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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, 1998
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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 __________
Commission File Number
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1-956
Duquesne Light Company
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-0451600
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 393-6000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such report), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No ___
---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
DQE, Inc. is the holder of all shares of common stock, $1 par value, of Duquesne
Light Company consisting of 10 shares as of March 31, 1998 and April 30, 1998.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
DUQUESNE LIGHT COMPANY
CONDENSED STATEMENT OF CONSOLIDATED INCOME
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
---------
1998 1997
------------ -------------
<S> <C> <C>
Operating Revenues
Sales of Electricity:
Customers - net $265,613 $265,349
Utilities 7,072 8,731
-------------- ---------------
Total Sales of Electricity 272,685 274,080
Other 9,722 8,929
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Total Operating Revenues 282,407 283,009
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Operating Expenses
Fuel and purchased power 59,533 51,654
Other operating 66,076 63,017
Maintenance 20,283 17,749
Depreciation and amortization 55,680 53,262
Taxes other than income taxes 19,565 20,244
Income taxes 15,939 22,041
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Total Operating Expenses 237,076 227,967
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OPERATING INCOME 45,331 55,042
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OTHER INCOME AND DEDUCTIONS 11,703 5,908
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INCOME BEFORE INTEREST AND
OTHER CHARGES 57,034 60,950
INTEREST CHARGES 20,448 21,394
MONTHLY INCOME PREFERRED
SECURITIES DIVIDEND
REQUIREMENTS 3,141 3,141
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NET INCOME 33,445 36,415
DIVIDENDS ON PREFERRED AND
PREFERENCE STOCK 998 1,009
-------------- ---------------
EARNINGS FOR COMMON STOCK $ 32,447 $ 35,406
============== ===============
</TABLE>
See notes to condensed consolidated financial statements.
2
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DUQUESNE LIGHT COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1998 1997
-------------------- -------------------
ASSETS
<S> <C> <C>
Property, plant and equipment $ 4,508,820 $ 4,510,738
Less: Accumulated depreciation and amortization (1,983,330) (1,947,819)
--------------------- --------------------
Property, plant and equipment - net 2,525,490 2,562,919
--------------------- --------------------
Long-term investments:
Investment in DQE Common Stock 61,244 57,617
Nuclear decommissioning trust 51,141 47,059
Other long-term investments 76,857 81,888
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Total long-term investments 189,242 186,564
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Current assets:
Cash and temporary cash investments 128,054 165,169
Receivables 111,436 121,975
Other current assets, principally material and supplies 81,295 80,984
--------------------- --------------------
Total current assets 320,785 368,128
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Other non-current assets:
Regulatory assets 672,470 680,885
Other 44,940 41,683
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Total other non-current assets 717,410 722,568
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TOTAL ASSETS $ 3,752,927 $ 3,840,179
===================== ====================
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock - $1 par value (shares - 90,000,000
authorized; 10 issued) $ -- $ --
Capital surplus 833,895 831,151
Retained earnings 172,129 172,682
--------------------- --------------------
Total common stockholder's equity 1,006,024 1,003,833
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Preferred and preference stock before deferred employee stock
ownership plan (ESOP) benefit 242,598 242,903
Deferred ESOP benefit (15,562) (16,400)
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Total preferred and preference stock 227,036 226,503
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Long-term debt 1,150,337 1,218,276
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Total capitalization 2,383,397 2,448,612
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Obligations under capital leases 38,927 37,540
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Current liabilities:
Current maturities and sinking fund requirements 61,856 97,523
Other current liabilities 164,503 154,955
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Total current liabilities 226,359 252,478
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Deferred income taxes - net 630,514 599,811
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Deferred investment tax credits 95,677 97,782
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Deferred income 153,964 183,304
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Other non-current liabilities 224,089 220,652
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Commitments and contingencies (Note 4)
--------------------- --------------------
TOTAL CAPITALIZATION AND LIABILITIES $ 3,752,927 $ 3,840,179
===================== ====================
</TABLE>
See notes to condensed consolidated financial statements.
3
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DUQUESNE LIGHT COMPANY
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
---------
1998 1997
----------------- -----------------
<S> <C> <C>
Cash Flows From Operating Activities
Operations $ 96,533 $ 86,319
Changes in working capital other than cash (13,224) 28,208
(Increase) decrease in ECR (7,270) 99
Other 4,598 18,370
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Net Cash Provided By Operating Activities 80,637 132,996
----------------- ------------------
Cash Flows From Investing Activities
Construction expenditures (8,128) (14,309)
Long-term investments (3,020) (4,230)
Other (422) 2,251
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Net Cash Used in Investing Activities (11,570) (16,288)
----------------- ------------------
Cash Flows From Financing Activities
Reductions of long-term obligations - net (98,163) (7,540)
Dividends on capital stock (998) (40,247)
Other (7,021) (1,491)
----------------- ------------------
Net Cash Used in Financing Activities (106,182) (49,278)
----------------- ------------------
Net (decrease) increase in cash and temporary cash investments (37,115) 67,430
Cash and temporary cash investments at beginning of period 165,169 154,414
----------------- ------------------
Cash and temporary cash investments at end of period $ 128,054 $221,844
================= ==================
Non-Cash Investing and Financing Activities
================= ==================
Capital lease obligations recorded $ 2,552 $ 500
================= ==================
</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 Duquesne Light Company's
(Duquesne's) operations, markets, products, services and prices, and other
factors discussed in Duquesne's filings with the Securities and Exchange
Commission (SEC).
1. CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES
Duquesne Light Company (Duquesne) is a wholly owned subsidiary of DQE, Inc.
(DQE), an energy services holding company formed in 1989. Duquesne is engaged
in the generation, transmission, distribution and sale of electric energy.
Duquesne was formed under the laws of Pennsylvania by the consolidation and
merger in 1912 of three constituent companies. Duquesne has one wholly owned
subsidiary, Monongahela Light and Power Co., also a Pennsylvania corporation,
which currently holds energy-related investments.
On August 7, 1997, the shareholders of DQE and Allegheny Energy, Inc.
(AYE), approved a proposed tax-free, stock-for-stock merger. Upon consummation
of the merger, DQE will be a wholly owned subsidiary of AYE. Immediately
following the merger, Duquesne will remain a wholly owned subsidiary of DQE. The
transaction was originally expected to close in mid-1998, subject to approval of
applicable regulatory agencies. On April 30, 1998, the Pennsylvania Public
Utility Commission (PUC) voted to approve the proposed merger of DQE and AYE,
provided that the companies first join a fully functioning Independent System
Operator (ISO) in order to address market power concerns. An ISO is a regional
electricity transmission organization. This precondition could delay, or
ultimately prevent, consummation of the merger. (See "PUC Proceedings"
discussion, Note 3, on page 7.)
The condensed consolidated financial statements include the accounts of
Duquesne and its wholly owned subsidiary. All material intercompany balances
and transactions have been eliminated in the preparation of the condensed
consolidated financial statements.
In the opinion of management, the unaudited condensed consolidated
financial statements included in this report reflect all adjustments that are
necessary for a fair presentation of the results of interim periods and are
normal, recurring adjustments. Prior periods have been reclassified to conform
with accounting presentations adopted during 1998.
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, 1997. The results of operations for the three months ended March
31, 1998, 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.
Duquesne is subject to the accounting and reporting requirements of the
SEC. In addition, Duquesne's electric utility operations are subject to
regulation by the PUC, including regulation under the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Customer Choice Act), and the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters.
Duquesne's consolidated financial statements report regulatory assets and
liabilities in accordance with Statement of Financial Accounting Standards
(SFAS) 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, Duquesne'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.)
5
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Duquesne's long-term investments include assets of nuclear decommissioning
trusts and marketable securities accounted for in accordance with SFAS No. 115,
Accounting for Certain Investments in Debt and Equity Securities. These
investments are classified as available-for-sale and are stated at market value.
The amounts of unrealized holding gains related to marketable securities at
March 31, 1998, and December 31, 1997, were $31.7 million and $26.6 million
($18.5 million and $15.6 million net of tax, respectively).
Through the Energy Cost Rate Adjustment Clause (ECR), Duquesne 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 Duquesne'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. The rate currently being recovered is
1.28 cents per KWH, based upon estimated 1996 costs. To the extent that current
fuel and purchased power costs, in combination with previously deferred fuel and
purchased power costs, are not projected to be recoverable through this pricing
mechanism, these costs would become transition costs subject to recovery through
a competitive transition charge (CTC). (See "Rate Matters," Note 3, on page 7.)
Nuclear fuel expense is recorded on the basis of the quantity of electric energy
generated and includes such costs as the fee imposed by the United States
Department of Energy (DOE) for future disposal and ultimate storage and
disposition of spent nuclear fuel. Fossil fuel expense includes the costs of
coal, natural gas and fuel oil used in the generation of electricity.
On Duquesne's statement of consolidated income, these ECR revenues are
included as a component of operating revenues. For ECR purposes, Duquesne defers
fuel and other energy expenses for recovery, or refunding, in subsequent years.
The deferrals reflect the difference between the amount that Duquesne is
currently collecting from customers and its actual ECR energy costs. The PUC
annually reviews Duquesne's ECR energy costs for the fiscal year April through
March, compares them to previously projected ECR energy costs, and adjusts the
ECR for over- or under-recoveries and for two PUC-established coal cost
standards. This adjustment was not made during 1997, despite a projected
increase of 0.13 cents per KWH, pending the outcome of Duquesne's Restructuring
Plan or Stand-Alone Plan (as defined in "Rate Matters," Note 3, on page 7).
