DQE INC, 10-Q, 1997-08-14

DQE INC
10-Q, 1997-08-14
ELECTRIC SERVICES

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<PAGE>

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-Q

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

For the Quarterly Period Ended June 30, 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 - 77,408,557 shares outstanding as of June 30,
1997 and 77,604,495 shares outstanding as of July 31, 1997.
<PAGE>

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

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

<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------- ----------------------------
1997 1996 1997 1996
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Operating Revenues
Sales of Electricity:
Customers - net $250,522 $258,896 $514,540 $524,066
Utilities 6,289 15,077 15,020 31,042
------------ ------------ ----------- ------------
Total Sales of Electricity 256,811 273,973 529,560 555,108
Other 27,189 19,384 58,024 38,767
------------ ------------ ----------- ------------
Total Operating Revenues 284,000 293,357 587,584 593,875
------------ ------------ ----------- ------------

Operating Expenses
Fuel and purchased power 50,516 58,695 102,170 117,860
Other operating 76,881 71,744 158,513 142,175
Maintenance 22,551 18,864 40,300 39,368
Depreciation and amortization 58,546 55,827 113,720 112,808
Taxes other than income taxes 19,875 20,842 40,433 42,963
------------ ------------ ----------- ------------
Total Operating Expenses 228,369 225,972 455,136 455,174
------------ ------------ ----------- ------------

OPERATING INCOME 55,631 67,385 132,448 138,701
------------ ------------ ----------- ------------
OTHER INCOME 42,451 16,817 60,952 31,640
------------ ------------ ----------- ------------
INTEREST AND OTHER CHARGES 29,029 26,673 57,709 52,376
------------ ------------ ----------- ------------
INCOME BEFORE INCOME TAXES 69,053 57,529 135,691 117,965
INCOME TAXES 22,275 18,557 43,816 36,688
------------ ------------ ----------- ------------
NET INCOME $ 46,778 $ 38,972 $ 91,875 $ 81,277
============ ============ =========== ============

AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING
(Thousands of Shares) 77,394 77,392 77,341 77,490
============ ============ =========== ============

EARNINGS PER SHARE OF
COMMON STOCK $0.61 $0.50 $1.19 $1.05
============ ============ =========== ============

DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $0.34 $0.32 $0.68 $0.64
============ ============ =========== ============
</TABLE>

See notes to condensed consolidated financial statements.

2
<PAGE>

DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
June 30, December 31,
1997 1996
---------------- ----------------
<S> <C> <C>
ASSETS
Current assets:
Cash and temporary cash investments $ 344,144 $ 410,978
Receivables 110,274 130,125
Other current assets, principally materials and supplies 100,432 81,125
---------------- ----------------
Total current assets 554,850 622,228
---------------- ----------------
Long-term investments:
Affordable Housing 146,855 150,270
Leveraged leases 325,648 134,133
Other leases 77,803 85,893
Gas reserves 74,213 79,916
Other 76,518 68,477
---------------- ----------------
Total long-term investments 701,037 518,689
---------------- ----------------
Property, plant and equipment 4,747,557 4,787,470
Less: Accumulated depreciation and amortization (2,004,294) (1,969,945)
---------------- ----------------
Property, plant and equipment - net 2,743,263 2,817,525
---------------- ----------------
Other non-current assets:
Regulatory assets 605,334 636,816
Other 51,869 43,734
---------------- ----------------
Total other non-current assets 657,203 680,550
---------------- ----------------
TOTAL ASSETS $ 4,656,353 $ 4,638,992
================ ================
LIABILITIES AND CAPITALIZATION
Current liabilities:
Notes payable $ 38,000 $ 749
Current maturities and sinking fund requirements 140,252 72,831
Accounts payable 69,862 96,230
Accrued liabilities 25,252 58,044
Dividends declared 28,811 28,633
Other 1,404 4,075
---------------- ----------------
Total current liabilities 303,581 260,562
---------------- ----------------
Deferred income taxes - net 761,130 759,089
---------------- ----------------
Deferred investment tax credits 101,991 106,201
---------------- ----------------
Capital lease obligations 22,768 28,407
---------------- ----------------
Deferred income 174,913 189,293
---------------- ----------------
Other 278,476 240,763
---------------- ----------------
Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,356,364 1,439,746
---------------- ----------------
Preferred and preference stock of subsidiaries:
Non-redeemable preferred stock 213,608 213,608
Non-redeemable preference stock, Plan Series A 29,195 28,997
---------------- ----------------
Total preferred and preference stock before deferred
employee stock ownership plan (ESOP) benefit 242,803 242,605
Deferred ESOP benefit (18,565) (19,533)
---------------- ----------------
Total preferred and preference stock of subsidiaries 224,238 223,072
---------------- ----------------
Common shareholders' equity:
Common stock - no par value (authorized - 187,500,000 shares;
issued - 109,679,154 shares) 989,747 990,502
Retained earnings 816,890 777,607
Less treasury stock (at cost) (32,270,597 and 32,406,135
shares, respectively) (373,745) (376,250)
---------------- ----------------
Total common shareholders' equity 1,432,892 1,391,859
---------------- ----------------
Total capitalization 3,013,494 3,054,677
---------------- ----------------
TOTAL LIABILITIES AND CAPITALIZATION $ 4,656,353 $ 4,638,992
================ ================
</TABLE>
See notes to condensed consolidated financial statements.

