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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 June 30, 1998
-----------------
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From __________ to __________
Commission File Number
----------------------
1-956
Duquesne Light Company
----------------------
(Exact name of registrant as specified in its charter)
Pennsylvania 25-0451600
------------ ----------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
-------------------------------
(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 June 30, 1998 and July 31, 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 Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
1998 1997 1998 1997
--------------- -------------- -------------- -------------
<S> <C> <C> <C> <C>
Operating Revenues
Sales of Electricity:
Customers - net $266,727 $251,786 $532,340 $517,135
Utilities 6,970 6,289 14,042 15,020
-------------- -------------- -------------- ---------------
Total Sales of Electricity 273,697 258,075 546,382 532,155
Other 10,886 14,201 20,608 23,130
-------------- -------------- -------------- ---------------
Total Operating Revenues 284,583 272,276 566,990 555,285
-------------- -------------- -------------- ---------------
Operating Expenses
Fuel and purchased power 71,575 50,516 131,108 102,170
Other operating 54,166 64,425 120,242 127,442
Maintenance 15,669 22,551 35,952 40,300
Depreciation and amortization 56,104 57,836 111,784 111,098
Taxes other than income taxes 19,363 19,521 38,928 39,765
Income taxes 21,888 12,136 37,827 34,177
-------------- -------------- -------------- ---------------
Total Operating Expenses 238,765 226,985 475,841 454,952
-------------- -------------- -------------- ---------------
OPERATING INCOME 45,818 45,291 91,149 100,333
-------------- -------------- -------------- ---------------
Other Income and Deductions 7,969 6,524 19,672 12,432
Income Before Interest and Other Charges
and Extraordinary Item 53,787 51,815 110,821 112,765
Interest Charges 20,086 21,518 40,535 42,913
Monthly Income Preferred Securities
Dividend Requirements 3,141 3,141 6,281 6,281
-------------- -------------- -------------- ---------------
INCOME Before Extraordinary Item 30,560 27,156 64,005 63,571
EXTRAORDINARY ITEM (NET OF TAXES) (82,548) -- (82,548) --
-------------- -------------- -------------- ---------------
NET INCOME (LOSS) After Extraordinary Item $(51,988) $ 27,156 $(18,543) $ 63,571
-------------- -------------- -------------- ---------------
DIVIDENDS ON PREFERRED AND
PREFERENCE STOCK 991 1,005 1,989 2,014
-------------- -------------- -------------- ---------------
EARNINGS (LOSS) FOR COMMON STOCK $(52,979) $ 26,151 $(20,532) $ 61,557
============== ============== ============== ===============
</TABLE>
See notes to condensed consolidated financial statements.
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DUQUESNE LIGHT COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
June 30, December 31,
1998 1997
---------------------- ---------------------
<S> <C> <C>
ASSETS
Property, plant and equipment $ 4,510,152 $ 4,510,738
Less: Accumulated depreciation and amortization (3,220,954) (1,947,819)
--------------------- --------------------
Property, plant and equipment - net 1,289,198 2,562,919
--------------------- --------------------
Long-term investments 186,980 186,564
--------------------- --------------------
Current assets:
Cash and temporary cash investments 163,867 165,169
Receivables 123,020 121,975
Other current assets, principally material and supplies 102,827 80,984
--------------------- --------------------
Total current assets 389,714 368,128
--------------------- --------------------
Other non-current assets:
Regulatory assets 2,272,292 680,885
Other 30,688 41,683
--------------------- --------------------
Total other non-current assets 2,302,980 722,568
--------------------- --------------------
TOTAL ASSETS $ 4,168,872 $ 3,840,179
===================== ====================
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock - $1 par value (shares - 90,000,000
authorized; 10 issued) $ -- $ --
Capital surplus 832,284 831,151
Retained earnings 95,151 172,682
--------------------- --------------------
Total common stockholder's equity 927,435 1,003,833
--------------------- --------------------
Preferred and preference stock 226,077 226,503
--------------------- --------------------
Long-term debt 1,258,398 1,218,276
--------------------- --------------------
Total capitalization 2,411,910 2,448,612
--------------------- --------------------
Obligations under capital leases 40,826 37,540
--------------------- --------------------
Current liabilities:
Current maturities and sinking fund requirements 68,465 97,523
Other current liabilities 127,453 154,955
