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[CONFORMED]
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 1996
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[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From to
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Commission File Number
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1-10290
DQE, Inc.
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-1598483
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Cherrington Corporate Center, Suite 100
500 Cherrington Parkway, Coraopolis, Pennsylvania 15108-3184
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 262-4700
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such report), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
DQE Common Stock, no par value - 77,612,236 shares outstanding as of March 31,
1996 and 77,540,786 shares outstanding as of April 30, 1996.
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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
March 31,
--------------------
1996 1995
--------- ---------
<S> <C> <C>
Operating Revenues:
Sales of Electricity:
Customers-net $265,170 $263,144
Utilities 15,965 12,489
-------- --------
Total Sales of Electricity 281,135 275,633
Other 19,383 22,644
-------- --------
Total Operating Revenues 300,518 298,277
-------- --------
Operating Expenses:
Fuel and purchased power 59,165 55,100
Other operating 70,431 73,096
Maintenance 20,504 18,830
Depreciation and amortization 56,981 48,774
Taxes other than income taxes 22,121 21,870
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Total Operating Expenses 229,202 217,670
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OPERATING INCOME 71,316 80,607
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OTHER INCOME 14,823 15,629
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INTEREST AND OTHER CHARGES 25,703 27,669
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INCOME BEFORE INCOME TAXES 60,436 68,567
Income Taxes 18,131 27,666
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NET INCOME $ 42,305 $ 40,901
======== ========
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING
(Thousands of Shares) 77,588 78,063
======== ========
EARNINGS PER SHARE OF COMMON
STOCK $0.55 $0.52
======== ========
DIVIDENDS DECLARED PER SHARE
OF COMMON STOCK $0.32 $0.29
======== ========
</TABLE>
See notes to condensed consolidated financial statements.
2
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DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1996 1995
------------ -------------
<S> <C> <C>
ASSETS:
Current Assets:
Cash and temporary cash investments $ 55,430 $ 24,767
Receivables 130,185 125,768
Other current assets, principally
materials and supplies 110,755 86,851
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Total Current Assets 296,370 237,386
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Long-term Investments 416,631 440,916
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Property, Plant and Equipment 4,724,997 4,746,113
Less Accumulated Depreciation and Amortization (1,686,266) (1,685,877)
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Property, Plant and Equipment - Net 3,038,731 3,060,236
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Other Non-current Assets:
Regulatory assets 655,883 671,928
Other 50,806 48,377
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Total Other Non-current Assets 706,689 720,305
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TOTAL ASSETS $ 4,458,421 $ 4,458,843
=========== ===========
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable $ 11,086 $ 35,098
Current maturities and sinking fund
requirements 72,156 71,379
Accounts payable 78,505 90,941
Accrued liabilities 82,838 52,063
Dividends declared 27,292 27,825
Other 12,481 9,191
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Total Current Liabilities 284,358 286,497
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Deferred Income Taxes - Net 807,440 801,631
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Deferred Investment Tax Credits 110,203 115,760
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Capital Lease Obligations 36,303 34,546
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Deferred Income 211,202 221,740
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Other 190,493 197,973
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Commitments and Contingencies (Note 5)
Capitalization:
Long-term Debt 1,405,895 1,400,993
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Preferred and Preference Stock of Subsidiaries:
Non-redeemable preferred stock 63,608 63,608
Non-redeemable preference stock, Plan Series A 29,407 29,615
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Total preferred and preference stock
before deferred employee stock ownership
plan (ESOP) benefit (involuntary liquidation
values of $92,878 and $93,086 exceed par by
$28,579 and$28,781, respectively) 93,015 93,223
Deferred ESOP benefit (21,634) (22,257)
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Total Preferred and Preference
Stock of Subsidiaries 71,381 70,966
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Common Shareholders' Equity:
Common stock-no par value
(authorized - 187,500,000 shares;
issued - 109,679,154 shares) 991,264 997,461
Retained earnings 716,455 698,986
Less treasury stock (at cost) (32,066,918
and 32,123,601 shares, respectively) (366,573) (367,710)
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Total Common Shareholders' Equity 1,341,146 1,328,737
----------- -----------
Total Capitalization 2,818,422 2,800,696
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TOTAL LIABILITIES AND CAPITALIZATION $ 4,458,421 $ 4,458,843
=========== ===========
</TABLE>
See notes to condensed consolidated financial statements.
3
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DQE
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
------------------
1996 1995
-------- --------
<S> <C> <C>
Cash Flows from Operating Activities:
Operations $ 96,706 $ 88,575
Changes in working capital other than cash (7,226) 34,596
Other - net (4,896) (5,930)
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Net Cash Provided from Operating Activities 84,584 117,241
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Cash Flows Used by Investing Activities:
Capital expenditures (18,539) (12,447)
Long-term investments 17,418 (9,194)
Other - net (979) (1,388)
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Net Cash Used by Investing Activities (2,100) (23,029)
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Cash Flows Used in Financing Activities:
Decrease in notes payable (19,073) (10,000)
Dividends on common stock (24,835) (22,820)
Reductions of long-term obligations (net) (4,495) (4,372)
Repurchase of common stock -- (18,538)
Other - net (3,418) (567)
-------- --------
Net Cash Used in Financing Activities (51,821) (56,297)
-------- --------
Net increase in cash and temporary cash investments 30,663 37,915
Cash and temporary cash investments at 24,767 50,058
beginning of period -------- --------
Cash and temporary cash investments at end of period $ 55,430 $ 87,973
======== ========
</TABLE>
See notes to condensed consolidated financial statements.
4
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q, are forward-looking statements that involve
risks and uncertainties including, but not limited to, economic, competitive,
governmental and technological factors affecting DQE and 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.
1. CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES
DQE is an energy services holding company. Its subsidiaries are Duquesne
Light Company (Duquesne), Duquesne Enterprises (DE), DQE Energy Services (DES)
and Montauk. DQE and its subsidiaries are collectively referred to as the
Company.
Duquesne is an electric utility engaged in the production, transmission,
distribution and sale of electric energy, and is the largest of DQE's
subsidiaries. DE makes strategic investments related to DQE's core energy
business. These investments enhance DQE's capabilities as an energy provider,
increase asset utilization, and act as a hedge against changing business
conditions. DES was formed in August 1995 and is a marketing and development
company providing energy solutions for customers in domestic and international
markets. Montauk is a financial services company that makes long-term
investments and provides financing for the Company's initiatives at DE and DES.