3
<PAGE>

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

<TABLE>
<CAPTION>
Six Months Ended
June 30,
----------------------------
1997 1996
----------- -----------
<S> <C> <C>
Cash Flows From Operating Activities
Operations $ 219,600 $195,457
Changes in working capital other than cash (72,802) (54,726)
Other 3,810 (6,359)
----------- -----------
Net Cash Provided By Operating Activities 150,608 134,372
----------- -----------

Cash Flows From Investing Activities
Capital expenditures (42,975) (34,995)
Proceeds from the sale of equity securities 42,895 -
Long-term investments - net (192,088) (27,741)
Other 312 (1,728)
----------- -----------
Net Cash Used in Investing Activities (191,856) (64,464)
----------- -----------

Cash Flows From Financing Activities
Increase in notes payable 38,000 19,519
Issuance of preferred stock - 150,000
Dividends on common stock (52,592) (49,555)
Reductions of long term obligations - net (12,849) (58,668)
Repurchase of common stock - (11,717)
Other 1,855 (5,700)
----------- -----------
Net Cash (Used in) Provided by Financing Activities (25,586) 43,879
----------- -----------

Net (decrease) increase in cash and temporary cash investments (66,834) 113,787
Cash and temporary cash investments at beginning of period 410,978 24,767
----------- -----------
Cash and temporary cash investments at end of period $ 344,144 $138,554
=========== ===========

Non-Cash Investing Activities
Equity funding obligations recorded $ 17,491 $ 16,716
=========== ===========
</TABLE>
On May 1, 1997, DQE exchanged its shares in Chester Engineers for shares of
common stock which were subsequently sold at various dates through June 5,
1997.

See notes to condensed consolidated financial statements.

4
<PAGE>

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). 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 beneficial 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 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 dynamic energy services
industry. These alliances 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
provides financing for the Company's other market-driven businesses and their
customers.

On August 7, 1997, the shareholders of the Company and Allegheny Power
System (APS), approved a proposed tax-free, stock-for-stock merger. Upon
consummation of the merger, DQE will be a wholly owned subsidiary of Allegheny
Energy, Inc., which will be the combined company's name. 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 APS common stock for each share of the
Company's common stock, and APS'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 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 APS, 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 APS.

All material intercompany balances and transactions have been eliminated in
the preparation of the condensed consolidated financial statements.

5
<PAGE>

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. The results of operations for the three and six months ended
June 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 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 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 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 June 30, 1997, and December 31, 1996, are $4.6 million and $4.4 million,
respectively ($2.7 million and $2.6 million net of tax, respectively).

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 projections
do not support recovery of previously deferred costs 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.)

