incurred
by the Company in 1996 to comply with these DEP regulations. Based on
information currently available, an additional $2.8 million will be spent in
1997. The additional capital cost of compliance through the year 2000 is
estimated, based on current information, to be $17 million. This estimate is
subject to the results of groundwater assessments and DEP final approval of
compliance plans.

Environmental Matters

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

On July 18, 1997, the Environmental Protection Agency announced new
national ambient air quality standards for ozone and fine particulate matter. To
allow each state time to determine what areas may not meet the standards and to
adopt control strategies to achieve compliance, the ozone standards will not be
implemented until 2004, and the fine particulate matter standards will not be
implemented until 2007 or later. Because appropriate state ambient air
monitoring and implementation plans have not been developed, the costs of
compliance with these new standards cannot be determined by the Company at this
time.

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, Inc. 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, 1996 and the Company's condensed consolidated financial
statements, which are set forth on pages 2 through 15 in Part I, Item 1 of this
Report.

General
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On August 7, 1997, the shareholders of the Company and Allegheny Energy,
Inc. (AYE), approved a proposed tax-free, stock-for-stock merger. Upon
consummation of the merger, the Company will be a wholly owned subsidiary of
AYE. Immediately following the merger, Duquesne, DE, DES, DQEnergy and Montauk
will remain wholly owned subsidiaries of the Company. The transaction is
expected to close in the first half of 1998, subject to approval of applicable
regulatory agencies. (See "Proposed Merger" discussion on page 22.)

The Company's Electric Service Territory

The Company's utility operations provide electric service to customers in
Allegheny County, including the City of Pittsburgh, Beaver County and
Westmoreland County. (See "Competition" discussion on page 23.) 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 is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to
regulation by the Pennsylvania Public Utility Commission (PUC) 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.

The Electricity Generation Customer Choice and Competition Act (Customer
Choice Act) went into effect in Pennsylvania on January 1, 1997. This
legislation provides for a gradual deregulation of the generation of
electricity, while maintaining regulation of the transmission and distribution
of electricity and related services to customers. On August 1, 1997, Duquesne
filed its restructuring plan with the PUC, setting forth its plan to enable
customers to choose their electric generation supplier. (See "Competition"
discussion on page 23.)

The Company'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.

A company's electric utility operations or a portion of such operations
could cease to meet the SFAS No. 71 criteria for various reasons, including a
change in the FERC regulations or the competition-related changes in the PUC
regulations described above. (See "Competition" discussion on page 23.) Members
of the Emerging Issues Task Force of the Financial Accounting Standards Board
(Task Force) have discussed issues related to the impact of changes in the
regulatory environment for electric utilities. Although the arrangements vary
from state to state, the regulators are expected to provide (or are providing,
such as in the Customer Choice Act) for a transition period for the generation
of electricity from a fully regulated to a competitive environment. During
these transition periods, mechanisms are being provided for a utility to recover
certain assets and transition costs prior to (and, in some cases, subsequent to)
the change to competition, while at the same time the price of electricity
generated after the change to competition will be based on market rates. The
Task Force has determined that once a transition plan has been approved,
application of SFAS No. 71 to the generation portion of a utility must be
discontinued and replaced by the application of Statement of Financial
Accounting Standards No. 101, Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71 (SFAS No. 101). The
consensus reached by the Task Force provides further guidance that the
regulatory assets and liabilities of the generation portion of a utility to
which SFAS No. 101 is being applied should be determined on the basis of the
source from which the regulated cash flows to realize such regulatory assets and
settle such liabilities will be derived. Under the Customer Choice Act the
Company believes that its generation-related regulatory assets will be recovered
through a competitive transition charge (CTC) collected in connection with
providing transmission and distribution services and the Company will continue
to

apply SFAS No. 71. Fixed assets related to the generation portion of a utility
will be evaluated on the cash flows provided by the CTC, in accordance with
Statement of Financial Accounting Standards No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of
(SFAS No. 121). The Company believes that all of its regulatory assets
continue to satisfy the SFAS No. 71 criteria in light of the transition to
competitive generation under the Customer Choice Act and the ability to recover
these regulatory assets through a CTC. Once any portion of the Company's
electric utility operations is deemed to no longer meet the SFAS No. 71
criteria, or is not recovered through a CTC, the Company will be required to
write off any above-market cost assets, the recovery of which is uncertain, and
any regulatory assets or liabilities for those operations that no longer meet
these requirements. Any such write off of assets could be material to the
financial position of the Company.