Over- or under-recoveries from customers have been recorded in the
consolidated balance sheet as payable to, or receivable from, customers. Based
on Duquesne's Restructuring Plan and Stand-Alone Plan, the 1997 under-recoveries
were reclassified as a regulatory asset and may be recovered through a CTC. At
March 31, 1998, $30.8 million was receivable from customers. At December 31,
1997, $23.5 million was receivable from customers and shown as other current
liabilities.
2. RECEIVABLES
Components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
March 31, March 31, December 31,
1998 1997 1997
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 84,323 $ 97,655 $ 90,149
Other utility receivables 19,894 16,534 23,106
Other receivables 23,541 9,288 23,736
Less: Allowance for uncollectible accounts (16,322) (19,566) (15,016)
- --------------------------------------------------------------------------------------------------------------
Total Receivables $111,436 $103,911 $121,975
==============================================================================================================
</TABLE>
6
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Duquesne and an unaffiliated corporation have an agreement that entitles
Duquesne to sell, and the corporation to purchase, on an ongoing basis, up to
$50 million of accounts receivable. At March 31, 1998, and March 31 and
December 31, 1997, Duquesne 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 Duquesne. Duquesne has not
determined, but may attempt to extend the agreement or to replace the facility
with a similar arrangement or to eliminate it upon expiration.
3. RATE MATTERS
Competition and the Customer Choice Act
The electric utility industry continues to undergo fundamental change in
response to development of open transmission access and increased availability
of energy alternatives. Under historical ratemaking practice, regulated electric
utilities were granted exclusive geographic franchises to sell electricity in
exchange for making investments and incurring obligations to serve customers
under the then-existing regulatory framework. Through the ratemaking process,
those prudently incurred costs were recovered from customers along with a return
on the investment. Additionally, certain operating costs were approved for
deferral for future recovery from customers (regulatory assets). As a result of
this historical ratemaking process, utilities have assets recorded on their
balance sheets at above-market costs, thus creating transition or stranded
costs.
In Pennsylvania, the Customer Choice Act went into effect January 1, 1997.
The Customer Choice Act enables Pennsylvania's electric utility customers to
purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, delivery of the
electricity from the generation supplier to the customer will remain the
responsibility of the existing franchised utility. The Customer Choice Act also
provides that the existing franchised utility may recover, through a CTC, an
amount of transition costs that are determined by the PUC to be just and
reasonable. Pennsylvania's electric utility restructuring is being accomplished
through a two-stage process consisting of an initial customer choice pilot
period (running through 1998) and a phase-in to competition period (beginning in
1999). For the first stage, Duquesne filed a pilot program with the PUC on
February 27, 1997. For the second stage, Duquesne filed on August 1, 1997 its
restructuring and merger plan (the Restructuring Plan) and its stand-alone
restructuring plan (the Stand-Alone Plan) with the PUC.
Customer Choice Pilots
The pilot period gives 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's pilot filing proposed unbundling transmission, distribution,
generation and competitive transition charges and offered participating
customers the same options that were to be available in a competitive generation
market. The pilot was designed to comprise approximately 5 percent of Duquesne's
residential, commercial and industrial demand. The 28,000 customers
participating in the pilot may choose unbundled service, with their electricity
provided by an alternative generation supplier, and will be subject to unbundled
distribution and CTC charges approved by the PUC and unbundled transmission
charges pursuant to Duquesne's FERC-approved tariff. On May 9, 1997, the PUC
issued a Preliminary Opinion and Order approving Duquesne's filing in part, and
requiring certain revisions. Duquesne and other utilities objected to several
features of the PUC's Preliminary Opinion and Order. Hearings on several key
issues were held in July. The PUC issued its final order on August 29, 1997,
approving a revised pilot program for Duquesne. On September 8, 1997, Duquesne
appealed the determination of the market price of generation set forth in this
order to the Commonwealth Court of Pennsylvania. Duquesne expects a hearing to
be scheduled for mid-1998. Although this appeal is pending, Duquesne complied
with the PUC's order to implement the pilot program that began on November 3,
1997.
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Phase-In to Competition
As set forth in the Customer Choice Act, the phase-in to competition begins
on January 1, 1999, when 33 percent of customers will have customer choice
(including customers covered by the pilot program); 66 percent of customers will
have customer choice no later than January 1, 2000; and all customers will have
customer choice no later than January 1, 2001. However, in its sole order to
date (the PECO Order), the PUC ordered the phase-in provisions of the Customer
Choice Act to require the acceleration of the second and third phases to January
2, 1999 and January 2, 2000, respectively; in addition, in its April 30, 1998
meeting the PUC voted to similarly accelerate the phase-in to competition for
Duquesne's customers. (See "PUC Proceedings" discussion on page 9.) As they
are phased-in, customers that have chosen an electricity generation supplier
other than Duquesne will pay that supplier for generation charges, and will pay
Duquesne a CTC (discussed below) and unbundled charges for transmission and
distribution. Customers that continue to buy their generation from Duquesne will
pay for their service at current regulated tariff rates divided into unbundled
generation, transmission and distribution charges. The PECO Order concluded that
under the Customer Choice Act, an electric distribution company, such as
Duquesne, is to remain a regulated utility and may only offer PUC-approved,
tariffed rates (including unbundled generation rates). Delivery of electricity
(including transmission, distribution and customer service) will continue to be
regulated in substantially the same manner as under current regulation.
Rate Cap and Transition Cost Recovery
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 rates they currently charge customers. Duquesne
has mitigated in excess of $350 million of transition costs during the past
three years through accelerated annual depreciation and a one-time write-down of
nuclear generating station costs, accelerated recognition of nuclear lease
costs, increased nuclear decommissioning funding, and amortization of various
regulatory assets. This relative level of transition cost reduction, while
holding rates constant, is unmatched within Pennsylvania.
The PUC will determine what portion of a utility's transition costs that
remain at January 1, 1999 will be recoverable through a CTC from customers. The
CTC recovery period could last through 2005, providing a utility a total of up
to nine years beginning January 1, 1997 to recover transition costs, unless this
period is extended as part of a utility's PUC-approved transition plan. An
overall four-and-one-half-year rate cap from January 1, 1997 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 rates as long as transition costs are being recovered, with certain
exceptions. Duquesne has requested recovery of transition costs of approximately
$2 billion, net of deferred taxes, beginning January 1, 1999. Of this amount,
$0.5 billion represents regulatory assets and $1.5 billion represents
potentially uneconomic plant and plant decommissioning costs. Any estimate of
the ultimate level of transition costs for Duquesne depends on, among other
things, the extent to which such costs are deemed recoverable by the PUC, the
ongoing level of the cost of Duquesne's operations, regional and national
economic conditions, and growth of Duquesne's sales. (See "Financial Exposure to
Transition Cost Recovery" discussion on page 21; "PUC Proceedings" discussion on
page 9; and "Regulatory Assets and Emerging Issues Task Force" discussion on
page 10).
Stand-Alone Plan
In the event the merger of DQE with AYE is not consummated under the filed
Restructuring Plan, Duquesne has sought approval for restructuring and recovery
of its own transition costs through a CTC under the Stand-Alone Plan. Duquesne
argued, as a fundamental premise, that any finding of market value for
Duquesne's generating assets to determine transition costs should be based on
market evidence and not on an administrative determination of that value based
on price forecasts (the PECO Order determined the market value of PECO Energy
Company's generation based on the price forecast sponsored by the Pennsylvania
Office of Consumer Advocate). Duquesne proposed a number of alternative market
valuation methodologies that it believed would satisfy this market-based
standard. As an alternative, if the PUC finds that a determination of market
value as of
8
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December 31, 1998, is required by the Customer Choice Act, then Duquesne has
agreed that the PUC may order an immediate auction of Duquesne's generation at
that time. (A more detailed discussion of alternative methodologies to
determine transition costs based on market evidence is set forth in Duquesne's
Annual Report on Form 10-K for the Year Ended December 31, 1997.)
Restructuring Plan
The Restructuring Plan incorporated the benefits of the merger with AYE,
such as anticipated savings to Duquesne, on a nominal basis, of $365 million in
generation-related costs over 20 years, and $9 million in transmission-related
costs and $173 million in distribution-related costs over 10 years. The
Restructuring Plan also incorporated the market-based approach to determining
transition costs proposed by Duquesne in its Stand-Alone Plan, however Duquesne
did not agree that the PUC may order an immediate auction of its generation to
determine transition costs. (A more detailed discussion of alternative
methodologies to determine transition costs based on market evidence is set
forth in Duquesne's Annual Report on Form 10-K for the Year Ended December 31,
1997.) The opposing parties believe that there should be a one-time valuation
of the generation assets performed as of December 31, 1998. Any merger-related
synergies relating to generation would then be used to reduce Duquesne's
transition costs as of that date. These parties also believe that Duquesne's
proposed distribution rate decrease should be effective on January 1, 1999.
Duquesne has requested a total CTC recovery of transition costs of $1.899
billion in the event the PUC does not accept its proposal to determine
transition costs based on market evidence.
PUC Proceedings
On March 25, 1998, two PUC administrative law judges recommended that a
decision on the proposed merger of DQE and AYE be deferred for up to 18 months
to allow the companies to address market power concerns. In two other decisions
issued at the same time, the judges recommended approval, with modifications, of
the restructuring plans of Duquesne and of AYE's utility subsidiary, West Penn
Power. On April 14, 1998, Duquesne filed exceptions to the administrative law
judges' recommendations. Also on April 14, DQE and AYE jointly filed exceptions
to the PUC administrative law judges' recommendation that approval of the
proposed merger be delayed.