Statement of Financial Accounting Standards No. 130, Reporting
Comprehensive Income (SFAS No. 130) was issued in June 1997. SFAS No. 130
establishes standards for the reporting and display of comprehensive income and
its components (revenues, expenses, gains, and losses) in a full set of general-
purpose financial statements. SFAS No. 130 also requires that the Company (a)
classify items of other comprehensive income by their nature in a financial
statement and (b) display the accumulated balance of other comprehensive income
separately from retained earnings and additional paid-in-capital in the equity
section of a statement of financial position. SFAS No. 130 will be effective
for fiscal years beginning after December 15, 1997.

6
<PAGE>

Statement of Financial Accounting Standards No. 131, Disclosures About
Segments of an Enterprise and Related Information (SFAS 131) was also issued in
June 1997. SFAS No. 131 establishes standards for public business enterprises
to report information about operating segments in annual financial statements,
and requires that those enterprises report selected information about operating
segments in interim financial reports issued to shareholders. It also
establishes standards for related disclosures about such enterprises' products
and services, geographic areas of operation and major customers. SFAS No. 131
requires that the Company report a measure of segment profit or loss, certain
specific revenue and expense items, and segment assets. It requires that the
Company report descriptive information about how the operating segments were
determined, the products and services provided by the operating segments,
differences between the measurements used in reporting segment information and
those used in its general-purpose financial statements, and changes in the
measurement of segment amounts from period to period. SFAS No. 131 will be
effective for financial statements for periods beginning after December 15,
1997.

2. RECEIVABLES

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

<TABLE>
<CAPTION>
June 30, June 30, December 31,
1997 1996 1996
(Amounts in Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------

<S> <C> <C> <C>
Electric customer accounts receivable $ 88,314 $105,199 $ 92,475
Other utility receivables 15,738 14,611 22,402
Other receivables 26,324 31,396 33,936
Less: Allowance for uncollectible accounts (20,102) (21,338) (18,688)
- -------------------------------------------------------------------------------------------------------------
Total Receivables $110,274 $129,868 $130,125
=============================================================================================================
</TABLE>

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 June 30, 1997, 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

7
<PAGE>

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 Plan with the PUC, setting forth its plan to enable customers to
choose their electric generation supplier (Restructuring Plan).

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.

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 material
to the financial position of the Company.

8
<PAGE>

The Company's regulatory assets related to generation, transmission, and
distribution as of June 30, 1997, were $468.3 million, $39.2 million and $97.8
million, respectively. The components of all regulatory assets for the periods
presented are as follows:

<TABLE>
<CAPTION>
June 30, December 31,
1997 1996
(Amounts in Thousands of Dollars)
- -----------------------------------------------------------------------------------------
<S> <C> <C>
Regulatory tax receivable $370,420 $394,131
Unamortized debt costs (a) 90,586 93,299
Deferred rate synchronization costs 39,339 41,446
Beaver Valley Unit 2 sale/leaseback premium (b) 29,306 30,059
Deferred employee costs (c) 27,970 29,589
Deferred nuclear maintenance outage costs 4,988 13,462
Deferred coal costs (see below) 13,860 12,191
DOE decontamination and decommissioning receivable 9,315 9,779
Other 19,550 12,860
- -----------------------------------------------------------------------------------------
Total Regulatory Assets $605,334 $636,816
=========================================================================================
</TABLE>
(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.

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 $11.3 million and $9.6 million at June 30, 1997
and December 31, 1996. The unrecovered cost of the remainder of the system-wide
coal was $2.6 million at June 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. The Company expects to recover its investment
in BI Units 3 and 4, which remain in property held for future use through future
electricity sales. The Company believes its investment in BI will be necessary
in order to meet future business needs. Reliability enhancements at BI are
contingent upon the projects meeting a least-cost test versus other potential
sources of peaking capacity. The

9
<PAGE>

Company is analyzing the effects of customer choice on its future generating
requirements. The Company is seeking recovery of its investment and associated
costs of Phillips through a CTC. 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 June 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 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 site-specific studies finalized in 1997 for BV Unit 1, BV Unit 2
and 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.