RESULTS OF OPERATIONS
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Sales of Electricity to Customers

The third quarter of 1997 decrease in total operating revenues was $3.5
million or 1.0 percent, as compared to the third quarter of 1996. Total
operating revenues decreased $8.7 million or 0.9 percent, when comparing the
nine months ended September 30, 1997, to the same period in 1996. Operating
revenues are primarily derived from the Company's sales of electricity. The PUC
authorizes rates for electricity sales which are cost-based and are designed to
recover the Company's operating expense and investment in electric utility
assets and to provide a return on the investment. (See "Regulation" and
"Competition" discussions on pages 17 and 23.)

Sales to residential and commercial customers are influenced by weather
conditions. Warmer summer and cooler winter seasons lead to increased customer
use of electricity for cooling and heating. Commercial sales are also affected
by regional economic development. Customer revenues fluctuate as a result of
changes in sales volume and changes in fuel and other energy costs, as these
costs are generally recoverable from customers through the Energy Cost Rate
Adjustment Clause (ECR).

Through the ECR, the Company recovers (to the extent that such amounts are not
included in base rates) nuclear fuel, fossil fuel and purchased power expenses
and, also through the ECR, passes to its customers the profits from short-term
power sales to other utilities (collectively, ECR energy costs). Under the
Company's mitigation plan approved by the PUC in June 1996, the level of energy
cost recovery is capped at 1.47 cents per kilowatt-hour (KWH) through May 2001.
To the extent that current fuel and purchased power costs, in combination with
previously deferred fuel and purchased power costs, are not projected to be
recoverable through this pricing mechanism, these costs would become transition
costs subject to recovery through a competitive transition charge. (See
"Competition" discussion on page 23.)

Net Customer Revenues

Net customer revenues, reflected on the statement of consolidated income,
increased $11.3 million or 3.8 percent in the third quarter of 1997, as compared
to the same period in 1996. The variance can be attributed primarily to an
increase in energy costs, the result of a less favorable generation mix and a
higher cost purchased power market. To a lesser extent, customer revenues
were favorably impacted by an increase of 7.5 percent in industrial (KWH)
sales. Sales to a new customer, an industrial gas supplier, represented 72
percent of the increase while the remaining industrial increase was due to
expansion of one of the Company's largest customers' facilities. Residential
and commercial sales were relatively unchanged when comparing the third quarters
of 1997 and 1996.

In the nine months ended September 30, 1997, as compared to the same period in
1996, net customer revenues increased $1.8 million or 0.2 percent. This increase
was due to higher energy costs. For the nine months ended

September 30, 1997, industrial KWH sales increased 6.5 percent, as compared to
the same period in 1996. The increase was the result of sales to a new
customer, an industrial gas supplier, and improved business for several of the
Company's largest industrial customers. Offsetting the increase in industrial
sales were decreases in residential and commercial sales. Reduced residential
and commercial customer KWH sales of 2.5 percent and 1.7 percent were due to
mild temperatures, as compared to 1996, and resulted in a $3.7 million or 0.6
percent decrease in revenues.

Sales to Other Utilities

Short-term sales to other utilities are regulated by the FERC and are made at
market rates. Fluctuations in electricity sales to other utilities are related
to the Company's customer energy requirements, the energy market and
transmission conditions, and the availability of the Company's generating
stations. The Company's electricity sales to other utilities in the third
quarter of 1997 were $8.4 million or 57.4 percent less than in the third quarter
of 1996. In a comparison of the nine months ended September 30, 1997, to the
same period in 1996, sales to other utilities decreased $24.4 million or 53.5
percent. The fluctuations were due to reduced availability of generating
capacity as a result of the sale of the Company's 50 percent interest in the Ft.
Martin Power Station (Ft. Martin) in October 1996 and to increased forced
outages of the BV Units 1 and 2 and a planned refueling outage at Perry Unit 1.
Future levels of short-term sales to other utilities will be affected by market
rates and by the outcome of the Company's FERC filings requesting firm
transmission access. (See "Outlook" discussion on page 22.)