The administrative law judge did not support Duquesne's market-based
approach to determining the value of its generating assets (and thereby its
CTC), and recommended instead either an immediate auction of Duquesne's
generating assets if the proposed DQE/AYE merger is not consummated, or an
administrative determination of the value of such assets if the proposed DQE/AYE
merger is consummated. In its exceptions, Duquesne sought clarification of the
administrative law judge's recommendation and reaffirmed its fundamental premise
that market data should be used to set the value of its generating assets.
In their joint exceptions, DQE and AYE committed to mitigate the potential
market power of the new company by joining the Midwest Independent System
Operator (MISO) and by relinquishing control of the output of Duquesne's 570-
megawatt Cheswick Power Station (Cheswick) for a minimum of two years or until
the MISO has been approved. Both actions would occur immediately upon
completion of the proposed merger. DQE and AYE further committed to issue a
request for proposals to sell the output of Cheswick within a month of securing
all required regulatory approvals for the proposed merger. Duquesne would
continue to own and operate Cheswick.
On April 30, 1998, the PUC held a nonbinding vote on the recommended
decisions. Reversing the recommendation to delay a decision by up to 18 months,
the PUC voted instead to approve the merger. However, to address market power
concerns, the PUC also required membership in a fully functioning ISO prior to
consummation of the merger. The PUC recognized that joining either the MISO (as
discussed above) or the Pennsylvania-New Jersey-Maryland ISO (PJM) would be an
acceptable option. The MISO's application for approval is before the FERC, but
no date for a decision has been set. Pursuing membership in PJM would require
DQE and AYE to file an updated market power study with the PUC. The
precondition of joining a fully functioning ISO could delay, or ultimately
prevent, consummation of the merger.
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With respect to the Stand-Alone Plan, the PUC voted to require Duquesne to
auction its generating assets in order to determine their market value and its
CTC. Duquesne would have to submit a divestiture plan to the PUC within 90 days
of the effective date of a final order. If such a divestiture were not
completed by January 1, 1999, Duquesne would use an interim CTC set at the rate
approved in its pilot program. The CTC determined by the auction would be
permanent, precluding annual adjustments based on the market price of power as
originally proposed by Duquesne.
With respect to the Restructuring Plan, the PUC proposed calculating
Duquesne's transition costs based on an administrative determination of the
value of its generating assets as opposed to Duquesne's proposed market-based
approach. The PUC would set Duquesne's transition costs at approximately $1.3
billion, reflecting $152.28 million in generation-related savings resulting from
the merger. This amount would disallow certain assets Duquesne anticipated
including in its transition costs, including, among other things, the cold-
reserved units at Philips Power Station and at a portion of Brunot Island Power
Station. (See "Regulatory Assets and Emerging Issues Task Force" discussion
below.) The PUC would permit transition cost recovery through 2005 pursuant to a
CTC initially set at an average of 2.58 cents per KWH for 1999 (resulting in a
shopping credit, or reduction from previously bundled rates, of 4.01 cents per
KWH). The PUC would also reduce Duquesne's distribution rates by $15 million per
year beginning January 1, 2000, to reflect merger savings. Duquesne has
calculated the effects of the PUC's CTC and shopping credit determination, and
estimates that, correcting for computational errors, the 1999 average CTC should
be 2.73 cents per KWH (resulting in a shopping credit of 3.49 cents per KWH).
The PUC also voted to accelerate Duquesne's phase-in to competition
schedule. The Customer Choice Act calls for phase-in of one-third of customers
by January 1, 1999; two-thirds by January 1, 2000; and the final third by
January 1, 2001. The PUC voted to accelerate the second third to January 2,
1999, and the final third to January 2, 2000.
Final orders with respect to the PUC's vote will be written, and a final
binding vote is currently scheduled to take place on May 21, 1998.
The Federal Filings
In addition to the PUC filings of the Restructuring Plan and the Stand-
Alone Plan, on August 1, 1997, DQE and AYE filed their joint merger application
with the FERC (the FERC Filing). Pursuant to the FERC Filing, DQE and AYE have
committed to forming or joining an ISO that meets the entity's requirements,
including marginal cost transmission pricing, following the merger. In April
1998, DQE and AYE executives notified the FERC of their intention to join the
MISO, and that they would not withdraw from the MISO without the prior approval
of the FERC. In addition, DQE and AYE have stated in the FERC Filing that
following the merger the combined entity's market share will not violate the
market power conditions and requirements set by the FERC. On January 20, 1998,
DQE and AYE filed merger applications with the Antitrust Division of the
Department of Justice and the Federal Trade Commission. These applications are
currently pending.
Regulatory Assets and Emerging Issues Task Force
As a result of the application of SFAS No. 71, Duquesne records regulatory
assets on its consolidated balance sheet. The regulatory assets represent
probable future revenue to Duquesne because provisions for these costs are
currently included, or are expected to be included, in charges to electric
utility customers through the ratemaking process.
A company's electric utility operations, or a portion of such operations,
could cease to meet the SFAS No. 71 criteria for various reasons, including a
change in the FERC regulations or the competition-related changes in the PUC
regulations. (See "Competition and the Customer Choice Act" discussion on page
7.) The Emerging Issues Task Force of the Financial Accounting Standards Board
(EITF) 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 SFAS No. 101, Regulated Enterprises - Accounting
for the Discontinuation of Application of FASB Statement No. 71 (SFAS No. 101).
The consensus reached by the EITF 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. Pursuant to the PUC's April 30 vote, certain of
Duquesne's generation-related regulatory assets may be recovered through a
10
<PAGE>
CTC collected in connection with providing transmission and distribution
services. Duquesne will continue to apply SFAS No. 71 with respect to such
assets. Fixed assets related to the generation portion of a utility will be
evaluated including the cash flows provided by the CTC, in accordance with SFAS
No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of (SFAS No. 121). Following the final PUC vote on May 21,
once any portion of Duquesne's electric utility operations is deemed to no
longer meet the SFAS No. 71 criteria, or is not recovered through a CTC,
Duquesne will be required to write off assets (to the extent their net book
value exceeds fair value), the recovery of which is uncertain, and any
regulatory assets or liabilities for those operations that no longer meet these
requirements. Any such write-off of assets could be materially adverse to the
financial position, results of operations and cash flows of Duquesne. (See "PUC
Proceedings" discussion on page 9.)
Duquesne's regulatory assets related to generation, transmission and
distribution as of March 31, 1998 were $556.1 million, $32.4 million and $84.0
million, respectively. At December 31, 1997, Duquesne's regulatory assets
related to generation, transmission and distribution were $561.9 million, $33.2
million and $85.8 million, respectively.
The components of all regulatory assets for the periods presented are as
follows:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
March 31, December 31,
1998) 1997
(Amounts in Thousands of Dollars)
- ------------------------------------------------------------------------------------------
<S> <C> <C>
Regulatory tax receivable $288,113 $301,664
Brunot Island and Phillips cold reserve units 105,693 105,693
Unamortized debt costs 93,226 87,915
Deferred energy costs 48,854 39,225
Deferred rate synchronization costs 36,177 37,231
Beaver Valley Unit 2 sale/leaseback premium 28,177 28,554
Deferred employee costs 20,109 25,130
Deferred nuclear maintenance outage costs 13,685 17,013
DOE decontamination and decommissioning receivable 8,609 8,847
Other 29,827 29,613
- ------------------------------------------------------------------------------------------
Total Regulatory Assets $672,470 $680,885
- ------------------------------------------------------------------------------------------
</TABLE>
4. COMMITMENTS AND CONTINGENCIES
Construction
Duquesne estimates that it will spend, excluding the Allowance for Funds
Used During Construction and nuclear fuel, approximately $130 million on
construction during 1998.
Nuclear-Related Matters
Duquesne 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. Duquesne expects to decommission Beaver Valley
Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and Perry Unit 1 no earlier
than the expiration of each plant's operating license in 2016, 2027 and 2026,
respectively. At the end of its operating life, BV Unit 1 may be placed in safe
storage until BV Unit 2 is ready to be decommissioned, at which time the units
may be decommissioned together.
Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit
2, and a 1997 update of the 1994 study for Perry Unit 1, Duquesne's approximate
share of the total estimated decommissioning costs, including removal and
decontamination costs, is $170 million, $55 million and $90 million,
respectively. The amount currently being used to determine Duquesne's cost of
service related to decommissioning all three nuclear units is $224 million.
Duquesne is seeking recovery of any potential shortfall in decommissioning
funding as part of either its Restructuring Plan or its Stand-Alone Plan. (See
"Rate Matters," Note 3, on page 7.)
11
<PAGE>
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. Consistent with this requirement, in
1997 Duquesne increased its annual contributions to the decommissioning trusts
by $5 million to approximately $9 million. Duquesne has received approval from
the IRS for tax qualification of 100 percent of additional nuclear
decommissioning trust funding for BV Unit 2 and Perry Unit 1, and 79 percent for
BV Unit 1.
Funding for nuclear decommissioning costs is deposited in external,
segregated trust accounts and invested in a portfolio of corporate common stock
and debt securities, municipal bonds, certificates of deposit and United States
government securities. The market value of the aggregate trust fund balances at
March 31, 1998, totaled approximately $51.1 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 Duquesne. 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. Duquesne'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 assessments from the nuclear industry prove insufficient
to pay claims, the United States Congress could impose other revenue-raising
measures on the industry.
Duquesne's share of insurance coverage for property damage, decommissioning
and decontamination liability is $1.2 billion. Duquesne would be responsible for
its share of any damages in excess of insurance coverage. In addition, if the
property damage reserves of Nuclear Electric Insurance Limited (NEIL), an
industry mutual insurance company that provides a portion of this coverage, are
inadequate to cover claims arising from an incident at any United States nuclear
site covered by that insurer, Duquesne could be assessed retrospective premiums
totaling a maximum of $7.3 million.