All material intercompany balances and transactions have been eliminated in
the preparation of the condensed consolidated financial statements of DQE.
In the opinion of management, the unaudited condensed consolidated
financial statements included in this report reflect all adjustments that are
necessary for a fair presentation of the results of interim periods, and are
normal, recurring adjustments. Prior period financial statements were
reclassified to conform with the 1996 presentation.
These statements should be read with the financial statements and notes
included in the Form 10-K, Annual Report, filed with the Securities and Exchange
Commission (SEC) for the year ended December 31, 1995. The results of operations
for the three months ended March 31, 1996, are not necessarily indicative of the
results that may be expected for the full year. The preparation of financial
statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements. The reported amounts of revenues and
expenses during the reporting period may also be affected by the estimates and
assumptions management is required to make. Actual results could differ from
those estimates.
The Company is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to the
regulation of the Pennsylvania Public Utility Commission (PUC) and the Federal
Energy Regulatory Commission (FERC). As a result, the consolidated financial
statements contain regulatory assets and liabilities in accordance with
Statement of Financial Accounting Standards No. 71, Accounting for the Effects
of Certain Types of Regulation (SFAS No. 71) and reflect the effects of the
ratemaking process. Such effects concern mainly the time at which various items
5
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enter into the determination of net income in accordance with the principle of
matching costs and revenues. (See "Rate Matters," Note 4, 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 March 31, 1996, and December 31, 1995, are $5.9 million and $4.4 million,
respectively. Reduced for deferred income taxes, net unrealized holding losses
on investments are $3.5 million and $2.6 million at March 31, 1996, and December
31, 1995, respectively.
2. STOCK SPLIT
On April 19, 1995, the Board of Directors of DQE declared a three-for-two
stock split for shareholders of record May 1, 1995. One additional share of
common stock was issued for every two shares outstanding as of the record date.
All references in the condensed consolidated financial statements as to issued
and outstanding shares and per share amounts have been restated to reflect the
stock split. The Company increased the quarterly dividend from $.30 to $.32 per
share on the post-split shares effective with the dividend paid January 1,
1996. The Board plans to continue its past practice of reviewing the dividend
quarterly.
3. RECEIVABLES
Components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
March 31, March 31, December 31,
1996 1995 1995
(Amounts in Thousands of Dollars)
<S> <C> <C> <C>
- - -------------------------------------------------------------------------------------------------------------
Electric customer accounts receivable $103,263 $ 94,523 $103,821
Other utility receivable 16,258 25,430 22,441
Other receivables 31,004 50,967 25,164
Less: Allowance for uncollectible accounts (20,340) (16,456) (18,658)
- - -------------------------------------------------------------------------------------------------------------
Receivables less allowance for uncollectible
accounts 130,185 154,464 132,768
Less: Receivables sold -- -- (7,000)
- - -------------------------------------------------------------------------------------------------------------
Total Receivables $130,185 $154,464 $125,768
=============================================================================================================
</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 million of accounts receivable. At March 31, 1996 and 1995, the Company had
no receivables sold to the unaffiliated corporation. At December 31, 1995, the
Company had sold $7 million of receivables to the unaffiliated corporation. The
accounts receivable sales agreement, which expires in June 1996, is one of many
sources of funds available to the Company. The Company may attempt to extend
the agreement, or to replace the facility with a similar one or to eliminate it
upon expiration.
6
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4. RATE MATTERS
At this time, the Company has no pending base rate case and has no
immediate plans to file a base rate case. In the Company's amended petition
currently before the PUC for the sale of its ownership interest in the Ft.
Martin Power Station, the Company proposes to freeze its base rates for a five-
year period. (See "Sale of Ft. Martin" discussion on page 8.)
Regulatory Assets
As a result of the application of SFAS No. 71, the Company records
regulatory assets on its consolidated balance sheet. The regulatory assets
represent probable future revenue to the Company because provisions for these
costs are currently included, or are expected to be included, in charges to
electric utility customers through the ratemaking process.
The Company's electric utility operations currently satisfy the SFAS No. 71
criteria. However, a company's electric utility operations or a portion of such
operations could cease to meet these criteria for various reasons, including a
change in the PUC or the FERC regulations. Should the Company's electric utility
operations cease to meet the SFAS No. 71 criteria, the Company would be required
to write off any regulatory assets or liabilities for those operations that no
longer meet these requirements. Management will continue to evaluate significant
changes in the regulatory and competitive environment in order to assess the
Company's overall consistency with the criteria of SFAS No. 71.
The components of regulatory assets for the periods presented are as
follows:
<TABLE>
<CAPTION>
March 31, December 31,
1996 1995
(Amounts in Thousands of Dollars)
- - ---------------------------------------------------------------------------
<S> <C> <C>
Regulatory tax receivable $411,165 $414,543
Unamortized debt costs (a) 97,382 98,776
Deferred rate synchronization costs 43,449 51,149
(see page 8)
Beaver Valley Unit 2 sale/leaseback 31,187 31,564
premium (b)
Deferred employee costs (c) 28,628 31,218
Extraordinary property loss 4,546 8,300
Deferred nuclear maintenance outage 10,465 6,776
costs
DOE decontamination and decommissioning 10,461 10,687
receivable
Deferred coal costs 12,759 12,753
Other 5,841 6,162
- - ---------------------------------------------------------------------------
Total Regulatory Assets $655,883 $671,928
===========================================================================
</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.
With respect to the financial statement presentation of Statement of
Financial Accounting Standards No. 109, Accounting for Income Taxes, the Company
reflects the amortization of the regulatory tax receivable resulting from
reversals of deferred taxes as depreciation and amortization expense. Reversals
of deferred income taxes - net are included in income taxes.
7
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Deferred Rate Synchronization Costs
In 1987, the PUC approved the Company's petition to defer initial operating
and other costs of Perry Unit 1 and Beaver Valley Unit 2 (BV Unit 2). The
Company deferred the costs incurred from the date the units went into commercial
operation, until the date a rate order was issued. In its rate order, the PUC
postponed ruling on whether these costs would be recoverable from the Company's
electric utility customers. The Company is not earning a return on the deferred
costs. The Company believes that these deferred costs are recoverable. In 1990
and 1995, the PUC permitted other Pennsylvania electric utilities rate recovery
of such costs.