--------------------- --------------------
Total current liabilities 195,918 252,478
--------------------- --------------------
Deferred income taxes - net 592,627 599,811
--------------------- --------------------
Deferred income 134,624 183,304
--------------------- --------------------
Beaver Valley lease liability 478,442 --
--------------------- --------------------
Other non-current liabilities 314,525 318,434
--------------------- --------------------
TOTAL CAPITALIZATION AND LIABILITIES $ 4,168,872 $ 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>
Six Months Ended
June 30,
--------
1998 1997
--------------- -----------------
<S> <C> <C>
Cash Flows From Operating Activities
Operations $219,070 $191,838
Changes in working capital other than cash (54,585) (32,888)
(Increase) decrease in ECR (19,219) 1,492
Other 2,507 (7,752)
----------------- ------------------
Net Cash Provided By Operating Activities 147,773 152,690
----------------- ------------------
Cash Flows From Investing Activities
Construction expenditures (34,621) (40,234)
Long-term investments (11,537) (6,826)
Other (1,025) 8,948
----------------- ------------------
Net Cash Used in Investing Activities (47,183) (38,112)
----------------- ------------------
Cash Flows From Financing Activities
Reductions of long-term obligations - net (36,938) (63,490)
Dividends on capital stock (59,451) (12,849)
Other (5,503) (802)
----------------- ------------------
Net Cash Used in Financing Activities (101,892) (77,141)
----------------- ------------------
Net (decrease) increase in cash and temporary cash investments (1,302) 37,437
Cash and temporary cash investments at beginning of period 165,169 154,414
----------------- ------------------
Cash and temporary cash investments at end of period $163,867 $191,851
================= ==================
Non-Cash Investing and Financing Activities
Capital lease obligations recorded $4,941 $ 4,086
================= ==================
</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.
As previously reported, in August 1997 the shareholders of DQE and
Allegheny Energy, Inc. (AYE), approved a proposed tax-free, stock-for-stock
merger, pursuant to which DQE would have become a wholly owned subsidiary of
AYE. On May 29, 1998, the Pennsylvania Public Utility Commission (PUC) issued
its final order (modified on July 23) approving the proposed merger, subject to
certain preconditions and stranded cost calculations. On July 28, DQE announced
its decision not to consummate the merger under the circumstances associated
with the final order. (See "Restructuring Plans and PUC Proceedings"
discussion, Note 2, 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 and six months ended
June 30, 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.
As a result of the PUC's final order regarding Duquesne's Stand-Alone Plan
and Merger Plan under the Customer Choice Act (see "Rate Matters", Note 2, on
page 6), the electricity generation portion of Duquesne's business no longer
meets the criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, application of SFAS No. 71 to this portion of Duquesne's business
has been 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) as interpreted by
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EITF 97-4, Deregulation of the Pricing of Electricity--Issues Related to the
Application of FASB Statements No. 71 and 101. Under SFAS No. 101, the
regulatory assets and liabilities of the generation portion of Duquesne are
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 final restructuring order, certain of Duquesne's
generation-related regulatory assets will 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 Duquesne's
business are evaluated in accordance with SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets to Be Disposed Of (SFAS No. 121). Under SFAS
No. 121, all but approximately $46 million of Duquesne's generating fixed assets
are impaired. Pursuant to the PUC's final restructuring order, with the
exception of certain disallowances, the above-market generation costs also will
be recovered through the CTC. Accordingly, these above-market costs have been
reclassified on the condensed consolidated balance sheet from "Property, plant
and equipment" to "Regulatory assets". To the extent that Duquesne is able to
recover more than $46 million through the divestiture of its generating plants,
any excess recovery will be applied to reduce the costs to be recovered through
the CTC. The electricity transmission and distribution portion of Duquesne's
business continues to meet the SFAS No. 71 criteria and accordingly reflects
regulatory assets and liabilities consistent with cost-based ratemaking
regulations. (See "Rate Matters", Note 2, below.)