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. Guidelines
require that 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.

10
<PAGE>

The annual contributions to the decommissioning funds 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 June 30, 1997, totaled approximately $40.3 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 $3.5 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 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.

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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, which are anticipated to begin
in September 1997 for BV Unit 1 and in March 1998 for BV Unit 2. 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 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 to 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. 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 June 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.

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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. This amount for fossil decommissioning
is currently estimated to be $130 million for 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 its Restructuring Plan.

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 June 30, 1997, the Company's share of these guarantees was $16.0
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 $18.4 million at June 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.

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Employees

In November 1996, the Company reached an agreement on a three-year contract
extension through September 30, 2001, with the International Brotherhood of
Electrical Workers, which represents approximately 2,000 of the Company's
employees. The contract extension provides, among other things, for a three-
year 3% annual wage increase, employment security and income protection, and an
early retirement program for certain 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.

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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 14 in Part I, Item 1 of
this Report.

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

On August 7, 1997, the shareholders of the Company and Allegheny Power
System, Inc. (APS), approved a proposed tax-free, stock-for-stock merger. Upon
consummation of the merger, the Company will be a wholly owned subsidiary of
Allegheny Energy, Inc. (Allegheny Energy), which will be the combined company's
name. 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 20.)

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. 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.

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<PAGE>

Regulation

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 21.)

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 21.)
Members of the Emerging Issues Task Force of the Financial Accounting Standards
Board (the "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 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).

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<PAGE>

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
- --------------------------------------------------------------------------------

Sales of Electricity to Customers

The decrease in the second quarter of 1997 total operating revenues was
$9.4 million or 3.2 percent, as compared to the second quarter of 1996. Total
operating revenues decreased $6.3 million or 1.1 percent, when comparing the six
months ended June 30, 1997, to the six months ended June 30, 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 16 and 21.)

Sales to residential and commercial customers are strongly 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.

Net Customer Revenues

Net customer revenues, reflected on the statement of consolidated income,
decreased $8.4 million or 3.2 percent in the second quarter of 1997, as compared
to the same period in 1996. The variance can be attributed primarily to
decreased residential and commercial customer kilowatt-hour (KWH) sales of 6.2
percent and 3.9 percent, respectively, due to mild second quarter 1997
temperatures, as compared to 1996, resulting in decreased revenues of $5.1
million and $4.9 million, respectively. Due to the mild temperatures, fuel
volume was down from the second quarter of 1996 by 12.1 percent. Industrial
sales increased 10.4 percent as compared to the second quarter of 1996 resulting
in increased industrial revenues of $1.7 million, primarily due to a major
customer's expansion, outages experienced by that customer in the second quarter
of 1996, and significant electricity consumed by a new customer. The remainder
of the increase in electric demand is the result of improved business for other
industrial customers.

In the six months ended June 30, 1997, as compared to the six months ended
June 30, 1996, net customer revenues decreased $9.5 million or 1.8 percent.
Reduced residential customer KWH sales of 4.1 percent due to mild temperatures,
as compared to 1996, resulted in a $6.2 million decrease in residential customer
revenues. Due to the mild temperatures, fuel volume was down from the first six
months of 1996 by 10.3 percent. Industrial sales for the six months ended June
30, 1997, increased 5.9 percent, as compared to the six months ended June 30,
1996 resulting in a $2.1 million increase in industrial revenues. The increase
is the result of improved business for several of the Company's largest
industrial customers.

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<PAGE>

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 second
quarter of 1997 were $8.8 million less than in the second quarter of 1996. In a
comparison of the six months ended June 30, 1997, to the six months ended June
30, 1996, sales to other utilities decreased $16.0 million. The fluctuations
were due to a decline in demand from other utilities and reduced availability as
a result of the sale of the Company's 50 percent interest in the Ft. Martin
Power Station (Ft. Martin). Future levels of short-term sales to other
utilities will be affected by the possible sale of other generating stations,
market rates, and by the outcome of the Company's FERC filings requesting firm
transmission access. (See "Outlook" discussion on page 20.)