As a result of negotiations with the sole intervenor in proceeding before
the PUC related to the Company's plan for the sale of its ownership interest in
the Ft. Martin Power Station, the Company agreed to charge off $9.0 million
related to the depreciation portion of deferred rate synchronization costs. The
Company has recorded a $7.7 million write-off of deferred rate synchronization
costs in the first quarter of 1996. (See "Sale of Ft. Martin" discussion,
below.) The Company's amended petition currently under consideration by the PUC
also proposes to amortize the remaining $42.1 million of deferred rate
synchronization costs over a ten-year period.
Property Held for Future Use
In 1986, the PUC approved the Company's request to remove Phillips Power
Station (Phillips) and a portion of Brunot Island Power Station (BI) from
service and from rate base. The Company expects to recover its net investment in
these plants through future electricity sales. The Company believes its
investment in these plants will be necessary in order to meet future business
needs outlined in the Company's plans for optimizing generation resources. If
business opportunities do not develop as expected, the Company will consider the
sale of these assets. In the event that market demand, transmission access or
rate recovery do not support the utilization or sale of the plants, the Company
may have to write off part or all of their costs. A portion of the BI combustion
turbine capacity currently held for future use may be returned to service
pending the outcome of the sale of the Company's ownership interest in the Ft.
Martin Power Station. (See "Sale of Ft. Martin" discussion, below.) At March
31, 1996, the Company's net investment in Phillips and BI held for future use
was $78.3 million and $44.9 million, respectively.
Sale of Ft. Martin
In December 1995, the Company filed a Petition for Declaratory Order with
the PUC requesting approval for the sale of its ownership interest in the Ft.
Martin Power Station and for a six-point plan to be financed in part by the
proceeds of the Ft. Martin transaction. Under the plan, the Company offers to
freeze its base rates for a period of five years. In addition, the Company
proposes to record a one-time reduction of approximately $130 million in the
value of the Company's nuclear plant investment. The Company also proposes to
use the proceeds from the sale to finance reliability enhancements to the simple
cycle units located at BI, to retire debt and to reduce equity. The plan also
proposes an annual increase of $25 million for three years in depreciation and
amortization expense related to the Company's nuclear investment, as well as
additional annual contributions to its nuclear plant decommissioning funds of $5
million for five years, without any increase in existing electric rates. Lastly,
the Company proposes a five-year annual $5 million credit to the Energy Cost
Rate Adjustment Clause (ECR) to compensate the Company's electric utility
customers for the lost profits from any reduced short-term power sales foregone
by the sale of its ownership interest in the Ft. Martin Power Station.
In April 1996, the Company filed an Amendment to Petition for Declaratory
Order (the Amendment). The Amendment resulted from negotiations with the Office
of Consumer Advocate, the sole intervenor in this proceeding. The Amendment
adds the following three proposals to the original six-point plan for the sale
of the Company's ownership interest in the Ft. Martin Power Station
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(discussed in the preceding paragraph). In addition to the original annual
credit of $5 million to the ECR, the Company proposes to cap energy costs
beginning April 1, 1997, through the remainder of the plan period, at the
historical five-year average of 14.7 mils per kilowatt hour. Second, the Company
agrees to charge off $9 million related to the depreciation portion of the $51.1
million of deferred rate synchronization costs associated with BV Unit 2 and
Perry Unit 1. Thereafter, the Company proposes to amortize the remaining $42.1
million of deferred rate synchronization costs over a ten-year period. Finally,
the Company proposes to contribute $.5 million annually to a supplemental low-
income customer assistance program. This bill payment program, which is also
subject to PUC approval, will be designed to provide financial assistance to
low-income electric customers. The PUC is currently reviewing the Company's
amended petition.
5. COMMITMENTS AND CONTINGENCIES
Construction
The Company estimates that it will spend, excluding Allowance for Funds
Used During Construction (AFC) and nuclear fuel, approximately $90 million on
electric utility construction during 1996. Approximately $5 million of capital
expenditures for the reliability enhancements to the simple cycle units located
at BI contemplated in the Company's amended petition before the PUC are excluded
from this estimate. (See "Sale of Ft. Martin" discussion on page 8.)
Nuclear-Related Matters
The Company operates two nuclear units and has an ownership interest in a
third. The operation of a nuclear facility involves special risks, potential
liabilities and specific regulatory and safety requirements. Specific
information about risk management and potential liabilities is discussed below.
Nuclear Decommissioning. The PUC ruled that recovery of the
decommissioning costs for Beaver Valley Unit 1 (BV Unit 1) could begin in 1977,
and that recovery for BV Unit 2 and Perry Unit 1 could begin in 1988. The
Company expects to decommission BV Unit 1, BV Unit 2 and Perry Unit 1 no earlier
than the expiration of each plant's operating license, 2016, 2027 and 2026,
respectively. BV Unit 1 will be placed in safe storage until the expiration of
the BV Unit 2 operating license, at which time the units may be decommissioned
together.
Based on site-specific studies finalized in 1992 for BV Unit 2, and in 1994
for BV Unit 1 and Perry Unit 1, the Company's share of the total estimated
decommissioning costs, including removal and decontamination costs, currently
being used to determine the Company's cost of service, are $122 million for BV
Unit 1, $35 million for BV Unit 2 and $67 million for Perry Unit 1.
In conjunction with an August 18, 1994, PUC Accounting Order, the Company
has increased the annual contribution to its decommissioning trusts by
approximately $2 million, to bring the total annual funding to approximately $4
million per year. In collaboration with the Company and several other
Pennsylvania utilities, the PUC Office of Special Assistants is evaluating
various decommissioning issues, including funding methods. The Company expects
that any action relating to any forthcoming PUC report will result in further
increases in annual contributions to its decommissioning trusts. Consistent
with these anticipated future PUC actions, the Company's amended petition before
the PUC for the sale of its ownership interest in the
9
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Ft. Martin Power Station provides for additional annual contributions to its
nuclear decommissioning funds of $5 million for five years without any increase
in existing electric utility rates. (See "Sale of Ft. Martin" discussion on
page 8.)