Through the Energy Cost Rate Adjustment Clause (ECR), Duquesne recovered
(to the extent that such amounts were not included in base rates) nuclear fuel,
fossil fuel and purchased power expenses and, also through the ECR, passed to
its customers the profits from short-term power sales to other utilities
(collectively, ECR energy costs). As a consequence of the PUC's final orders
regarding Duquesne's Merger Plan and Stand-Alone Plan (see "Rate Matters", Note
2, below), such fuel costs are no longer recoverable through the ECR. Instead,
effective May 29, 1998 (the date of the PUC's final restructuring order), for
customers with bundled rates, fuel costs are expensed as incurred and impact net
income.
Under-recoveries from customers have been recorded on the condensed
consolidated balance sheet as a regulatory asset. At May 29, 1998, $42.7 million
was receivable from customers. Duquesne expects to recover this amount through
the CTC. (See "Restructuring Plans and PUC Proceedings", Note 2, on page 7.) At
December 31, 1997, $23.5 million was receivable from customers.
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 June
30, 1998, and December 31, 1997, were $29.1 million and $26.6 million ($17.0
million and $15.6 million net of tax, respectively).
2. 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.
6
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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).
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. The
28,000 customers participating in Duquesne's 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.
Although the pilot program was implemented, pursuant to the PUC's order, on
November 3, 1997, Duquesne earlier appealed the determination of the market
price of generation set forth in the PUC's order to the Commonwealth Court of
Pennsylvania. Argument has not yet been scheduled.
Phase-In to Competition
As required by the PUC in its restructuring orders (see "Restructuring
Plans and PUC Proceedings" discussion below), the phase-in to competition begins
in January 1999, when 66 percent of customers will have customer choice
(including customers covered by the pilot program); all customers will have
customer choice in January 2000. As of the date of this report, approximately 41
percent of Duquesne's customers had elected to participate in the customer
choice program beginning in January 1999. 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. 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 (capped at
current levels so long as a CTC is being collected). 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
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 bundled rates as long as transition costs are
being recovered, with certain exceptions. Duquesne requested recovery of
transition costs of approximately $1.9 billion, net of deferred taxes, beginning
January 1, 1999. Of this amount, $0.4 billion represented regulatory assets and
$1.5 billion represented potentially uneconomic plant and plant decommissioning
costs. Portions of the requested transition cost recovery have been disallowed
by the PUC in its final orders (discussed below).
Restructuring Plans and PUC Proceedings
On August 1, 1997, Duquesne filed its stand-alone restructuring plan
(Stand-Alone Plan) in the event the merger of DQE and AYE is not consummated,
and DQE and AYE filed their application to merge and restructuring plan (Merger
Plan). A more detailed discussion of each of these plans is set forth in the
Annual Reports on Form 10-K for the Year Ended December 31, 1997, of Duquesne
and DQE. On May 29, 1998, the PUC issued final orders on the Stand-Alone Plan
and Merger Plan. On June 18, Duquesne submitted its compliance filing, which
would implement the PUC's final order regarding the Stand-Alone Plan or the
Merger Plan, as the case may be. The
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compliance filing also included Duquesne's request that the PUC recalculate the
CTC and shopping credit determination set forth in the final orders; Duquesne
estimates that, correcting for computational errors, the 1999 average CTC should
be 2.73 cents per kilowatt-hour (KWH) (resulting in a shopping credit of 3.49
cents per KWH). Duquesne, DQE and AYE also petitioned the PUC to reconsider its
final restructuring orders. The PUC denied Duquesne's petition to reconsider its
Stand-Alone Plan final order, and recommended that any reconsideration could be
better addressed in Duquesne's compliance filing. The PUC accepted DQE's and
AYE's petition to reconsider the Merger Plan final order. The orders and
reconsideration are discussed below.