Other Operating Revenues

Other operating revenues include the Company's non-KWH utility revenues and
revenues from market-based operating activities. The other operating revenue
decrease of $6.4 million or 24.1 percent when comparing the third quarter of
1997 and 1996 was the result of reduced revenues as a result of the sale of
Chester Engineers (Chester) in the second quarter of 1997, partially offset by
revenues from an investment made in the fourth quarter of 1996.

The variance in the nine months ended September 30, 1997, as compared to
the same period in 1996, was an increase of $14.0 million or 21.5 percent. The
increase was primarily due to revenues from an investment made in the fourth
quarter of 1996 and revenues from a second quarter settlement, partially offset
by reduced revenues attributable to the sale of Chester in the second quarter of
1997.

Operating Expenses

Fuel and Purchased Power Expense. Fluctuations in fuel and purchased power
expense generally result from changes in the cost of fuel, the mix between coal
and nuclear generation, the total KWHs sold, and generating station
availability. Because of the ECR, changes in fuel and purchased power costs did
not impact earnings in the third quarter of 1997 and 1996 or in the nine months
ended September 30, 1997 and 1996.

Fuel and purchased power expense increased $1.9 million or 3.1 percent in the
third quarter of 1997, as compared to the third quarter of 1996, as a result of
increases in purchased power and fossil fuel volumes due to reduced nuclear
availability from forced outages at BV Units 1 and 2 and a scheduled outage at
Perry Unit 1. The increase was partially offset by a 9.2 percent reduction in
sales volume. The decrease of $13.8 million or 7.7 percent for fuel and
purchased power expense in the nine months ended September 30, 1997, as compared
to the same period in 1996, was a reflection of the 10.4 percent decrease in
sales volume. The decrease was partially offset by increased purchased power
prices.

Other Operating Expense. Other operating expense decreased $6.2 million or
8.4 percent when comparing the third quarter of 1997 and the third quarter of
1996 and increased $11.3 million or 5.2 percent when comparing the first nine
months of 1997 with the first nine months of 1996.

The decrease in the third quarter of 1997 was primarily the result of
reduced operating costs associated with Chester, which was sold during the
second quarter of 1997, partially offset by operating costs of an investment
made in the fourth quarter of 1996. The increase in the first nine months of
1997 included operating costs of an investment made in the fourth quarter of
1996, partially offset by reduced operating costs of Chester.

Maintenance Expense. In comparing the third quarter of 1997 to the third
quarter of 1996, maintenance expense increased $1.7 million or 8.6 percent. In
the nine months ended September 30, 1997, there was an increase of $2.6 million
or 4.4 percent, as compared to the same period in 1996. During 1997 there were
approximately 45 percent more outage days at nuclear stations than in 1996 due
to forced outages at BV Units 1 and 2 and a scheduled refueling outage at Perry
Unit 1.

Depreciation and Amortization Expense. In the third quarter of 1997,
depreciation and amortization expense increased $7.7 million or 14.3 percent as
compared to the third quarter of 1996. There was a $8.6 million or 5.2 percent
increase in the nine months ended September 30, 1997, when compared to the same
period in 1996. The increases were the result of accelerated nuclear lease
recovery which began in the second quarter of 1997, as well as increased funding
of the nuclear decommissioning trust, in accordance with the PUC-approved sale
of Ft. Martin.

Taxes Other Than Income Taxes. During the third quarter of 1997 and the first
nine months of 1997, taxes other than income taxes decreased $0.9 million or 3.9
percent and $3.4 million or 5.2 percent, respectively, from the same periods in
1996, due to the reduced West Virginia Business and Occupation taxes as a result
of the sale of Ft. Martin in the fourth quarter of 1996.

Other Income

Comparing the third quarter of 1997 to the third quarter of 1996, other income
increased $6.9 million or 40.3 percent. The increase was the result of
additional interest income recognized from a higher level of short-term
investments and long-term investment income. During the nine months ended
September 30, 1997, there was an increase of $36.2 million including the sale of
Chester. A pre-tax gain of approximately $13.0 million net of costs of the
sale and reserves for contingencies was realized on the sale in the second
quarter of 1997. The remaining increase was the result of additional interest
income recognized from a higher level of short-term investments and long-term
investment income.