The Company records decommissioning costs under the category of
depreciation and amortization expense and accrues a liability, equal to that
amount for nuclear decommissioning expense. Such nuclear decommissioning funds
are deposited in external, segregated trust accounts. The funds are invested in
a portfolio of municipal bonds, certificates of deposit and United States
government securities having a weighted average duration of four to seven years.
Trust fund earnings increase the fund balance and the recorded liability. The
market value of the aggregate trust fund balances at March 31, 1996, totaled
approximately $29.0 million. On the Company's consolidated balance sheet, the
decommissioning trusts have been reflected in long-term investments, and the
related liability has been recorded as other non-current liabilities.
Nuclear Insurance. All of the companies with an interest in BV Unit 1, BV
Unit 2 and Perry Unit 1 maintain nuclear property insurance, which provides
coverage for property damage, decommissioning and decontamination liabilities.
The Company's share of this program provides for $1.2 billion of insurance
coverage for its net investment of $400.0 million in the Beaver Valley Power
Station (BVPS) and $559.3 million in Perry Unit 1, plus its interest in BV Unit
2 with lease commitments of $402.8 million, at March 31, 1996. The lease
commitments of $402.8 million represent the net present value of future lease
payments discounted at 10.94 percent, the return currently authorized the
Company by the PUC. 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, 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 $10.9 million.
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
Company has purchased $200 million of insurance, the maximum amount available,
which provides the first level of financial protection.
Additional protection of $8.3 billion would be provided by an assessment of
up to $75.5 million per incident on each nuclear unit in the United States. The
Company's maximum total assessment, $56.6 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. A further surcharge
of 5 percent could be levied if the total amount of public claims exceeded the
funds provided under the assessment program. Additionally, a state premium tax
may be charged on the assessment and surcharge. Finally, the United States
Congress could impose other revenue-raising measures on the nuclear industry if
funds prove insufficient to pay claims.
The Company carries extra expense insurance which would pay the incremental
cost of any replacement power purchased (in addition to costs that would have
been incurred had the units been operating) and other incidental expense after
the occurrence of certain types of accidents at its nuclear units in a limited
amount for a limited period of time. The coverage provides for 100 percent of
the estimated extra expense per week during the 52-week period starting 21 weeks
after an accident and 80 percent of such estimate per week for the following 104
weeks with no coverage thereafter. The amount and duration of actual extra
expense could substantially exceed insurance coverage. NEIL also provides this
insurance. If NEIL's reserves are inadequate to cover claims at any United
States nuclear site covered by that insurer, the Company could be assessed
retrospective premiums totaling a maximum of $3.5 million.
10
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Beaver Valley Power Station Steam Generators. BVPS's two units are equipped
with steam generators that were designed and built by Westinghouse Electric
Corporation (Westinghouse). Similar to other Westinghouse nuclear plants,
outside diameter stress corrosion cracking (ODSCC) has occurred in the steam
generator tubes of both units. BV Unit 1, which was placed in service in 1976,
has removed approximately 15 percent of its steam generator tubes from service
through a process called plugging. However, BV Unit 1 continues to operate at
100 percent reactor power and has the ability to return tubes to service by
repairing them through a process called sleeving. To date, no tubes at either
unit have been sleeved. BV Unit 2, which was placed in service eleven years
after BV Unit 1, has not yet exhibited the degree of ODSCC experienced at BV
Unit 1. Less than 2 percent of BV Unit 2's tubes are plugged; however, it is
too early in the life of the unit to determine the extent to which ODSCC may
become a problem.
The Company has undertaken certain measures, such as increased inspections,
water chemistry control, and tube plugging, to minimize the operational impact
of and to reduce susceptibility to ODSCC. Although the Company has taken these
steps to allay the effects of ODSCC, the inherent potential for future ODSCC in
steam generator tubes of the Westinghouse design still exists. Material
acceleration in the rate of ODSCC could lead to a loss of plant efficiency,
significant repairs or the possible replacement of BV Unit 1's steam
generators. The total replacement cost of BV Unit 1's steam generators is
currently estimated at approximately $125 million. The Company would be
responsible for $59 million of this total, which includes the cost of equipment
removal and replacement, but excludes replacement power costs. The earliest
that BV Unit 1's steam generators could be replaced is 1999.
BV Unit 1 completed its 11th refueling outage on May 11, 1996. The outage
lasted 49 days and was the shortest refueling outage in the history of the unit.
During the outage, various inspections of the unit's steam generators were made,
including examinations using a new "Plus Point" probe. Use of the probe found
fewer defects than expected at the top of the steam generators' tube sheets. In
addition, the Company returned to service tubes that had previously been
plugged. The net result of activity during the refueling outage is that the
number of steam generator tubes in service at the end of the outage is 85
percent, approximately 1 percent greater than at the beginning of the outage.
The Company continues to explore all viable means of managing ODSCC,
including new repair technologies, and plans to perform 100 percent tube
inspections at each unit during future refueling outages. The Company will
continue to monitor and evaluate the condition of the BVPS steam generators.
Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982
established a policy for handling and disposing of spent nuclear fuel and a
policy requiring the established final repository to accept spent fuel.
Electric utility companies have entered into contracts with the Department of
Energy (DOE) for the permanent disposal of spent nuclear fuel and high-level
radioactive waste in compliance with this legislation. The DOE has indicated
that its repository under these contracts will not be available for acceptance
of spent fuel before 2010 at the earliest. Existing on-site spent fuel storage
capacities at BV Unit 1, BV Unit 2 and Perry Unit 1 are expected to be
sufficient until 2016, 2010 and 2011, respectively.
Uranium Enrichment Decontamination and Decommissioning Fund. Nuclear
reactor licensees in the United States are assessed annually for the
decontamination and decommissioning of DOE uranium enrichment facilities.
Assessments are based on the amount of uranium a utility had processed for
enrichment prior to enactment of the National Energy Policy Act of 1992 (NEPA)
and are to be paid by such utilities over a 15-year period. At March 31, 1996,
the Company's liability for contributions is approximately $9.9 million (subject
to an inflation adjustment). Contributions, when made, are recovered from
electric utility customers through the ECR.