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
increases of $7.8 million or 40.3 percent when comparing the second quarter of
1997 and 1996 and $19.3 million or 49.7 percent when comparing the six months
ended June 30, 1997, to the six months ended June 30, 1996, are primarily due to
revenues of an investment made in the fourth quarter of 1996. These increases
were partially offset by reduced revenues attributable to the sale of Chester
Engineers, Inc. (Chester) in the second quarter of 1997.

Operating Expenses

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 Energy Cost Rate
Adjustment Clause (ECR), changes in fuel and purchased power costs did not
impact earnings in the second quarter of 1997 and 1996 or in the six months
ended June 30, 1997 and 1996.

Fuel and purchased power expense decreased $8.2 million or 13.9 percent in the
second quarter of 1997, as compared to the second quarter of 1996, and decreased
$15.7 million or 13.3 percent for the six months ended June 30, 1997, as
compared to the same period in 1996. These decreases in purchased power
and fossil fuel volume were the result of reduced residential and commercial
consumption due to mild 1997 temperatures. These decreases were partially offset
by increased fuel prices and purchased power prices.

Other operating expense increased $5.1 million or 7.1 percent when comparing
the second quarter of 1997 and 1996, and increased $16.3 million or 11.5 percent
when comparing the first six months of 1997 and 1996. The increases were
primarily the result of operating costs associated with an investment made in
the fourth quarter of 1996.

In comparing the second quarter of 1997 to the second quarter of 1996,
maintenance expense increased $3.7 million or 19.5 percent. During the second
quarter of 1997 there were approximately 75 percent more generating station
outage-days than in the second quarter of 1996. In the first six months of 1997
compared to the first six months of 1996, maintenance expense increased $0.9
million or 2.4 percent. There were approximately 12 percent more generating
station outage-days in the first six months of 1997 than in the same period in
1996.

In the second quarter of 1997, depreciation and amortization expense increased
$2.7 million or 4.9 percent as compared to the second quarter of 1996. There
was a $0.9 million or 0.8 percent increase in the six months ended June 30,
1997, when compared to the same period in 1996. The increases are the result of
increased nuclear fixed cost recovery in the second quarter of 1997, as well as
increased funding of the nuclear decommissioning trust, in accordance with the
PUC-approved

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<PAGE>

Ft. Martin sale. The increase is partially offset due to the full recovery of
Perry Unit 2 abandonment costs during the third quarter of 1996.

Other Income

Comparing the second quarter of 1997 to the second quarter of 1996 and the six
months ended June 30, 1997, to the six months ended June 30, 1996, increases of
$25.6 million and $29.3 million in other income were partially the result of the
sale of Chester. A 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

There was an increase of $2.4 million or 8.8 percent in interest and other
charges during the second quarter of 1997 as compared to the second quarter of
1996. In comparing the six months ended June 30, 1997, with the six months
ended June 30, 1996, there was a $5.3 million or 10.2 percent increase in
interest and other charges. The reason for the increases was primarily the
result of paying two full quarters of dividends in 1997 related to Monthly
Income Preferred Securities (MIPS) issued in May 1996.

Income Taxes

Income taxes increased in the second quarter of 1997 and the first six months
of 1997 as compared to the same periods in 1996 by $3.7 million and $7.1
million. The 20.0 and 19.4 percent increases in income taxes can be attributed
to increased taxable income primarily due to the gain on the sale of Chester
which was recognized in the second quarter of 1997.

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

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 June 30, 1997, the Company was in compliance with all of its
debt covenants.

Mortgage bonds in the amounts 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
$50.0 million of accounts receivable. During the second quarter, the $50.0
million accounts receivable sale arrangement was extended through June 1998. The
Company may attempt to extend the agreement, or replace it with a similar
facility, or eliminate the agreement, upon expiration.