Interest and Other Charges

In comparing the nine months ended September 30, 1997, with the same period in
1996, there was a $5.7 million or 7.1 percent increase in interest and other
charges. The reason for this increase was primarily the recognition of three
full quarters of dividends in 1997 related to Monthly Income Preferred
Securities issued in May 1996.

Income Taxes

Income taxes decreased in the third quarter of 1997 as compared to the same
period in 1996 by $2.5 million. The variance was due to a decrease in the
Pennsylvania corporate net income tax and lower taxable income. In the nine
months ended September 30, 1997, income taxes increased $4.6 million as compared
to the same period in 1996. The increase in income taxes can be attributed to
increased taxable income, as the effective tax rate remained constant.
Partially offsetting this increase was the Pennsylvania corporate net income tax
decrease which occurred in the third quarter of 1997.

Liquidity and Capital Resources
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Financing

The Company expects to meet its current obligations and debt maturities
through the year 2001 with funds generated from operations and through new
financings. At September 30, 1997, the Company was in compliance with all of
its debt covenants.

Mortgage bonds in the amount of $50 million, $35 million and $35 million
will mature in November 1997, February 1998 and June 1998, respectively. The
Company expects to retire these bonds with available cash or to refinance the
bonds.

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 million of accounts receivable. This $50 million accounts receivable sale
arrangement extends through June 1998. The Company may attempt to extend the
agreement, or replace it with a similar facility, or eliminate the agreement,
upon expiration.

The Company maintains a $150 million revolving credit facility which
expires in October 1998. No borrowings were outstanding under this facility at
September 30, 1997. The Company also maintains a $125 million revolving credit
facility expiring in June 1998. There were $10 million in borrowings
outstanding at September 30, 1997. The weighted average interest rate applied
to such borrowings was 6.1 percent. With respect to each of these revolving
credit facilities, 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. Each revolving credit facility contains a two-year repayment period
for any amounts outstanding at the expiration of the revolving credit period.
The Company also maintains an aggregate of $150 million in bank term loans
outstanding at September 30, 1997.

Investing
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The Company has made market-driven long-term investments in the following
areas: leases; affordable housing; gas reserves; real estate; energy facility
development, operation and maintenance; engineering services; and other
investments. Investing activities during the first nine months of 1997 included
approximately $171.6 million in lease investments, $8.4 million in affordable
housing investments, $11.5 million in natural gas reserve partnerships and the
remaining $12.4 million in other investments. During the first nine months of
1996, the Company invested approximately $47.0 million in lease investments,
$3.1 million in affordable housing investments, $5.4 million in natural gas
reserve partnerships and the remaining $9.3 million in other investments.
During the first nine months of 1997, the Company also had long-term sales
primarily of gas reserve partnerships totaling $3.6 million. The Company had
long-term sales primarily of leveraged lease investments totaling $17.7 million
during the first nine months of 1996.

The Company currently holds 1,058,750 shares of common stock of Exide
Electronics Group, Inc. (Exide) as an investment. On October 16, 1997, Exide
and BTR plc (BTR) announced a definitive merger agreement, pursuant to which BTR
intends to acquire Exide through a tender offer for $29 per share in cash. The
tender offer is conditioned on 80 percent of the fully diluted Exide common
stock being tendered by midnight November 17. If the merger is approved and
completed, the Company anticipates approximately an $11 million pre-tax gain on
its investment in Exide.

Outlook
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Proposed Merger

On August 7, 1997, the shareholders of the Company and AYE approved a
proposed tax-free, stock-for-stock merger. Upon consummation of the merger, DQE
will be a wholly owned subsidiary of AYE. Immediately following the merger,
Duquesne, DE, DES, DQEnergy and Montauk will remain wholly owned subsidiaries of
DQE. The transaction is intended to be accounted for as a pooling of interests.
Under the terms of the transaction, the Company's shareholders will receive 1.12
shares of AYE common stock for each share of the Company's common stock, and
AYE's dividend in effect at the time of the closing of the merger. The
transaction is expected to close in the first half of 1998, subject to approval
of applicable regulatory agencies as discussed above. Further details about the
proposed merger are provided in the Company's report on Form 8-K, filed with the
SEC on April 10, 1997, and the Joint Proxy Statement/Prospectus of the Company
and AYE, dated June 25, 1997, which has been distributed to the Company's
shareholders. Unless otherwise indicated, all information presented in this
Form 10-Q relates to the Company only and does not take into account the
proposed merger between the Company and AYE.