In addition, Duquesne participates in a NEIL program that provides
insurance for the increased cost of generation and/or purchased power resulting
from an accidental outage of a nuclear unit. Subject to the policy 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, Duquesne could be assessed retrospective premiums totaling
a maximum of $2.6 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 removed approximately 17 percent of its steam generator tubes from service
through a process called "plugging." However, BV Unit 1 still has the capability
to operate at 100 percent reactor power and has the ability to return tubes to
service by repairing them through a process called "sleeving." No tubes at
either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was
placed in service 11 years after BV Unit 1, has not yet exhibited the degree of
ODSCC experienced at BV Unit 1. Approximately 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 at that unit.
Duquesne has undertaken certain measures, such as increased inspections,
water chemistry control and tube plugging, to minimize the operational impact of
and to reduce susceptibility to ODSCC. Although Duquesne has taken these steps
to allay the effects of ODSCC, the inherent potential for future ODSCC in steam
generator tubes of the Westinghouse design still exists. Material acceleration
in the rate of ODSCC could lead to a loss of plant efficiency, significant
repairs or the possible replacement of the BV Unit 1 steam generators. The total
replacement cost of the BV Unit 1 steam generators is currently estimated at
$125 million. Duquesne would be responsible for $59 million of this total, which
includes the cost of equipment removal and replacement steam generators but
excludes replacement power costs. The earliest that the BV Unit 1 steam
generators could be replaced during a currently scheduled refueling outage is
the spring of 2002.
12
<PAGE>
Duquesne continues to explore all viable means of managing ODSCC, including
new repair technologies, and plans to continue to perform 100 percent tube
inspections during future refueling outages. The next refueling outage for BV
Unit 1 is scheduled to begin in April 1999, and the next refueling outage for BV
Unit 2 is currently scheduled to begin in September 1998. Both outages will
include inspection of 100 percent of each unit's steam generator tubes. Duquesne
will continue to monitor and evaluate the condition of the BVPS steam
generators.
BV Unit 1 went off-line January 30, 1998, due to an issue identified in a
technical review completed by Duquesne. BV Unit 2 went off-line December 16,
1997, to repair the emergency air supply system to the control room and has
remained off-line due to other issues identified by a technical review similar
to that performed at BV Unit 1. These technical reviews are in response to a
1997 commitment made by Duquesne to the Nuclear Regulatory Commission (NRC).
Duquesne is one of many utilities faced with similar issues, some of which date
back to the initial start-up of BVPS. Both BVPS units remain off-line for a
reaffirmation of compliance with technical specification requirements of various
plant systems. Duquesne is currently participating in a series of meetings with
the NRC to review its action plans. Both units are expected to remain off-line
until the action plans have been satisfactorily completed.
Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982
established a federal policy for handling and disposing of spent nuclear fuel
and a policy requiring the establishment of a final repository to accept spent
nuclear fuel. Electric utility companies have entered into contracts with the
DOE for the permanent disposal of spent nuclear fuel and high-level radioactive
waste in compliance with this legislation. The DOE has indicated that its
repository under these contracts will not be available for acceptance of spent
nuclear fuel before 2010. The DOE has not yet established an interim or
permanent storage facility, despite a ruling by the United States Court of
Appeals for the District of Columbia Circuit that the DOE was legally obligated
to begin acceptance of spent nuclear fuel for disposal by January 31, 1998.
Existing on-site spent nuclear fuel storage capacities at BV Unit 1, BV Unit 2
and Perry Unit 1 are expected to be sufficient until 2017, 2011 and 2011,
respectively.
In early 1997, Duquesne joined 35 other electric utilities and 46 states,
state agencies and regulatory commissions in filing suit in the United States
Court of Appeals for the District of Columbia Circuit against the DOE. The
parties requested the court to suspend the utilities' payments into the Nuclear
Waste Fund and to place future payments into an escrow account until the DOE
fulfills its obligation to accept spent nuclear fuel. The DOE had requested that
the court delay litigation while it pursued alternative dispute resolution under
the terms of its contracts with the utilities. The court ruling, issued November
14, 1997, was not entirely in favor of the DOE or the utilities. The court
permitted the DOE to pursue alternative dispute resolution, but prohibited it
from using its lack of a spent fuel repository as a defense. While the DOE has
requested a rehearing on the matter, the utilities and states have requested the
DOE be required to submit a definitive plan to begin accepting spent nuclear
fuel. The court has not ruled on either request yet.
Uranium Enrichment Obligations. Nuclear reactor licensees in the United
States are assessed annually for the decontamination and decommissioning of DOE
uranium enrichment facilities. Assessments are based on the amount of uranium a
utility had processed for enrichment prior to enactment of the National Energy
Policy Act of 1992 (NEPA) and are to be paid by such utilities over a 15-year
period. At each of March 31, 1998 and December 31, 1997, Duquesne's liability
for contributions was approximately $7.2 million (subject to an inflation
adjustment). (See "Rate Matters," Note 3, on page 7.)
Fossil Decommissioning
In Pennsylvania, current ratemaking does not allow utilities to recover
future decommissioning costs through depreciation charges during the operating
life of fossil-fired generating stations. Based on studies conducted in 1997,
this amount for fossil decommissioning is currently estimated to be $130 million
for Duquesne's interest in 17 units at six sites. Each unit is expected to be
decommissioned upon the cessation of the final unit's operations. Duquesne has
submitted these estimates to the PUC, and is seeking to recover these costs as
part of either its Restructuring Plan or its Stand-Alone Plan. (See "Rate
Matters" discussion, Note 3, on page 7.)
13
<PAGE>
Guarantees
Duquesne and the other owners of Bruce Mansfield Power Station (Bruce
Mansfield) have guaranteed certain debt and lease obligations related to a coal
supply contract for Bruce Mansfield. At March 31, 1998, Duquesne's share of
these guarantees was $10.8 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 Duquesne solely in relation to these obligations are $11.7 million
at March 31, 1998.
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. Duquesne is
assessing the sites it utilizes and has developed compliance strategies that are
currently under review by the DEP. Based on information currently available, $8
million will be spent in 1998 to comply with these DEP regulations. The
additional capital cost of compliance through the year 2000 is estimated, based
on current information, to be $16 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 Duquesne with respect to air
and water quality and other environmental matters. Duquesne believes it is in
current compliance with all material applicable environmental regulations.
Other
Duquesne is involved in various other legal proceedings and environmental
matters. Duquesne believes that such proceedings and matters, in total, will not
have a materially adverse effect on its financial position, results of
operations or cash flows.
___________________________
14
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in
conjunction with Duquesne's Annual Report on Form 10-K filed with the Securities
and Exchange Commission (SEC) for the year ended December 31, 1997 and
Duquesne's condensed consolidated financial statements, which are set forth on
pages 2 through 14 in Part I, Item 1 of this Report.
General
- -------------------------------------------------------------------------------
Duquesne Light Company (Duquesne) is a wholly owned subsidiary of DQE, Inc.
(DQE), an energy services holding company formed in 1989. Duquesne is engaged
in the generation, transmission, distribution and sale of electric energy.
Duquesne was formed under the laws of Pennsylvania by the consolidation and
merger in 1912 of three constituent companies. Duquesne has one wholly owned
subsidiary, Monongahela Light and Power Co., also a Pennsylvania corporation,
which currently holds energy-related lease investments.
On August 7, 1997, the shareholders of DQE and Allegheny Energy, Inc.
(AYE), approved a proposed tax-free, stock-for-stock merger. Upon consummation
of the merger, DQE will be a wholly owned subsidiary of AYE. Immediately
following the merger, Duquesne will remain a wholly owned subsidiary of DQE.
The transaction was originally expected to close in mid-1998, subject to
approval of applicable regulatory agencies. On April 30, 1998, the Pennsylvania
Public Utility Commission (PUC) voted to approve the proposed merger of DQE and
AYE, provided that the companies first join an Independent System Operator (ISO)
in order to address market power concerns. An ISO is a regional electricity
transmission organization. This precondition could delay, or ultimately
prevent, consummation of the merger. (See "PUC Proceedings" discussion on page
22.)
Service Territory
Duquesne provides electric service to customers in Allegheny County,
including the City of Pittsburgh, Beaver County and Westmoreland County. (See
"Rate Matters" discussion on page 19.) 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 Duquesne, 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, Duquesne also sells electricity to other
utilities.
Regulation
Duquesne is subject to the accounting and reporting requirements of the SEC.
In addition, Duquesne's electric utility operations are subject to regulation by
the PUC, including regulation under the Pennsylvania Electricity Generation
Customer Choice and Competition Act (Customer Choice Act), and the Federal
Energy Regulatory Commission (FERC) under the Federal Power Act with respect to
rates for interstate sales, transmission of electric power, accounting and other
matters. (See "Rate Matters" on page 19.)
Duquesne is 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.
Duquesne's consolidated financial statements report regulatory assets and
liabilities in accordance with Statement of Financial Accounting Standards
(SFAS) 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, Duquesne's consolidated financial statements
reflect regulatory assets and liabilities consistent with cost-based, pre-
competition ratemaking regulations. The regulatory assets represent probable
future revenue to Duquesne because provisions for these costs are currently
included, or are expected to be included, in charges to electric utility
customers through the ratemaking process.