11
<PAGE>
Guarantees
The Company and the owners of Bruce Mansfield Power Station have
guaranteed certain debt and lease obligations related to a coal supply contract
for the Bruce Mansfield plant. At March 31, 1996, the Company's share of these
guarantees was $21.1 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 $23.1 million at
March 31, 1996.
The Company has entered into various partnerships to enhance the credit
associated with affordable housing investments made by third-party investors.
As part of the transactions, the Company has guaranteed a minimum defined yield
and the funding of certain defined operating deficits in return for a fee. A
portion of the fees received has been deferred to absorb any required payments
with respect to these transactions. Based on an evaluation of the underlying
housing projects, it is management's belief that such deferrals are ample for
this purpose.
Residual Waste Management Regulations
In 1992, the Pennsylvania Department of Environmental Protection (DEP)
issued Residual Waste Management Regulations governing the generation and
management of non-hazardous residual waste, such as coal ash. The Company is
assessing the sites it utilizes and has developed compliance strategies
under review by the DEP. Capital compliance costs of $3.0 million were incurred
by the Company in 1995 to comply with these DEP regulations; on the basis of
information currently available, an additional $2.5 million will be incurred in
1996. The expected additional capital cost of compliance through the year 2000
is estimated, based on current information, to be approximately $25 million.
This estimate is subject to the results of ground water assessments and DEP
final approval of compliance plans.
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 or
results of operations.
______________________________
12
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Part I, Item 2 of this Quarterly Report, Form 10-Q (Report) should be read in
conjunction with the Company's condensed consolidated financial statements,
which are set forth on pages 2 through 12 in Part I, Item 1 of this Report.
General
- - -------------------------------------------------------------------------------
DQE is an energy services holding company formed in 1989. Its subsidiaries
are Duquesne Light Company (Duquesne), Duquesne Enterprises (DE), DQE Energy
Services (DES) and Montauk. DQE and its subsidiaries are collectively referred
to as the Company.
Duquesne is an electric utility engaged in the production, transmission,
distribution and sale of electric energy, and is the largest of DQE's
subsidiaries. DE makes strategic investments related to DQE's core energy
business. These investments enhance DQE's capabilities as an energy provider,
increase asset utilization, and act as a hedge against changing business
conditions. DES was formed in August 1995 and is a marketing and development
company providing energy solutions for customers in domestic and international
markets. Montauk is a financial services company that makes long-term
investments and provides financing for the Company's initiatives in high quality
products, services and energy solutions for its customers.
The Company's Electric Service Territory
The Company's utility operations provide electric service to customers in
Allegheny County, including the City of Pittsburgh, and Beaver County. This
represents a service territory of approximately 800 square miles in southwestern
Pennsylvania. 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 customers within this service area, the Company's utility
operations also sell electricity to other utilities beyond the Company's service
territory.
Regulation
The Company's electric utility operations are subject to regulation by the
Pennsylvania Public Utility Commission (PUC), as well as to regulation by the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters.
The Company's electric utility operations are also subject to regulation 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. The Company is also subject to the accounting and reporting
requirements of the United States Securities and Exchange Commission.
The Company's consolidated financial statements report regulatory assets and
liabilities in accordance with Statement of Financial Accounting Standards No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71), and
reflect the effects of the ratemaking process.
13
<PAGE>
In accordance with SFAS No. 71, the Company's consolidated financial statements
reflect regulatory assets and liabilities based on current cost-based ratemaking
regulations. The regulatory assets represent probable future revenue to the
Company because provisions for these costs are currently included, or are
expected to be included, in charges to electric utility customers through the
ratemaking process.
The Company's electric utility operations currently satisfy the SFAS No. 71
criteria. However, a company's utility operations or a portion of such
operations could cease to meet these criteria for various reasons, including a
change in the PUC or the FERC regulations. (See "Competition" discussion on page
17.) Should the Company's electric utility operations cease to meet the SFAS No.
71 criteria, the Company would be required to write off any regulatory assets or
liabilities for those operations that no longer meet these requirements.
Management will continue to evaluate significant changes in the regulatory and
competitive environment in order to assess the Company's overall consistency
with the criteria of SFAS No. 71.
Results of Operations
- - -------------------------------------------------------------------------------
Seasonality
- - -----------
The quarterly results are not necessarily indicative of full-year operations
because of seasonal fluctuations. Sales of electricity to customers by the
Company's electric utility operations tend to increase during the warmer summer
and colder winter seasons because of greater customer use of electricity for
cooling and heating, respectively.
In the near term, weather conditions and the overall level of business
activity in the Company's electric utility service territory are expected to
continue to be the primary factors affecting sales of electricity to customers.
In the long-term, the Company's electric sales may also be affected by increased
competition in the electric utility industry. (See "Competition" discussion on
page 17.)
Operating Revenues
Total operating revenues increased $2.2 million during the first quarter of
1996 as compared to the first quarter of 1995 due to higher sales of
electricity. The severe winter weather during the first three months of 1996
resulted in higher sales of electricity to residential customers of 2.7 percent.
First quarter 1996 sales to commercial and industrial customers were comparable
to commercial and industrial sales for the first quarter of 1995. The colder
winter temperatures also resulted in greater demand for electricity from other
utilities. Revenue from sales of electricity to other utilities increased $3.5
million, or 27.8 percent, in the first quarter of 1996 when compared to the
first quarter of 1995.
The $3.3 million comparative decrease in other operating revenues reflects
the restructuring of Chester Engineers (Chester), a subsidiary of DE and the
absence of increased billings in 1995 to the other joint owners of Beaver Valley
Unit 1 (BV Unit 1) related to the scheduled refueling outage.
14
<PAGE>
Operating Expenses
Total operating expenses increased $11.5 million during the first quarter of
1996 as compared to the first quarter of 1995.
Fuel and purchased power expense was $4.1 million greater in the first
quarter of 1996 when compared to the first quarter of 1995. This increase in
fuel and purchased power expense is consistent with the 1996 first quarter
increase in electric sales volume.
First quarter other operating expense decreased $2.7 million when compared
to 1995. The 3.6 percent net decrease includes reduced expenses resulting from
electric utility cost reductions and the restructuring of Chester. Also
influencing other operating expense were costs associated with DES, formed in
August 1995.