On August 1, 1997, the Company, Duquesne and AYE had previously filed their
restructuring and merger plans with the FERC, the PUC and the Maryland Public
Service Commission. At that time Duquesne also applied with the NRC for
approval of the indirect transfer of licenses to AYE. Additional filings
related to the merger will be made with other agencies, including the SEC, the
Department of Justice and the Federal Trade Commission. The Company cannot
predict the outcome of any of these filings.

Competition

The electric utility industry continues to undergo fundamental change in
response to open transmission access and increased availability of energy
alternatives. Under historical PUC ratemaking, 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. As a result of this historical ratemaking
process, utilities have assets recorded on their balance sheets at above-market
costs and have commitments to purchase power at above-market prices (transition
costs).

Under the Customer Choice Act, which went into effect on January 1, 1997,
Pennsylvania has become a leader in customer choice. The Customer Choice Act
will enable Pennsylvania's electric utility customers to purchase electricity at
market prices from a variety of electric generation suppliers (customer choice).
Electric utility restructuring will be accomplished through a two-stage process
consisting of a pilot period (running through 1998) and a phase-in period (1999
through 2001). The pilot period will give utilities an opportunity to examine a
wide range of technical and administrative details related to competitive
markets, including metering, billing, and cost and design of unbundled electric
services. Duquesne filed a pilot program with the PUC on February 27, 1997,
which proposed unbundling transmission, distribution, electricity and
competitive transition charges and offered participating customers the same
options that were to be available in a competitive generation market. The pilot
program was designed to comprise approximately 5 percent of Duquesne's
residential, commercial and industrial demand. The approximately 28,000
customers participating in the pilot may choose unbundled service with their
electricity provided by an alternative electric generation supplier, and will be
subject to unbundled distribution charges approved by the PUC and unbundled
transmission charges pursuant to Duquesne's FERC-approved tariff. Each customer
also will be required to pay a non-bypassable access fee (competitive transition
charge or CTC) that would provide Duquesne with a reasonable opportunity to
recover transition costs during the period and subject to the generation cap
discussed below. On May 9, 1997, the PUC issued a Preliminary Opinion and Order
approving the Company's filing in part, and requiring certain revisions. The
Company and other utilities objected to several features of the PUC's
preliminary order. Hearings on several key issues were held in July. The PUC
issued its final order on August 29, 1997, approving a revised pilot program for
the Company. On September 8, 1997, the Company appealed the determination of the
market price of generation set forth in this order to the Commonwealth Court of
Pennsylvania. Although this appeal is still pending, the Company has complied
with the PUC's order to implement the pilot program which began on November 1,
1997.

It is anticipated that the net financial impact of Duquesne's customers
choosing alternative generation suppliers during the pilot period will be a
reduction of operating revenue of approximately $1 million per month. Until
the PUC rules on Duquesne's Restructuring Plan or Stand-Alone Plan (each as
defined below), in which Duquesne is seeking to maintain its current rates,
Duquesne will establish a reserve for this shortfall. To the extent there is a
revenue shortfall between rates established for the pilot period and rates set
upon approval of the Restructuring Plan or Stand-Alone Plan, the PUC has
authorized Duquesne to establish a regulatory asset for any resulting income
impact and will rule on the recovery of this regulatory asset as part of its
approval of Duquesne's Restructuring Plan or Stand-Alone Plan. To the extent
rates for the Restructuring Plan or Stand-Alone Plan are below current rates,
the difference will be written off.