Order on the Stand-Alone Plan. With respect to stranded cost recovery, the
PUC's final order on the Stand-Alone Plan approves Duquesne's proposal to
auction its generating assets and use the proceeds to offset stranded costs. The
remaining balance of such costs (with certain exceptions described below) will
be recovered from ratepayers through a CTC, collectible through 2005. As
required, Duquesne will submit a divestiture plan to the PUC by August 27, 1998.
Duquesne has been ordered to use an interim system average CTC set at 2.9 cents
per KWH (resulting in a shopping credit of 3.75 cents per KWH), the rate
approved in its pilot program. The final CTC determined by the auction will
remain constant over the recovery period. The PUC's order approves the auction
only in the context of the Stand-Alone Plan, not the Merger Plan.
By conducting the auction, Duquesne expects to recover (through the auction
proceeds or the final CTC) or avoid the incurrence of all its stranded
generation costs, with the exception being a $65 million disallowance (net
present value, after tax) related to Duquesne's cold reserved units at the
Phillips Power Station and Brunot Island Power Station. The PUC's final order
also approves recovery of $339 million of the $357 million in regulatory assets
claimed by Duquesne. The disallowed regulatory assets relate primarily to
deferred coal costs under previously applied coal caps and deferred caretaker
costs associated with the cold reserved units.
At June 30, 1998, Duquesne recorded a charge to its earnings of $142.3
million ($82.5 million net of taxes) to reflect the disallowance associated with
the investments in cold reserved units and the disallowance of a portion of the
regulatory asset claim.
Order on the Merger Plan. The PUC's final order on the merger (as modified
during the reconsideration process) would allow the transaction to be
consummated but requires the parties to agree, prior to closing, to certain
conditions. The conditions relate to the mitigation of market power, including
membership in an independent system operator (ISO), an entity that would operate
the transmission facilities of Duquesne, AYE and other utilities in the region.
The PUC's final order would allow DQE and AYE to maintain their current
membership in the Midwest ISO, but the PUC held that the Midwest ISO must be
"fully functional" and it must satisfy seven criteria specified by the PUC no
later than June 30, 2000. In the meantime, the merged company would be required
to relinquish control of 570 megawatts of output from Duquesne's Cheswick Power
Station (Cheswick). Divestiture of a further 2,500 megawatts would be required
if, based on a PUC evaluation in January 2000, the merged company continued to
fail certain market power tests and the Midwest ISO had not progressed
sufficiently toward a structure that fully mitigates market power. The PUC
would determine what generation assets would be divested and who would be
eligible to bid for them. DQE objects to the PUC's having authority over all
aspects of the divestiture, particularly the lack of any provision to adjust
stranded costs following the divestiture. In addition, the Midwest ISO, as
presently constituted and as proposed to the FERC, does not meet the seven
criteria specified by the PUC.
The PUC's final order regarding the Merger Plan also addressed the recovery
of stranded costs by Duquesne and AYE's wholly owned utility subsidiary West
Penn Power Company (West Penn) in the event the merger is consummated. The order
sets stranded costs at approximately $1.3 billion, using an administrative
forecast of generation market values and costs. Applied to Duquesne, and
compared to the Stand-Alone Plan, this methodology results in the disallowance
of an additional $370 million in stranded costs (net present value, pre-tax).