The timing of BV Unit 1 and Perry Unit 1 refueling outages resulted in a
shift between utility other operating and maintenance expenses when comparing
the three months ended March 31, 1996, with the same period in 1995.
Depreciation and amortization expense for the first quarter increased $8.2
million, or 16.8 percent, due primarily to the amortization of the regulatory
asset associated with deferred rate synchronization costs. (See "Deferred Rate
Synchronization Costs" and "Sale of Ft. Martin" discussions on pages 8 and 16,
respectively.)
Other income decreased $.8 million in the first quarter of 1996 when
compared to the first quarter of 1995. First quarter 1996 income generated by
long-term investments was comparable to the first quarter 1995 pre-tax gain of
approximately $7.2 million related to the acquisition of International Power
Machines (IPM) (in which the Company had a $2.8 million equity investment) by
Exide Electronics Group (Exide).
Income taxes decreased $9.5 million compared to the first quarter of 1995
primarily because of lower income before income taxes and amortization of
deferred investment tax credits.
Liquidity and Capital Resources
- - -------------------------------------------------------------------------------
Financing
The Company expects to meet its current obligations and debt maturities
through the year 2000 with funds generated from operations and through new
financings. At December 31, 1995, the Company was in compliance with all of its
debt covenants.
The Company's 1947 first mortgage bond indenture was retired in the third
quarter of 1995 following the maturity of the last bond series issued under the
indenture. All of the Company's First Collateral Trust Bonds have been issued
under a new mortgage indenture established in April 1992 (the 1992 Indenture).
All First Collateral Trust Bonds became first mortgage bonds when the 1947
mortgage indenture was retired. The 1992 Indenture includes more flexible
provisions and eliminates conventions such as mandatory sinking funds and
formula-derived maintenance and replacement clauses.
On May 14, 1996, Duquesne Capital L.P., a Delaware special purpose
limited partnership whose sole general partner is Duquesne, issued in aggregate
$150 million, principal amount of 8-3/8% Cumulative Monthly Income Preferred
Securities, Series A, with a stated liquidation value of $25. The Company
intends to apply the proceeds of such loan or loans to the payment or provision
for payment at maturity, the purchase, on the open market, in private
transactions or otherwise, or the redemption of outstanding securities,
including the payment of $50 million in aggregate principal amount of long-term
debt maturing May 15, 1996 and for general corporate purposes.
15
<PAGE>
Stock Split
On April 19, 1995, the Board of Directors of DQE declared a three-for-two
stock split for shareholders of record May 1, 1995. One additional share of
common stock was issued for every two shares outstanding as of the record date.
The Company increased the quarterly dividend from $.30 to $.32 per share on the
post-split shares effective with the dividend paid January 1, 1996. The Board
plans to continue its past practice of reviewing the dividend quarterly.
Investing
- - -------------------------------------------------------------------------------
The Company's long-term investments focus in five principal areas:
affordable housing, natural gas reserves, lease and leasehold investments,
environmental services, and energy solution investments. The Company invested
$1.0 million and $10.6 million in affordable housing funds in the first quarter
of 1996 and 1995, respectively. During the first quarter of 1996, the Company
had sales of long-term investments of $17.4 million, primarily in lease and
leasehold investments.
On February 8, 1995, IPM was acquired by Exide. As a result of this merger,
the Company acquired 526,250 shares of Exide common stock, a 6.8 percent
interest. Since the merger, the Company has acquired an additional 532,500
shares of Exide for $9.8 million. At March 31, 1996, the Company held an 11.6
percent interest in Exide. Other long-term investments at March 31, 1996,
included a $14.0 million investment in Exide common stock.
On August 31, 1995, Chester repurchased 30 percent of its own outstanding
common stock for $6 million. As a result of this purchase, DE owns 100 percent
of the outstanding common stock of Chester. On February 28, 1996, DE signed a
letter of intent to issue a one year option to an unaffiliated third-party (the
Purchaser) to acquire 71 percent of DE's interest in Chester. The Purchaser's
option to acquire its interest in Chester can only be exercised simultaneously
with an initial public offering (IPO) of Chester's stock. Subsequent to the IPO,
it is estimated that Chester's stock would be held 21 percent, 28 percent, and
51 percent by DE, the public and the Purchaser, respectively.
Outlook
- - -------------------------------------------------------------------------------
Sale of Ft. Martin
On November 29, 1995, the Company and AYP Capital, Inc., an unregulated
subsidiary of the Allegheny Power System (APS), entered into an agreement for
the sale of the Company's 50 percent ownership interest in Unit 1 of the Ft.
Martin Power Station, for the sum of $169 million. The agreement is subject to
all necessary regulatory approvals. On December 20, 1995, the Company filed a
Petition for Declaratory Order with the PUC requesting approval for the sale in
conjunction with a six-point plan to be financed in part by the proceeds of the
Ft. Martin transaction. Under the plan, the Company offers to freeze its base
rates for a period of five years. In addition, the Company proposes to record a
one-time reduction of approximately $130 million in the value of the Company's
nuclear plant investment. The Company also proposes to use the proceeds from the
sale to finance reliability enhancements to the simple cycle units located at
Brunot Island (BI), to retire debt and to reduce equity. The BI simple cycle
units will provide 135 megawatts (MW) of summer peaking capacity and 168 MW of
winter peaking capacity and permit the Company to achieve greater operational
flexibility in meeting peak system demands. The plan also proposes an annual
increase of $25 million for three years in depreciation and amortization expense
related to the Company's nuclear investment, as well as additional annual
contributions to its nuclear plant decommissioning funds of $5 million for five
years, without any increase in existing electric rates. Lastly, the Company
proposes a five-year annual $5 million credit to the ECR to compensate the
16
<PAGE>
Company's electric utility customers for the lost profits from any reduced
short-term power sales foregone by the sale of its ownership interest in the Ft.
Martin Power Station.