The phase-in to competition begins on January 1, 1999, when 33 percent of
consumers will have customer choice (including consumers covered by the pilot
program); 66 percent of consumers will have customer choice by January 1, 2000;
and all consumers will have customer choice by January 1, 2001. Although the
Customer Choice Act will give customers their choice of electric generation
suppliers, delivery of the electricity from the generation supplier to the
customer will

remain the responsibility of the existing franchised utility. Delivery of
electricity (including transmission, distribution and customer service) will
continue to be regulated in substantially the current manner. Before the phase-
in to customer choice begins in 1999, the PUC expects utilities to take vigorous
steps to mitigate transition costs as much as possible without increasing the
price they currently charge customers. The PUC will determine what portion of a
utility's remaining transition costs will be recoverable from customers through
a CTC. This charge will be paid by consumers who choose alternative generation
suppliers as well as customers who choose their franchised utility. The CTC
could last as long as 2005, providing a utility a total of up to nine years to
recover transition costs, unless extended as part of a utility's PUC-approved
transition plan. An overall four-and-one-half year price cap will be imposed on
the transmission and distribution charges of electric utility companies.
Additionally, electric utility companies may not increase the generation price
component of prices as long as transition costs are being recovered, with
certain exceptions. If a utility ultimately is unable to recover its transition
costs within the pricing structure and timeframe approved by the PUC, such
stranded costs will be written off.

On August 1, 1997, Duquesne filed its restructuring and merger plan (the
Restructuring Plan) and its stand-alone restructuring plan (the Stand-Alone
Plan) with the PUC. Although the provisions of the Competition Act require a
PUC decision nine months from the filing date (which would be April 30, 1998),
the Pennsylvania Attorney General's Office requested an extension in order to
conduct an investigation into certain competition issues relating to the
Restructuring Plan. Pursuant to an arrangement among Duquesne, the PUC and the
Attorney General, the Company anticipates a decision by the PUC (with respect to
the Restructuring Plan if the merger with AYE is approved, or with respect to
the Stand-Alone Plan if the merger is not approved) on or before May 29, 1998.

plans to use the generation-related portion of its share of net operating
synergy savings to shorten the stranded cost recovery period. In addition, the
anticipated cost savings are expected to permit Duquesne to increase its minimum
depreciation and amortization commitment by an estimated $160 million, reduce
distribution rates by $25 million in 2001, and freeze distribution rates at this
reduced level until 2005. The merger-related synergies are expected to enable
Duquesne to reduce its stranded costs beginning in 2005 by $200 million.

Any estimate of the ultimate level of transition costs depends on, among
other things, the extent to which such costs are deemed recoverable by the PUC,
the ongoing level of Duquesne's costs of operations, regional and national
economic conditions, and growth of Duquesne's sales. The Company believes that
it is entitled to recover substantially all of its transition costs, based upon
prior PUC rulings issued to Duquesne, but cannot predict the outcome of this
regulatory process. In the event the PUC rules that any or all of these
transition costs cannot be recovered through a CTC mechanism or the Company
fails to satisfy the requirements of SFAS No. 71, these stranded costs will be
written off. (See "Regulation" discussion on page 17.) As the Company has
substantial exposure to transition costs relative to its size, significant
stranded cost write-offs could have a materially adverse effect on the Company's
financial position, results of operations and cash flows. Various financial
covenants and restrictions could be violated if substantial write-off of assets
or recognition of liabilities occurs.

In addition to the Restructuring Plan and the Stand-Alone Plan, on August 1,
1997, the Company and AYE filed their joint merger application with the FERC
(the FERC Filing). Pursuant to the FERC Filing, the Company and AYE have
committed to forming or joining an independent system operator (ISO) which meets
their requirements following the merger. In addition, the Company and AYE have
stated in the FERC Filing that following the merger Allegheny Energy's market
share will not violate the market power conditions and requirements set by the
FERC.

At the national level, in 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, requires
each public utility that owns, controls or operates interstate transmission
facilities to file a tariff offering unbundled transmission services containing
non-rate terms that conform to the FERC's pro forma tariff. Order No. 888 also
allows full recovery of prudently incurred costs from departing customers. FERC
deferred to state regulators with respect to retail access, recovery of retail
transition costs and the scope of state regulatory jurisdiction. The second
rule, Order No. 889, 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.

The Company is aware of the foregoing state and federal regulatory and
business uncertainties and is attempting to position itself to effectively
operate in a more competitive environment.