15
<PAGE>
A company's electric utility operations, or a portion of such operations,
could cease to meet the SFAS No. 71 criteria for various reasons, including a
change in the FERC regulations or the competition-related changes in the PUC
regulations. (See "Rate Matters" on page 19.) The Emerging Issues Task Force of
the Financial Accounting Standards Board (EITF) 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
SFAS No. 101, Regulated Enterprises - Accounting for the Discontinuation of
Application of FASB Statement No. 71 (SFAS No. 101). The consensus reached by
the EITF 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. Pursuant to the PUC's April 30 vote, certain of Duquesne's generation-
related regulatory assets may be recovered through a competitive transition
charge (CTC) collected in connection with providing transmission and
distribution services. Duquesne will continue to apply SFAS No. 71 with respect
to such assets. Fixed assets related to the generation portion of a utility will
be evaluated including the cash flows provided by the CTC, in accordance with
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed Of (SFAS No. 121). Following the final PUC vote on
May 21 regarding Duquesne's Restructuring Plan and Stand-Alone Plan (as defined
in "Rate Matters" on page 19), once any portion of Duquesne's electric utility
operations is deemed to no longer meet the SFAS No. 71 criteria, or is not
recovered through a CTC, Duquesne will be required to write off assets (to the
extent their net book value exceeds fair value), the recovery of which is
uncertain, and any regulatory assets or liabilities for those operations that no
longer meet these requirements. Any such write-off of assets could be materially
adverse to the financial position, results of operations and cash flows of
Duquesne. (See "PUC Proceedings" discussion on page 22.)
RESULTS OF OPERATIONS
- --------------------------------------------------------------------------------
Duquesne's future financial condition and its future operating results are
substantially dependent upon the effects of the Restructuring Plan or Stand-
Alone Plan currently before the PUC. To the extent Duquesne does not ultimately
recover its transition costs, a charge against earnings would be recognized.
Such charge could have a materially adverse effect on Duquesne's financial
position, results of operations and cash flows. (See "Rate Matters" on page
19.)
Earnings
Duquesne's earnings for common stock decreased to $32.4 million in the
first quarter of 1998 compared to $35.4 million in the first quarter of 1997.
This $3.0 million or 8.4 percent decrease was the result of mild first quarter
1998 temperatures impacting the weather-sensitive residential and commercial
customer kilowatt-hour (KWH) sales and accelerated nuclear lease recovery.
These decreases were partially offset by increased other income from an
investment made in the fourth quarter of 1997.
Revenues
Total operating revenues in the first quarter 1998 decreased $0.6 million
or 0.2 percent as compared to the first quarter of 1997.
- ------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Increase (Decrease) in First Quarter 1998
(Revenues in Millions of Dollars) as Compared to First Quarter 1997
- ------------------------------------------------------------------------------------
KWH Revenues
----------------------------------------
<S> <C> <C>
Residential (7.4)% $(1.0)
Commercial (7.3)% (0.5)
Industrial 4.2% 1.8
Less: Provision for Doubtful Accounts 0.0
- ------------------------------------------------------------------------------------
Sales to Electric Utility Customers (4.2)% 0.3
- ------------------------------------------------------------------------------------
Sales to Other Utilities (26.3)% (1.7)
Other Revenues 0.8
- ------------------------------------------------------------------------------------
Total Sales (7.3)% $(0.6)
====================================================================================
</TABLE>
16
<PAGE>
Sales of Electricity to Customers
Operating revenues are primarily derived from Duquesne's sales of
electricity. Currently the PUC authorizes rates for electricity sales which are
cost-based and are designed to recover Duquesne's operating expenses and
investment in electric utility assets and to provide a return on the investment.
Customer revenues fluctuate as a result of changes in sales volume and changes
in fuel and other energy costs, as these costs are generally recoverable from
customers through the Energy Cost Rate Adjustment Clause (ECR). Under current
fuel cost recovery provisions, fuel revenues generally equal fuel expense,
including the fuel component of purchased power, and do not affect net income.
As required under the Customer Choice Act, Duquesne has filed with the PUC its
plan addressing its proposed restructuring to operate in a competitive
environment including unbundled charges for transmission, distribution,
generation and a CTC. Although not yet approved in a final vote, the PUC has
proposed rates in connection with these filings and the phase-in to competition.
(See "PUC Proceedings" discussion on page 22.)
Sales to residential and commercial customers are influenced by weather
conditions. Warmer summer and colder winter seasons lead to increased customer
use of electricity for cooling and heating. Commercial sales are also affected
by regional development. Sales to industrial customers are influenced by
national and global economic conditions. In addition, the Customer Choice Act
has and will continue to affect bundled sales to Duquesne's retail customers.
The customer choice pilot that was implemented in November 1997, when 5 percent
of customers were given the right to customer choice, reduced sales to retail
customers by approximately 5 percent. It is anticipated that the net financial
impact of Duquesne's customers' choosing alternative generation suppliers during
the pilot period (through 1998) will be a reduction of operating revenues of
approximately $1 million per month. (See "Rate Matters" discussion on page 19.)
In the first quarter of 1998, net customer revenues reflected on the
statement of consolidated income increased by $0.3 million to $265.6 million
from the first quarter of 1997. The variance can be attributed to an increase
in energy costs of $9.5 million offset by a 4.2 percent decrease in KWH sales to
electric utility customers. Residential and commercial sales decreased 169,150
KWH when comparing the first quarter of 1998 and the first quarter of 1997 due
to the pilot program and mild 1998 temperatures. Sales to a new customer, an
industrial gas supplier, represent 82 percent of the increase in industrial
sales, while the remaining increase is due to expansion of one of Duquesne's
largest customers' facilities.
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 Duquesne's customer energy requirements, the energy market and
transmission conditions, and the availability of Duquesne's generating stations.
Future levels of short-term sales to other utilities will be affected by market
rates. Duquesne's electricity sales to other utilities in the first quarter of
1998 were $1.7 million or 19.0 percent less than in the first quarter of 1997.
The reduction was due to reduced availability of generating capacity as a result
of a 52 percent increase in outage hours as compared to the first quarter of
1997.
Other Operating Revenues
Duquesne's non-KWH revenues comprise other operating revenues in Duquesne's
statement of consolidated income. Other operating revenues are primarily
comprised of revenues from joint owners of BV Unit 1 and BV Unit 2 for their
shares of the administrative and general costs of operating these units. Other
operating revenues, therefore, fluctuate depending on timing of scheduled
refueling and maintenance outages at BVPS when significant costs are incurred.
The other operating revenues increase of $0.8 million or 8.9 percent when
comparing the first quarter of 1998 to the first quarter of 1997 is primarily
the result of higher transmission line and pole rental revenues.
17
<PAGE>
Operating Expenses
Fuel and Purchased Power Expense
Fluctuations in fuel and purchased power expense generally result from
changes in the cost of fuel, the mix between coal and nuclear generation, the
total KWHs sold, and generating station availability. Because of the ECR,
changes in fuel and purchased power costs did not impact earnings in the first
quarter of 1998 and the first quarter of 1997. Under Duquesne's 1996 PUC-
approved mitigation plan, the level of energy cost recovery is capped at 1.47
cents per KWH through May 2001. Pending the final order regarding Duquesne's
Restructuring Plan or Stand-Alone Plan filing, Duquesne may freeze the ECR and
roll it into base rates. (See "Rate Matters" on page 19.)
Fuel and purchased power expense increased $7.9 million or 15.3 percent in
the first quarter of 1998 as compared to the first quarter of 1997. The
increase resulted from higher energy costs by $11.8 million or 24.8 percent
partially offset by a $3.9 million or 7.7 percent reduction in energy volume
supplied. Reduced availability of generating stations due to a 52 percent
increase in outage hours forced Duquesne to buy purchased power and generate
power from the higher cost fossil stations. The pilot program and mild 1998
winter temperatures resulted in a reduction of approximately 7 percent of
residential and commercial KWH sales.
Other Operating Expense
The increase of $3.1 million or 4.9 percent in the first quarter of 1998 as
compared to the first quarter of 1997 can be primarily attributed to increased
employee costs charged to expense partially due to redeployment of resources
from capital projects to non-capital projects.
Maintenance Expense
Maintenance expense increased $2.5 million or 14.3 percent in the first
quarter of 1998 as compared to the first quarter of 1997. The increase is
primarily attributable to the timing of tree trimming and maintenance of
overhead lines expenses and to costs incurred for the Cheswick Power Station
scheduled outage that began on February 27, 1998.
Depreciation and Amortization Expense
Depreciation and amortization expense increased $2.4 million or 4.5 percent
in the first quarter of 1998 as compared to the first quarter of 1997, due to
accelerated nuclear lease recovery which began on May 1, 1997.
Income Taxes
Income taxes were lower in the first quarter of 1998 as compared to the
first quarter of 1997 by $6.1 million or 27.7 percent primarily due to reduced
taxable income.
Other Income and Deductions
Other income is primarily made up of income from long-term investments
entered into by the subsidiary of the utility and interest income from short-
term investments. A $5.8 million or 98.1 percent increase in other income in
the first quarter of 1998 as compared to the first quarter of 1997 resulted from
long-term investment income. The greater long-term investment income was the
result of investments made throughout 1997.
Interest Charges
Interest charges decreased $0.9 million or 4.4 percent in the first quarter
of 1998 as compared to the first quarter of 1997. The reason for the decrease
was primarily the result of the retirement and redemption of mortgage bonds
during the first quarter of 1998.
Liquidity and Capital Resources
- --------------------------------------------------------------------------------
Financing
Duquesne expects to meet its current obligations and debt maturities
through the year 2002 with funds generated from operations and through new
financings. At March 31, 1998, Duquesne was in compliance with all of its debt
covenants.