In April 1996, The Company filed an Amendment to Petition for Declaratory
Order (the Amendment). The Amendment resulted from negotiations with the Office
of Consumer Advocate, the sole intervenor in this proceeding. The Amendment adds
the following three proposals to the original six-point plan for the sale of the
Company's ownership interest in the Ft. Martin Power Station (discussed in the
preceding paragraph). In addition to the original annual credit of $5 million to
the ECR, the Company proposes to cap energy costs beginning April 1, 1997,
through the remainder of the plan period, at the historical five-year average of
14.7 mils per kilowatt hour. Second, the Company agrees to charge off $9 million
related to the depreciation portion of the $51.1 million of deferred rate
synchronization costs associated with BV Unit 2 and Perry Unit 1. Thereafter,
the Company proposes to amortize the remaining $42.1 million of deferred rate
synchronization costs over a ten-year period. Finally, the Company proposes to
contribute $.5 million annually to a supplemental low-income customer assistance
program. This bill payment program, which is also subject to PUC approval, will
be designed to provide financial assistance to low-income electric customers.
The PUC is currently reviewing the Company's amended petition.
Competition
The electric utility industry is undergoing fundamental change in response
to the open transmission access and increased availability of energy
alternatives fostered by the National Energy Policy Act of 1992 (NEPA), which
has served to increase competition in the industry. Previously captive customers
are seeking freedom to choose alternative suppliers of energy. These competitive
pressures require utilities to offer competitive pricing and terms to retain
customers and to develop new markets for the optimal utilization of their
generation capacity.
In Pennsylvania, the PUC currently is conducting an investigation concerning
regulatory reform and has indicated an intention to issue a report to the
governor and the Pennsylvania General Assembly by June 1996. The PUC staff
issued an interim report in August 1995 that recommended that retail wheeling
not be implemented at that time because of concerns that retail wheeling would
benefit large industrial customers at the expense of smaller customers and
utility shareholders who would absorb the costs of stranded investments, and
that service reliability could be impaired. The report concludes that
performance-based ratemaking, wholesale competition and utility cost cutting
could provide the benefits of retail wheeling without the attendant disruptions.
The Company cannot predict whether the PUC will adopt the recommendations of
this interim report. In addition, legislation related to retail customer choice
recently was introduced in the state legislature. The Company cannot predict
what legislation, if any, may ultimately be enacted.
At the national level, on April 24, 1996, the FERC issued two related final
rules that address the terms on which electric utilities will be required to
provide wholesale suppliers of electric energy with nondiscriminatory access
to the utility's wholesale transmission system. The first rule, Order No.
888, addresses both open access and stranded cost issues. Each public utility
that owns, controls or operates interstate transmission facilities is required
to file within sixty days from May 10, 1996, the date of publication of the
order in the Federal Register, a tariff that offers unbundled transmission
services containing non-rate terms that conform to the FERC's Order 888 pro
forma tariff and to propose rates for these services. The rules indicate FERC's
willingness to defer to state regulators with respect to retail access,
recovery of retail stranded costs and the scope of state regulatory
jurisdiction.
Order No. 888 also provides for full recovery of those costs that were
prudently incurred to serve wholesale (and retail-turned wholesale) customers
that subsequently leave a utility's system. These costs will be recovered from
the departing customers. However, the FERC will not be the forum for recovery
of stranded costs arising when retail customers leave a utility's system, even
if their new suppliers rely on FERC jurisdiction transmission services, unless
state regulators lack authority under state law to provide for recovery.
The second rule, Order No. 889, is the Open Access Same Time Information
rule (OASIS). This rule prohibits transmission owners and their affiliates from
gaining preferential access to information concerning transmission and
establishes a code of conduct to ensure the complete separation of a utility's
wholesale power marketing and transmission operation functions.
Finally, the FERC simultaneously issued a new 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 operate in a
more competitive environment. Because of the Company's current electric
generating configuration, some of its baseload capacity is used less than
optimally. The Company is currently considering ways to align its generating
capabilities more closely with customer demand. Its current rate structure
allows some flexibility
17
<PAGE>
in setting rates to retain its customer base and attract new business. In
addition, although currently sales to wholesale customers do not account for a
significant portion of the Company's revenues, open access transmission offers
the Company the opportunity to sell power on a market basis to customers
outside of its service territory. The company is currently evaluating the
impact of the FERC's recent action on its transmission access filings currently
before the FERC. (See "Transmission Access" discussion on page 19.)
Open access transmission requirements implicitly create the potential for
stranded costs. The Company has implemented, and will continue to evaluate, the
accelerated depreciation of its generating assets as one method to guard against
the competitive risks of stranded investments. The FERC Order No. 888 provides
for stranded cost recovery from wholesale customers, but the details of
implementation remain unclear. Recovery of retail stranded costs, if any, will
be determined at the state level when retail wheeling is addressed. The amended
petition for the sale of the Company's ownership interest in the Ft. Martin
Power Station currently before the PUC proposes an annual increase of $25
million for three years in depreciation and amortization expense related to the
Company's nuclear investment. This amended petition also proposes to record a
one-time write-down in the value of the Company's nuclear plant investment of
approximately $130 million and to increase by $5 million the annual contribution
to the Company's nuclear plant decommissioning funds, for a total of $25 million
in contributions over the next five years. Finally, the amended petition
proposes the recognition of $51.1 million of deferred rate synchronization costs
over a ten-year period. (See "Sale of Ft. Martin" discussion on page 16.) These
current and proposed accelerated investment cost recovery measures will be
absorbed by the Company without an increase in base rates. Although the Company
believes the initiatives proposed in the amended petition will enable it to
maintain and expand its existing customer base, if the proposal is approved, the
Company could face the risk of reduced rates of return if unforeseen costs arise
and if revenues from sales prove inadequate to fund those costs.
The Company believes that these and similar strategies will strengthen its
position to succeed in a more competitive environment by eliminating the need
to charge its electric utility customers in the future for these currently
recognized expenses. At this time, however, there is no assurance as to the
extent to which Company initiatives can or will ultimately eliminate regulatory
and other uncertainties associated with increased competition.