At June 30, 1997, the Company had a $150 million revolving credit facility
expiring in October 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 commitments. The credit facility contains a two-year repayment
period for any amounts outstanding at the expiration of the revolving credit
period. At June 30, 1997, there

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<PAGE>

were $38.0 million in borrowings outstanding. The weighted average interest rate
applied to such borrowings was 6.1 percent. At June 30, 1996, there were no
short-term borrowings outstanding.

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

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 six months of 1997 included
approximately $167.7 million in lease investments, $10.6 million in affordable
housing investments, $3.0 million in natural gas reserve partnerships and the
remaining $14.1 million in other investments. During the first six months of
1996, the Company invested approximately $38.0 million in lease investments,
$8.6 million in affordable housing investments and $10.4 million in natural gas
reserve partnerships. During the first six months of 1997, the Company also had
long-term sales primarily of gas reserve partnerships totaling $3.3 million. The
Company had long-term sales primarily of leveraged lease investments totaling
$17.4 million during the first six months of 1996.

On May 1, 1997, the Company completed the sale of Chester in accordance
with the terms of a sale agreement entered into on March 18, 1997. Pursuant to
this transaction, the Company received shares of common stock, all of which have
since been sold for aggregate proceeds of approximately $44 million.

On May 28, 1997, the Company acquired 9.2 percent of the common stock of
SatCon Technology Corporation (SatCon) for $5 million. The shares were acquired
as a long-term investment and as part of the formation of a strategic
partnership between DE and SatCon to commercialize flywheel energy storage
system technology for stationary power applications.

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

Proposed Merger

On August 1, 1997, the Company, Duquesne and APS filed applications
outlining their restructuring and merger plans with the FERC, the PUC and the
Maryland Public Service Commission, asking the necessary approvals to form
Allegheny Energy. Also on August 1, 1997, Duquesne filed an application with
the NRC for approval of the indirect transfer of licenses from Duquesne to
Allegheny Energy. Additional filings related to the merger will be made with
other federal agencies, including the SEC, the Department of Justice and the
Federal Trade Commission. Affiliated interest filings related to restructuring
will be made by APS with the Virginia State Corporation Commission and the
Public Service Commission of West Virginia. The Company cannot predict the
outcome of any of these filings.

On August 7, 1997, the shareholders of the Company and APS approved a
proposed tax-free, stock-for-stock merger. Upon consummation of the merger, DQE
will be a wholly owned subsidiary of Allegheny Energy. 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 APS common stock for each share of the
Company's common stock, and APS'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,

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<PAGE>

and the Joint Proxy Statement/Prospectus of the Company and APS, 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
APS.

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. Customers participating in the
pilot were to have two basic options. First, customers could choose to continue
taking bundled service from Duquesne under approved tariffs. Second, customers
could choose unbundled service with their electricity provided by an alternative
electric generation supplier. All customers choosing unbundled electric service
were to be subject to unbundled distribution charges approved by the PUC and
unbundled transmission charges pursuant to Duquesne's FERC-approved tariff. Each
customer electing unbundled service also would 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. On May 22, 1997, the Company
submitted comments on the PUC's preliminary order. The Company and other
utilities have objected to several features of the PUC's preliminary order. The
PUC anticipates issuing a final order on August 28, 1997, and a revised pilot
program must be filed within 30 days of such order. The revised pilot program
is now expected to begin in December 1997.

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

21
<PAGE>

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 plan (the Restructuring
Plan) with the PUC. The Company anticipates a decision by the PUC on or before
April 30, 1998. The Restructuring Plan uses 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

22
<PAGE>

exceed expectations or additional cost savings are available, the Company has
established a return on equity "spillover" mechanism that will ensure that the
related revenues are used to further mitigate stranded costs. Finally, the
Restructuring Plan redesigns 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.

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 "Regulation" discussion on page 16.) 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.

23
<PAGE>

In addition to the Restructuring Plan, on August 1, 1997, the Company and
APS filed their joint merger application with the FERC (the FERC Filing).
Pursuant to the FERC Filing, the Company and APS have committed to forming or
joining an independent system operator (ISO) which meets their requirements
following the merger. In addition, the Company and APS 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.