18
<PAGE>
Mortgage bonds in the amount of $35 million matured in February 1998 and
were retired using available cash. In March 1998, Duquesne redeemed $100 million
principal amount of its 8.75 percent mortgage bonds, originally due in May 2022
at a redemption price of 106.5625 percent of the principal amount, plus interest
accrued until redemption. The redemption was partially financed with proceeds of
the February 1998 issuance of $40 million principal amount of 6.45 percent
mortgage bonds, due in February 2008. In addition, in April 1998 Duquesne
issued $100 million principal amount of 7-3/8 percent mortgage bonds, due in
April 2038. Mortgage bonds in the amount of $35 million and $5 million will
mature in June and November 1998, respectively. Duquesne expects to retire these
bonds with available cash or to refinance the bonds. (See "Rate Matters" on page
19.)
Duquesne and an unaffiliated corporation have an agreement that entitles
Duquesne to sell, and the corporation to purchase, on an ongoing basis, up to
$50 million of accounts receivable. This accounts receivable sale arrangement
extends through June 1998. Duquesne may attempt to extend the agreement,
replace it with a similar facility, or eliminate the agreement, upon expiration.
Duquesne maintains a $150 million revolving credit facility which expires
in October 1998. Interest rates can, in accordance with the option selected at
the time of the borrowing, be based on prime, Eurodollar or certificate of
deposit rates. Commitment fees are based on the unborrowed amount of the
commitments. The revolving credit facility contains a two-year repayment period
for any amounts outstanding at the expiration of the revolving credit period.
No amounts were outstanding at March 31, 1998.
Investing
- ------------------------------------------------------------------------------
Duquesne's long-term investments consist of Duquesne's holdings of DQE
common stock, investments in affordable housing, lease investments, and nuclear
decommissioning trust funds. Duquesne invested approximately $3 million and $4
million in nuclear decommissioning trust funds during the three months ended
March 31, 1998 and March 31, 1997, respectively.
Rate Matters
- ------------------------------------------------------------------------------
Competition and the Customer Choice Act
The electric utility industry continues to undergo fundamental change in
response to development of open transmission access and increased availability
of energy alternatives. Under historical ratemaking practice, regulated electric
utilities were granted exclusive geographic franchises to sell electricity in
exchange for making investments and incurring obligations to serve customers
under the then-existing regulatory framework. Through the ratemaking process,
those prudently incurred costs were recovered from customers along with a return
on the investment. Additionally, certain operating costs were approved for
deferral for future recovery from customers (regulatory assets). As a result of
this historical ratemaking process, utilities have assets recorded on their
balance sheets at above-market costs, thus creating transition costs.
In Pennsylvania, the Customer Choice Act went into effect January 1, 1997.
The Customer Choice Act enables Pennsylvania's electric utility customers to
purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, delivery of the
electricity from the generation supplier to the customer will remain the
responsibility of the existing franchised utility. The Customer Choice Act also
provides that the existing franchised utility may recover, through a CTC, an
amount of transition costs that are determined by the PUC to be just and
reasonable. Pennsylvania's electric utility restructuring is being accomplished
through a two-stage process consisting of an initial customer choice pilot
period (running through 1998) and a phase-in to competition period (beginning in
1999). For the first stage, Duquesne filed a pilot program with the PUC on
February 27, 1997. For the second stage, Duquesne filed on August 1, 1997 its
restructuring and merger plan (the Restructuring Plan) and its stand-alone
restructuring plan (the Stand-Alone Plan) with the PUC.
19
<PAGE>
Customer Choice Pilots
The pilot period gives 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's pilot filing proposed unbundling transmission, distribution,
generation and competitive transition charges and offered participating
customers the same options that were to be available in a competitive generation
market. The pilot was designed to comprise approximately 5 percent of Duquesne's
residential, commercial and industrial demand. The 28,000 customers
participating in the pilot may choose unbundled service, with their electricity
provided by an alternative generation supplier, and will be subject to unbundled
distribution and CTC charges approved by the PUC and unbundled transmission
charges pursuant to Duquesne's FERC-approved tariff. On May 9, 1997, the PUC
issued a Preliminary Opinion and Order approving Duquesne's filing in part, and
requiring certain revisions. Duquesne and other utilities objected to several
features of the PUC's Preliminary Opinion and Order. Hearings on several key
issues were held in July. The PUC issued its final order on August 29, 1997,
approving a revised pilot program for Duquesne. On September 8, 1997, Duquesne
appealed the determination of the market price of generation set forth in this
order to the Commonwealth Court of Pennsylvania. Duquesne expects a hearing to
be scheduled for mid-1998. Although this appeal is pending, Duquesne complied
with the PUC's order to implement the pilot program that began on November 3,
1997.
Financial Impact of Pilot Program Order
It is anticipated that the net financial impact of Duquesne's customers'
choosing alternative generation suppliers during the pilot period (through 1998)
will be a reduction of operating revenues of approximately $1 million per month.
(See "Forward-Looking Statements" discussion on page 23.) Duquesne is seeking in
its Restructuring Plan and its Stand-Alone Plan to maintain current rates under
Section 2804(4)(v) of the Customer Choice Act (Rate Cap Provision), which states
that in certain circumstances an electric distribution utility may roll its
energy cost rate into base rates without reducing its rates below the capped
level if the PUC determines that excess earnings are to be used for mitigation
of transition costs. Duquesne will reduce its accelerated nuclear lease
amortization to offset the shortfall, if any, in operating revenues between the
pilot program and the final approved rates.
Phase-In to Competition
As set forth in the Customer Choice Act, the phase-in to competition begins
on January 1, 1999, when 33 percent of customers will have customer choice
(including customers covered by the pilot program); 66 percent of customers will
have customer choice no later than January 1, 2000; and all customers will have
customer choice no later than January 1, 2001. However, in its sole order to
date (the PECO Order), the PUC ordered the phase-in provisions of the Customer
Choice Act to require the acceleration of the second and third phases to January
2, 1999 and January 2, 2000, respectively; in addition, in its April 30, 1998,
meeting the PUC voted to similarly accelerate the phase-in to competition for
Duquesne's customers. (See "PUC Proceedings" discussion on page 22.) As they
are phased-in, customers that have chosen an electricity generation supplier
other than Duquesne will pay that supplier for generation charges, and will pay
Duquesne a CTC (discussed below) and unbundled charges for transmission and
distribution. Customers that continue to buy their generation from Duquesne will
pay for their service at current regulated tariff rates divided into unbundled
generation, transmission and distribution charges. The PECO Order concluded that
under the Customer Choice Act, an electric distribution company, such as
Duquesne, is to remain a regulated utility and may only offer PUC-approved,
tariffed rates (including unbundled generation rates). Delivery of electricity
(including transmission, distribution and customer service) will continue to be
regulated in substantially the same manner as under current regulation.
Rate Cap and Transition Cost Recovery
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 rates they currently charge customers. Duquesne
has mitigated in excess of $350 million of transition costs during the past
three years through accelerated annual depreciation and a one-time write-down of
20
<PAGE>
nuclear generating station costs, accelerated recognition of nuclear lease
costs, increased nuclear decommissioning funding, and amortization of various
regulatory assets. This relative level of transition cost reduction, while
holding rates constant, is unmatched within Pennsylvania.
The PUC will determine what portion of a utility's transition costs that
remain at January 1, 1999 will be recoverable through a CTC from customers. The
CTC recovery period could last through 2005, providing a utility a total of up
to nine years beginning January 1, 1997 to recover transition costs, unless this
period is extended as part of a utility's PUC-approved transition plan. An
overall four-and-one-half-year rate cap from January 1, 1997 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 rates as long as transition costs are being recovered, with certain
exceptions. Following is a summary of Duquesne's requested transition cost
recovery, net of deferred taxes, as of January 1, 1999; the related net balances
as of December 31, 1997; and the amounts mitigated during the past three years.
(See "PUC Proceedings" discussion on page 22.)
Transition Costs
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Mitigation Balance CTC Recovery
(Amounts in Millions of Dollars) 1/1/95 - 12/31/97 12/31/97 Requested 1/1/99
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Nuclear generation plant (a) $232 $ 968 $877
Fossil generation plant (a) -- 541 541
Generation-related regulatory assets (b) 103 382 357
Decommissioning costs (c) 18 133 124
- ------------------------------------------------------------------------------------------------
Total $353 $2,024 $1,899
- ------------------------------------------------------------------------------------------------
</TABLE>
(a) Nuclear and fossil generation plant represent a projection of the amount by
which the net book value, including materials and supplies inventories, and
fuel inventories, of the generating plants exceeds the market value for
these plants. "Nuclear generation plant" also includes the present value of
future above-market lease payments related to the sale/leaseback of BV Unit
2.
(b) Generation-related regulatory assets represent costs which under the
historical ratemaking process were deemed recoverable from customers through
future rates. These regulatory assets include, among other items, amounts
related to future federal income tax payments, premiums paid to reacquire
debt, initial operating costs of BV Unit 2 and Perry Unit 1, and energy
costs not recovered currently.
(c) Decommissioning costs represent the estimated present value of unfunded
fossil and nuclear generation plant decommissioning costs.
Financial Exposure to Transition Cost Recovery
Any estimate of the ultimate level of transition costs (including those set
forth in the table above) depends on, among other things, the extent to which
such costs are deemed recoverable by the PUC in its final binding vote; the
ongoing level of Duquesne's costs of operations; regional and national economic
conditions; and growth of Duquesne's sales. (See "Forward-Looking Statements"
discussion on page 23.) Indeed, the PECO Order, as modified by a settlement on
April 30, 1998, provides for recovery by PECO Energy Company (PECO) of 100
percent of transition costs determined to be just and reasonable by the PUC.
However, in determining transition costs, the PUC found the market value of
PECO's generating units to be significantly higher than the estimate of market
value sponsored by PECO. Thus, the total amount of transition costs requested by
PECO was significantly more than that allowed by the PUC in the PECO Order, as
the PUC-determined market value offset a larger portion of the transition costs.