18
<PAGE>
Transmission Access
In March 1994, the Company submitted, pursuant to the Federal Power Act, two
separate "good faith" requests for transmission service with APS and the
Pennsylvania-New Jersey-Maryland Interconnection Association (PJM Companies),
respectively. Each request is based on 20-year firm service with flexible
delivery points for 300 MW of transfer capability over the APS and PJM Companies
transmission networks, which together extend from western Pennsylvania to the
East Coast. Because of a lack of progress on pricing and other issues, on August
5 and September 16, 1994, the Company filed with the FERC applications for
transmission service from the PJM Companies and APS, respectively. The
applications are authorized under Section 211 of the Federal Power Act, which
requires electric utilities to provide firm wholesale transmission service. In
May 1995, the FERC issued proposed orders instructing APS and the PJM Companies
to provide transmission service to the Company and directing the parties to
negotiate specific rates, terms and conditions. The Company was unable to agree
to terms for transmission service with either APS or the PJM Companies. Briefs
were filed with the FERC outlining the areas of disagreement among the
companies. The matter is now pending before the FERC.
The Company is currently evaluating the impact of FERC actions (previously
discussed in "Competition") on these proceedings. The Company cannot predict the
final outcome of these proceedings.
Generation Resource Optimization
The Company's plans for optimizing generation resources are designed to
reduce underutilized generating capacity, promote competition in the wholesale
marketplace, maintain stable prices and meet customer-specified levels of
service reliability. The Company is committed to explore firm energy sales to
wholesale customers, system power sales, system power sales with specific unit
back-up, unit power sales, generating asset sales and any other approach to
efficiently managing capacity and energy.
The proposed sale of the Company's ownership interest in the Ft. Martin
Power Station demonstrates the Company's ongoing efforts to optimize the
utilization of generation resources. (See "Sale of Ft. Martin" discussion on
page 16.) The sale is expected to reduce power production costs by employing a
cost-effective source of peaking capacity through enhanced reliability of the
simple cycle units at BI. Implementation of the proposed plan will better align
the Company's generating capabilities with its native load requirements.
Customer Service Guarantees
The Company's commitment to provide reliable, quality service to its
electric utility customers is characterized by its customer service guarantees.
On March 6, 1995, Duquesne became the first Pennsylvania regulated utility, and
the third in the United States, to offer its residential customers guarantees of
its commitment to courteous, reliable and efficient service. The Company offers
a $25 credit to a customer's account if the Company fails to provide accurate
billings; to meet punctual service appointments; to extend prompt, courteous and
professional service; or to connect new services within one day of the date
requested by the customer.
19
<PAGE>
Customer Advanced Reliability System
In January 1996, the Company announced its Customer Advanced Reliability
System, a new communications service that will provide its electric utility
customers with superior levels of service reliability, security and convenience.
The Company has signed a long-term, full service contract with Itron, Inc.
(Itron), a leading supplier of energy information and communication solutions to
the electric utility industry. Over the next two years, Itron will install,
operate and maintain a communications network that will provide the Company with
an electronic link to its 580,000 customers.
The Customer Advanced Reliability System is designed to respond to customer
needs on the basis of immediate information about the status of power delivery
at individual homes and businesses. This electronic communications service is
another major element in the Company's multi-step plan to make the Company's
electric utility operations more competitive and efficient.
______________________________
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 Securities and Exchange Commission.
20
<PAGE>
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
a. On April 23, 1996, DQE held its 1996 Annual Meeting of Shareholders.
b. Proxies for the Annual Meeting were solicited pursuant to Regulation
14 under the Securities Exchange Act of 1934. There was no
solicitation in opposition to management's nominees for directors as
listed in the proxy statement dated March 18, 1996, and all nominees
were elected.
c. Three matters were submitted to shareholders for a vote at the Annual
Meeting.
Issue 1 was the election of three directors to the Board of Directors
to serve until the 1999 Annual Meeting and until their respective
successors have been chosen and qualified. The vote on this issue was
as follows:
<TABLE>
<CAPTION>
Broker
Nominee For Withheld Non-Votes
--------- ---------- --------- ---------
<S> <C> <C> <C>
Sigo Falk 64,153,983 1,592,916 740,785
Eric W. Springer 64,007,814 1,592,916 740,785
Wesley W. von Schack 64,147,539 1,592,916 740,785
</TABLE>
The following directors' terms continue after the Annual Meeting of
Shareholders:
until 1998 - Doreen E. Boyce, David D. Marshall and Robert Mehrabian;
until 1997 - Daniel Berg, Robert P. Bozzone, William H. Knoell and
Thomas J. Murrin.
Issue 2 was for the approval of amendments to the Long-Term Incentive
Plan, originally adopted by the stockholders in 1987 and subsequently
amended in 1993. The vote on this issue was as follows:
<TABLE>
<CAPTION>
<S> <C> <C>
For 47,546,320 Against 8,463,034 Abstain 1,916,316
---------- --------- ---------
Broker Non-Votes 8,532,228
---------
</TABLE>
Issue 3 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, 1996. The vote on this issue was as follows:
<TABLE>
<CAPTION>
<S> <C> <C>
For 64,481,141 Against 517,236 Abstain 734,740
---------- ------- -------
Broker Non-Votes 733,523
-------
</TABLE>
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits:
EXHIBIT 27.1 - Financial Data Schedule
b. No Current Report on Form 8-K was filed during the three months
ended March 31, 1996.
______________________________
21
<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
-----
(Registrant)
Date May 15, 1996 /s/ Gary L. Schwass
------------ ----------------------
(Signature)
Gary L. Schwass
Executive Vice President, Treasurer
and Principal Financial Officer
Date May 15, 1996 /s/ Morgan K. O'Brien
------------ -----------------------
(Signature)
Morgan K. O'Brien
Controller and
Principal Accounting Officer
22
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<CIK> 0000846930
<NAME> DQE
<MULTIPLIER> 1,000
<CURRENCY> 0
<S> <C>
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<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> MAR-31-1996
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<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,038,731
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<OTHER-ASSETS> 50,806
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0
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<OTHER-OPERATING-EXPENSES> 229,202
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<COMMON-STOCK-DIVIDENDS> 24,835
<TOTAL-INTEREST-ON-BONDS> 22,451
<CASH-FLOW-OPERATIONS> 84,584
<EPS-PRIMARY> 0.55
<EPS-DILUTED> 0.55
<FN>
<F1>Includes (366,573) of Treasury Stock at Cost
<F2>Includes 7,773 of Preference Stock
<F3>Non-Operating Expense
<F4>Includes 1,056 of Preferred and Preference Stock Dividends
-----
</TABLE>