24
<PAGE>

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.

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.

25
<PAGE>

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. Since April 1997, the parties have been engaged in
settlement discussions.

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 August 13, 1997, no shares of Series A Preferred Stock had ever been issued
or were outstanding.

When issued, the Series A Preferred Stock will rank 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 will be 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. Each share of Series A Preferred Stock will be entitled to
three votes. Shares of Series A Preferred Stock are mandatorily redeemable at
the beginning of the first month following the sixth anniversary of issuance;
the redemption price is $100 per share, plus all accrued and unpaid dividends.

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

a. On August 7, 1997, DQE held its 1997 Annual Meeting of Stockholders.

b. Proxies for the Annual Meeting were solicited pursuant to Regulation 14
under the Securities and Exchange Act of 1934, as amended. There was no
solicitation in opposition to management's nominees for directors as listed
in the proxy statement dated June 25, 1997, and all nominees were elected.

26
<PAGE>

c. Five proposals were submitted to stockholders for a vote at the Annual
Meeting.

Proposal 1 was the adoption of the Agreement and Plan of Merger among DQE,
APS and AYP Sub, Inc. ("Merger Sub"), pursuant to which Merger Sub (to be
formed as a wholly-owned subsidiary of APS) will be merged with and into
DQE and DQE will become a wholly-owned subsidiary of APS, and to approve
the transactions provided for therein. The vote on this proposal was as
follows:

For 59,831,134 Against 664,644 Abstain 582,226
---------- ------- -------

Broker Non-Votes 9,134,899
---------

Proposal 2 was to amend the Restated Articles of Incorporation of DQE to
make (S)(S) 2541-2548 of the Pennsylvania Business Corporation Law
inapplicable to DQE. The vote on this proposal was as follows:

For 59,424,341 Against 741,998 Abstain 971,617
---------- ------- -------

Broker Non-Votes 9,076,640
---------

Proposal 3 was the election of four directors to the Board of Directors to
serve until the 2000 Annual Meeting and until their respective successors
have been chosen and qualified. The vote on this proposal was as follows:
<TABLE>
<CAPTION>
Broker
Nominee For Withheld Non-Votes
- ------- --- --------- ---------
<S> <C> <C> <C>

Daniel Berg 66,002,126 1,012,986 3,150,597
---------- --------- ---------
Robert P. Bozzone 66,232,509 1,012,986 3,127,736
---------- --------- ---------
William H. Knoell 65,881,942 1,012,986 3,180,284
---------- --------- ---------
Thomas J. Murrin 66,026,503 1,012,986 3,137,859
---------- --------- ---------
</TABLE>

The following Directors terms continue after the Annual Meeting of
Stockholders: until 1998 - Doreen E. Boyce, David D. Marshall and Robert
Mehrabian; until 1999 - Sigo Falk and Eric W. Springer.

Proposal 4 was the ratification of the appointment, by the Board of
Directors, of Deloitte & Touche LLP as independent public accountants to
audit the books of the Company for the year ending December 31, 1997. The
vote on this proposal was as follows:

For 65,869,517 Against 536,818 Abstain 614,325
---------- ------- -------

Broker Non-Votes 3,151,643
---------

Proposal 5 was a proposal from a stockholder to cause the Board of
Directors to take action to consider amending the DQE Restated Articles of
Incorporation to eliminate three year Director terms and set a one year
Director term. The vote on this proposal was as follows:

For 20,967,331 Against 37,195,404 Abstain 2,904,360
---------- ---------- ---------

Broker Non-Votes 9,143,087
---------

27
<PAGE>

Item 6. Exhibits and Reports on Form 8-K

a. Exhibits:

EXHIBIT 10.1 - Securities Purchase Agreement, dated as of May 28, 1997, among
SatCon, Beacon Power Corporation and DE (included as Exhibit A
to DE's Schedule 13D filed with the SEC on June 9, 1997, and
incorporated herein by reference).

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.

______________________________

28
<PAGE>

SIGNATURES

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

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

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

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

<PAGE>

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