The PUC-ordered recovery of PECO's transition costs through a CTC is permitted
over a twelve-year period beginning January 1, 1999. However, PECO is only
permitted to earn a return on the unamortized balance of transition costs at a
rate equal to its long-term cost of debt. In its April 30 vote, the PUC proposed
that certain of Duquesne's transition costs cannot be recovered through a CTC.
If the PUC confirms its proposal in the final binding vote on May 21, these
costs will have to be written off. (See "Regulation" on page 15; see also "PUC
Proceedings" discussion on page 22.) On January 26, 1998, PECO announced that it
was reducing its dividend by 44 percent, and also that it was reporting a net
loss for 1997 of $1.5 billion, including an extraordinary charge of $3.1 billion
($1.8 billion net of taxes) in the fourth quarter of 1997 to reflect the effects
of the PECO Order (as effective prior to the April 30 settlement). As Duquesne
has substantial exposure to transition costs relative to its size, significant
transition cost write-offs could have a materially adverse effect on Duquesne's
financial position, results of
21
<PAGE>
operations and cash flows. Various financial covenants and restrictions could be
violated if substantial write-off of assets or recognition of liabilities
occurs. Under such circumstances, Duquesne may face constraints on its ability
to pay dividends, issue new mortgage debt or maintain access to bank lines of
credit, thus negatively impacting its operations.
Stand-Alone Plan
In the event the merger of DQE with AYE is not consummated under the filed
Restructuring Plan, Duquesne has sought approval for restructuring and recovery
of its own transition costs through a CTC under the Stand-Alone Plan. Duquesne
argued, as a fundamental premise, that any finding of market value for
Duquesne's generating assets to determine transition costs should be based on
market evidence and not on an administrative determination of that value based
on price forecasts (the PECO Order determined the market value of PECO's
generation based on the price forecast sponsored by the Pennsylvania Office of
Consumer Advocate). Duquesne proposed a number of alternative market valuation
methodologies that it believed would satisfy this market-based standard. As an
alternative, if the PUC finds that a determination of market value as of
December 31, 1998 is required by the Customer Choice Act, then Duquesne has
agreed that the PUC may order an immediate auction of Duquesne's generation at
that time. (A more detailed discussion of alternative methodologies to determine
transition costs based on market evidence is set forth in Duquesne's Annual
Report on Form 10-K for the Year Ended December 31, 1997.)
Restructuring Plan
The Restructuring Plan incorporated the benefits of the merger of DQE with
AYE, such as anticipated savings to Duquesne, on a nominal basis, of $365
million in generation-related costs over 20 years, and $9 million in
transmission-related costs and $173 million in distribution-related costs over
10 years. The Restructuring Plan also incorporated the market-based approach to
determining transition costs proposed by Duquesne in its Stand-Alone Plan,
however Duquesne did not agree that the PUC may order an immediate auction of
its generation to determine transition costs. (A more detailed discussion of
alternative methodologies to determine transition costs based on market evidence
is set forth in Duquesne's Annual Report on Form 10-K for the Year Ended
December 31, 1997.) The opposing parties believe that there should be a one-
time valuation of the generation assets performed as of December 31, 1998. Any
merger-related synergies relating to generation would then be used to reduce
Duquesne's transition costs as of that date. These parties also believe that
Duquesne's proposed distribution rate decrease should be effective on January 1,
1999. Duquesne has requested a total CTC recovery of transition costs of $1.899
billion in the event the PUC does not accept its proposal to determine
transition costs based on market evidence.
PUC Proceedings
On March 25, 1998, two PUC administrative law judges recommended that a
decision on the proposed merger of DQE and AYE be deferred for up to 18 months
to allow the companies to address market power concerns. In two other decisions
issued at the same time, the judges recommended approval, with modifications, of
the restructuring plans of Duquesne and of AYE's utility subsidiary, West Penn
Power. On April 14, 1998, Duquesne filed exceptions to the administrative law
judges' recommendations. Also on April 14, DQE and AYE jointly filed exceptions
to the PUC administrative law judges' recommendation that approval of the
proposed merger be delayed.
The administrative law judge did not support Duquesne's market-based
approach to determining the value of its generating assets (and thereby its
CTC), and recommended instead either an immediate auction of Duquesne's
generating assets if the proposed DQE/AYE merger is not consummated, or an
administrative determination of the value of such assets if the proposed DQE/AYE
merger is consummated. In its exceptions, Duquesne sought clarification of the
administrative law judge's recommendation and reaffirmed its fundamental premise
that market data should be used to set the value of its generating assets.
In their joint exceptions, DQE and AYE committed to mitigate the potential
market power of the new company by joining the Midwest Independent System
Operator (MISO) and by relinquishing control of the output of Duquesne's 570-
megawatt Cheswick Power Station
22
<PAGE>
(Cheswick) for a minimum of two years or until the MISO has been approved. Both
actions would occur immediately upon completion of the proposed merger. DQE and
AYE further committed to issue a request for proposals to sell the output of
Cheswick within a month of securing all required regulatory approvals for the
proposed merger. Duquesne would continue to own and operate Cheswick.
On April 30, 1998, the PUC held a nonbinding vote on the recommended
decisions. Reversing the recommendation to delay a decision by up to 18 months,
the PUC voted instead to approve the merger. However, to address market power
concerns, the PUC also required membership in a fully functioning ISO prior to
consummation of the merger. The PUC recognized that joining either the MISO (as
discussed above) or the Pennsylvania-New Jersey-Maryland ISO (PJM) would be an
acceptable option. The MISO's application for approval is before the FERC, but
no date for a decision has been set. Pursuing membership in PJM would require
DQE and AYE to file an updated market power study with the PUC. The
precondition of joining a fully functioning ISO could delay, or ultimately
prevent, consummation of the merger.
With respect to the Stand-Alone Plan, the PUC voted to require Duquesne to
auction its generating assets in order to determine their market value and its
CTC. Duquesne would have to submit a divestiture plan to the PUC within 90 days
of the effective date of a final order. If such a divestiture were not
completed by January 1, 1999, Duquesne would use an interim CTC set at the rate
approved in its pilot program. The CTC determined by the auction would be
permanent, precluding annual adjustments based on the market price of power as
originally proposed by Duquesne.
With respect to the Restructuring Plan, the PUC proposed calculating
Duquesne's transition costs based on an administrative determination of the
value of its generating assets as opposed to Duquesne's proposed market-based
approach. The PUC would set Duquesne's transition costs at approximately $1.3
billion, reflecting $152.28 million in generation-related savings resulting from
the merger. This amount would disallow certain assets Duquesne anticipated
including in its transition costs, including, among other things, the cold-
reserved units at Philips Power Station and at a portion of Brunot Island Power
Station. The PUC would permit transition cost recovery through 2005 pursuant to
a CTC initially set at an average of 2.58 cents per KWH for 1999 (resulting in a
shopping credit, or reduction from previously bundled rates, of 4.01 cents per
KWH). The PUC would also reduce Duquesne's distribution rates by $15 million per
year beginning January 1, 2000, to reflect merger savings. Duquesne has
calculated the effects of the PUC's CTC and shopping credit determination, and
estimates that, correcting for computational errors, the 1999 average CTC should
be 2.73 cents per KWH (resulting in a shopping credit of 3.49 cents per KWH).
The PUC also voted to accelerate Duquesne's phase-in to competition
schedule. The Customer Choice Act calls for phase-in of one-third of customers
by January 1, 1999; two-thirds by January 1, 2000; and the final third by
January 1, 2001. The PUC voted to accelerate the second third to January 2,
1999, and the final third to January 2, 2000.
Final orders with respect to the PUC's vote will be written, and a final
binding vote is currently scheduled to take place on May 21, 1998.
The Federal Filings
In addition to the PUC filings of the Restructuring Plan and the Stand-
Alone Plan, on August 1, 1997, DQE and AYE filed their joint merger application
with the FERC (the FERC Filing). Pursuant to the FERC Filing, DQE and AYE have
committed to forming or joining an ISO that meets the entity's requirements,
including marginal cost transmission pricing, following the merger. In April
1998, DQE and AYE executives notified the FERC of their intention to join the
MISO, and that they would not withdraw from the MISO without the prior approval
of the FERC. In addition, DQE and AYE have stated in the FERC Filing that
following the merger the combined entity's market share will not violate the
market power conditions and requirements set by the FERC. On January 20, 1998,
DQE and AYE filed merger applications with the Antitrust Division of the
Department of Justice and the Federal Trade Commission. These applications are
currently pending.
23
<PAGE>
Forward-Looking Statements
The foregoing paragraphs contain forward-looking statements (within the
meaning of the Private Securities Litigation Reform Act of 1995) regarding the
financial impact, consequences and benefits of the Customer Choice Act, the
pilot program, the Stand-Alone Plan, the Restructuring Plan and the merger of
DQE with AYE. Such forward-looking statements involve known and unknown risks
and uncertainties that may cause the actual results and benefits to materially
differ from those implied by such statements. Such risks and uncertainties
include, but are not limited to, the final binding vote of PUC approvals
regarding the Stand-Alone Plan or the Restructuring Plan, general economic and
business conditions, industry capacity, changes in technology, integration of
the operations of AYE and DQE, regulatory conditions to the merger, the loss of
any significant customers, and changes in business strategy or development
plans.
Beaver Valley Power Station (BVPS) Steam Generators
BV Unit 1 went off-line January 30, 1998, due to an issue identified in a
technical review completed by Duquesne. BV Unit 2 went off-line December 16,
1997, to repair the emergency air supply system to the control room and has
remained off-line due to other issues identified by a technical review similar
to that performed at BV Unit 1. These technical reviews are in response to a
1997 commitment made by Duquesne to the NRC. Duquesne is one of many utilities
faced with similar issues, some of which date back to the initial start-up of
BVPS. Both BVPS units remain off-line for a reaffirmation of compliance with
technical specification requirements of various plant systems. Duquesne is
currently participating in a series of meetings with the NRC to review its
action plans. Both units are expected to remain off-line until the action plans
have been satisfactorily completed.