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. The units continue to have the
capability to operate at 100 percent reactor power although 15 percent of BV
Unit 1 and 2 percent of BV Unit 2 steam generator tubes have been removed from
service. Material acceleration in the rate of ODSCC could lead to a loss in
plant efficiency and significant repairs or replacement of BV Unit 1 steam
generators. The total replacement cost of the BV Unit 1 steam generators is
estimated at $125 million, $59 million of which would be the Company's
responsibility. The earliest that the BV Unit 1 steam generators could be
replaced during a scheduled refueling outage is the fall of 2000.

Other

In September 1997, the Company amended its service contract with Itron,
Inc., with respect to the Customer Advanced Reliability System (CARS). The
amendment extends by one year into 1998 the period during which Itron, Inc.,
will install and finalize the system. As of September 30, 1997, more than 98
percent of customers' meters had been adapted for CARS, and more than 450,000
meters were being read automatically.

The Company owns Warwick Mine, an underground mine in southwestern
Pennsylvania. In September 1997, the Company completed negotiations and entered
into an agreement with a new unaffiliated contract operator of the mine.
Production of coal under this agreement began in October 1997.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Currently not applicable.

______________________________

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, 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. 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 on the basis of a waiver of partition
covenant 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. The Company removed the action to the United
States District Court for the Northern District of Ohio, Eastern Division, where
it is now pending. The Company anticipates that a trial will commence in the
third quarter of 1998.

On September 29, 1997, the City of Pittsburgh filed a federal antitrust
suit in the United States District Court for the Western District of
Pennsylvania, seeking to enjoin the proposed merger of the Company and AYE. The
City is also seeking unspecified monetary damages from the Company and AYE
arising from AYE's withdrawal of its proposal to provide power to two urban
redevelopment sites in Pittsburgh, both of which are within the Company's
electric service territory. On October 27, 1997, the Company filed a Motion to
Dismiss the City's suit.

Item 2. Changes in Securities

On July 30, 1997, DQE filed a Registration Statement on Form S-4 with the
SEC to begin the registration process for 1,000,000 shares of Series A Preferred
Stock, no par value. The issuance of Series A Preferred Stock was authorized by
a resolution of the DQE Board of Directors (the DQE Board) on July 29, 1997. As
of October 31, 1997, 11,720 shares of Series A Preferred Stock had been issued
and were outstanding.

The Series A Preferred Stock ranks senior to the Common Stock of DQE as to
the payment of dividends and as to the distribution of assets on liquidations,
dissolution or winding-up of DQE. The holders of Series A Preferred Stock are
entitled to vote on all matters submitted to a vote of the holders of Common
Stock, voting together with the holders of Common Stock as a single class.

Item 4. Submission of Matters to a Vote of Security Holders

The results of shareholder votes at DQE's August 7, 1997 Annual Meeting of
Stockholders were previously reported in DQE's Quarterly Report on Form 10-Q
filed with the SEC on August 14, 1997.

Item 6. Exhibits and Reports on Form 8-K

a. Exhibits:

EXHIBIT 3.1 - Statement with respect to the Preferred Stock, Series A
(Convertible), as filed with the Pennsylvania Department of
State on August 29, 1997.

EXHIBIT 27.1 - Financial Data Schedule

b. A Current Report on Form 8-K was filed July 28, 1997, to report the
Company's issuance of its earnings release for the quarter ended June 30,
1997. The release included the Company's (i) unaudited statement of income
for the three months ended June 30, 1997 and 1996, the six months ended
June 30, 1997 and 1996, and the twelve months ended December 31, 1997 and
1996, and (ii) unaudited balance sheet at June 30, 1997, and December 31,
1996.

A Current Report on Form 8-K was filed August 7, 1997, to report the
shareholders' approval of the Merger. No financial statements were
included with the filing.

______________________________

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, Inc.
--------------------
(Registrant)

Date November 13, 1997 /s/ Gary L. Schwass
----------------- --------------------------------
(Signature)
Gary L. Schwass
Executive Vice President
and Chief Financial Officer

Date November 13, 1997 /s/ Morgan K. O'Brien
----------------- ----------------------------------
(Signature)
Morgan K. O'Brien
Vice President and Controller
(Principal Accounting Officer)