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 still have the capacity to
operate at 100 percent reactor power, although approximately 17 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 Duquesne's
responsibility. The earliest that the BV Unit 1 steam generators could be
replaced during a currently scheduled refueling outage is the spring of 2002.
Year 2000
Many existing computer programs use only two digits to identify a year (for
example, "98" is used to represent "1998"). Such programs read "00" as the year
1900, and thus may not recognize dates beginning with the year 2000, or may
otherwise produce erroneous results or cease processing when dates after 1999
are encountered. Such failures could cause disruptions in normal business
operations. Duquesne continues to implement its strategy, formulated in 1995,
to address required computer software changes and upgrades relating to such
operations, and currently believes that implementation of its plan will minimize
its Year 2000 issues relating to these systems. Duquesne's Year 2000 team,
comprised of management representatives from all functional areas of Duquesne,
also continues to explore and assess Duquesne's exposure to Year 2000-related
problems in devices and equipment containing embedded microprocessors that may
not correctly identify the year, as well as potential problems that may
originate with third parties outside Duquesne's control. Duquesne has authorized
the retention of a Year 2000 consultant to assist the Year 2000 team in its
assessments.
Given the fact that Duquesne's assessment, as noted above, is currently in
progress, Duquesne cannot currently estimate the exact extent of any outstanding
Year 2000 systems and equipment issues, the specific time frame in which any
required corrections would need to be made and the costs to Duquesne in
correcting any possible related outstanding matters. Until Duquesne's
assessment is completed, it cannot determine whether Year 2000 issues and
related costs will be material to Duquesne's operations, financial condition and
results of operations.
24
<PAGE>
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Funding for nuclear decommissioning costs is deposited by Duquesne in
external, segregated trust accounts and invested in a portfolio of corporate
common stock and debt securities, municipal bonds, certificates of deposit and
United States government securities. The market value of the aggregate trust
fund balances at March 31, 1998 totaled approximately $51.1 million. The amount
funded into the trusts is based on estimated returns which, if not achieved as
projected, could require additional unanticipated funding requirements.
______________________________
Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve a
number of risks and uncertainties, and actual results may differ materially.
Such forward-looking statements involve known and unknown risks, uncertainties
and other factors that may cause the actual results, performance or achievements
of Duquesne to be materially different from any future results, performance or
achievements expressed or implied by such forward-looking statements. Such
factors may affect Duquesne's operations, markets, products, services and
prices. Such factors include, among others, the following: general and
economic and business conditions; industry capacity; changes in technology;
changes in political, social and economic conditions; pending regulatory
decisions regarding industry restructuring in Pennsylvania; regulatory
conditions applicable to the pending merger; the loss of any significant
customers; and changes in business strategy or development plans.
25
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Eastlake Unit 5
In September 1995, Duquesne commenced arbitration against Cleveland
Electric Illuminating Company (CEI), seeking damages, termination of the
Operating Agreement for Eastlake Power Station Unit 5 (Unit) and partition of
the parties' interests in the Unit 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 the Unit; and the concealment by CEI of material
information. In October 1995, CEI commenced an action against Duquesne in the
Court of Common Pleas, Lake County, Ohio seeking to enjoin Duquesne from taking
any action to effect a partition on the basis of a waiver of partition contained
in the deed to the land underlying the Unit. CEI also seeks monetary damages
from Duquesne for alleged unpaid joint costs in connection with the operation of
the Unit. Duquesne removed the action to the United States District Court for
the Northern District of Ohio, Eastern Division, where it is now pending.
Duquesne anticipates that a trial will commence late in 1998.
Proposed Merger
In September 1997, the City of Pittsburgh filed a federal antitrust suit
seeking to prevent the merger of DQE and AYE and asking for monetary damages.
Although the United States District Court for the District of Western
Pennsylvania dismissed the suit in January 1998, the City filed an appeal and
asked for expedited review. Duquesne anticipates a decision on whether the
appeal has been granted during the second quarter of 1998.
Unless otherwise indicated, all information presented in this report
relates to Duquesne only and does not take into account the proposed merger
between DQE and AYE.
Item 6. Exhibits and Reports on Form 8-K.
a. Exhibits:
EXHIBIT 10.1 - Duquesne Light/DQE Charitable Giving Program, as amended to
date (included as Exhibit 10.1 to DQE's Quarterly Report on
Form 10-Q (File No. 1-10290) for the Quarterly Period ended
March 31, 1998, and incorporated herein by reference)
EXHIBIT 12.1 - Calculation of Ratio of Earnings to Fixed Charges
EXHIBIT 27.1 - Financial Data Schedule
b. A Current Report on Form 8-K was filed April 8, 1998, to report the March
25, 1998, recommended decisions regarding the proposed merger and the
restructuring plans by administrative law judges to the PUC. No financial
statements were filed with this report.
A Current Report on Form 8-K was filed April 16, 1998, to report the filing
of Duquesne's exceptions to the recommended decisions, and to incorporate
certain exhibits into a previously filed registration statement. No
financial statements were filed with this report.
______________________________
26
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
Duquesne Light Company
--------------------------------
(Registrant)
Date May 13, 1998 /s/ Gary L. Schwass
--------------------------- ---------------------------------
(Signature)
Gary L. Schwass
Senior Vice President and
Chief Financial Officer
Date May 13, 1998 /s/ Morgan K. O'Brien
--------------------------- ---------------------------------
(Signature)
Morgan K. O'Brien
Vice President and Controller
(Principal Accounting Officer)
27
<PAGE>
Exhibit 12.1
Duquesne Light Company and Subsidiary
Calculation of Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Year Ended December 31,
Ended -----------------------
March 31, 1998 1997 1996 1995 1994 1993
--------------- -------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $19,468 $ 81,592 $ 82,505 $ 89,139 $ 94,646 $102,938
Other interest 183 183 1,632 2,599 1,095 2,387
Monthly Income Preferred Securities dividend requirements 3,141 12,563 7,921 - - -
Amortization of debt discount, premium and expense - net 1,348 5,828 5,973 6,252 6,381 5,541
Portion of lease payments representing an interest factor 11,294 44,208 44,357 44,386 44,839 45,925
------- -------- -------- -------- -------- --------
Total Fixed Charges $35,434 $144,374 $142,388 $142,376 $146,961 $156,791
------- -------- -------- -------- -------- --------
EARNINGS:
Income from continuing operations $33,445 $141,819 $149,860 $151,070 $147,449 $144,787
Income taxes 14,118* 73,838* 83,008* 92,894* 84,191* 77,237*
Fixed charges as above 35,434 144,374 142,388 142,376 146,961 156,791
------- -------- -------- -------- -------- --------
Total Earnings $82,997 $360,031 $375,256 $386,340 $378,601 $378,815
------- -------- -------- -------- -------- --------
RATIO OF EARNINGS TO FIXED CHARGES 2.34 2.49 2.64 2.71 2.58 2.42
======= ======== ======== ======== ======== ========
</TABLE>
Duquesne's share of the fixed charges of an unaffiliated coal
supplier, which amounted to approximately $0.7 million for the three months
ended March 31, 1998, has been excluded from the ratio.
*Earnings related to income taxes reflect a $4.5 million decrease for the three
months ended March 31, 1998, and a $17 million, $12 million, $13.5 million,
$13.5 million and $10.4 million decrease for the twelve months ended December
31, 1997, 1996, 1995, 1994 and 1993, respectively, due to a financial statement
reclassification related to Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes. The ratio of earnings to fixed charges, absent
this reclassification, equals 2.48 for the three months ended March 31, 1998,
and 2.61, 2.72, 2.81, 2.67 and 2.48 for the twelve months ended December 31,
1997, 1996, 1995, 1994 and 1993, respectively.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> MAR-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,525,490
<OTHER-PROPERTY-AND-INVEST> 189,242
<TOTAL-CURRENT-ASSETS> 320,785
<TOTAL-DEFERRED-CHARGES> 717,410
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,752,927
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 833,895
<RETAINED-EARNINGS> 172,129
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,006,024
4,000
223,036<F1>
<LONG-TERM-DEBT-NET> 1,150,337
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 40,000
0
<CAPITAL-LEASE-OBLIGATIONS> 38,927
<LEASES-CURRENT> 21,856
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,268,747
<TOT-CAPITALIZATION-AND-LIAB> 3,752,927
<GROSS-OPERATING-REVENUE> 282,407
<INCOME-TAX-EXPENSE> 15,939
<OTHER-OPERATING-EXPENSES> 221,137
<TOTAL-OPERATING-EXPENSES> 237,076
<OPERATING-INCOME-LOSS> 45,331
<OTHER-INCOME-NET> 11,703
<INCOME-BEFORE-INTEREST-EXPEN> 57,034
<TOTAL-INTEREST-EXPENSE> 23,589<F2>
<NET-INCOME> 33,445
998
<EARNINGS-AVAILABLE-FOR-COMM> 32,447
<COMMON-STOCK-DIVIDENDS> 33,000
<TOTAL-INTEREST-ON-BONDS> 20,816
<CASH-FLOW-OPERATIONS> 80,637
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0.00
<FN>
<F1>INCLUDES $12,428 OF PREFERENCE STOCK
<F2>INCLUDES $3,141 OF MONTHLY INCOME PREFERRED SECURITIES DIVIDEND REQUIREMENTS
</FN>
</TABLE>