The PUC's final order also reduces Duquesne's recoverable stranded costs by $152
million for estimated generation-related merger synergies and reduces
distribution rates beginning January 1, 2000, by $15 million annually to reflect
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estimated distribution-related merger synergies. The PUC's final order permits
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 4.00 cents per KWH).
With respect to West Penn, the PUC's final order disallows recovery of
approximately $1 billion of West Penn's stranded cost claim (net present value,
pre-tax). Of the disallowed amount, approximately $830 million relates to the
impact of the administrative determination of generation market value and costs.
The other disallowances relate to regulatory assets, non-utility generation and
other transition costs. In addition, the PUC's final order reduces West Penn's
recoverable stranded costs by $71 million for generation-related merger
synergies and reduces distribution rates beginning January 1, 2000, by $9
million for distribution-related merger synergies.
DQE Announcement. On July 28, 1998, DQE's Board of Directors concluded
that it could not consummate the merger under the circumstances described above.
On that same date, DQE informed AYE of this conclusion. More information
regarding this discussion is set forth in Duquesne's Current Report on Form 8-K
dated July 28, 1998.
On July 30, AYE informed DQE that it does not believe DQE has the right to
terminate the merger agreement under these circumstances, and that AYE will
continue to work toward consummation of the merger. AYE also stated it will
pursue all remedies available to protect the legal and financial interests of
AYE and its shareholders. With respect to the PUC's disallowance of
approximately $1 billion of stranded costs, AYE has filed an appeal in state
court and a complaint in federal court, challenging the order. In addition, a
settlement conference is scheduled for August 14 between AYE and the PUC
regarding the West Penn final order. Because various issues in West Penn's
restructuring order are related to Duquesne's Merger Plan (particularly with
respect to the recovery of stranded costs), and could impact DQE and its
shareholders, Duquesne plans to participate in the conference.
Regulatory Assets
As a result of the application of SFAS No. 71 to the transmission and
distribution portion of Duquesne's business, and as certain generation-related
costs will be recovered through the CTC collected in connection with the rate-
regulated portion of the business, 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.
Fixed assets related to the generation portion of Duquesne's business are
evaluated in accordance with SFAS No. 121. Under SFAS No. 121, all but
approximately $46 million of Duquesne's generating fixed assets are impaired.
Pursuant to the PUC's final restructuring order, with the exception of certain
disallowances, the above-market generation costs also will be recovered through
the CTC. Accordingly, these above-market costs have been reclassified on the
condensed consolidated balance sheet from "Property, plant and equipment" to
"Regulatory assets". (See Note 1.) As a result of the PUC's final restructuring
order, the BV Unit 2 lease costs will be recovered through the CTC. The lease
has been classified on the condensed consolidated balance sheet as a liability
with a corresponding regulatory asset.
The components of all regulatory assets for the periods presented are as
follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
June 30, December 31,
1998 1997
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------
<S> <C> <C>
Generation-related transition costs $2,156,626 $561,867
Transmission and distribution-related costs 115,666 119,018
- --------------------------------------------------------------------------------
Total Regulatory Assets $2,272,292 $680,885
- --------------------------------------------------------------------------------
</TABLE>
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3. RECEIVABLES
Components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
June 30, June 30, December 31,
1998 1997 1997
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 87,830 $ 88,314 $ 90,149
Other utility receivables 20,907 15,738 23,106
Other receivables 31,067 11,946 23,736
Less: Allowance for uncollectible accounts (16,784) (20,102) (15,016)
- --------------------------------------------------------------------------------------------------------------
Total Receivables $123,020 $ 95,896 $121,975
==============================================================================================================
</TABLE>
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 June 30, 1998, and June 30 and December
31, 1997, Duquesne had not sold any receivables to the unaffiliated corporation.
The accounts receivable sales agreement, which expires in June 1999, 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.
4. COMMITMENTS AND CONTINGENCIES
Duquesne currently anticipates divesting itself of its generating
assets and related obligations. (See "Order on the Stand-Alone Plan"
discussion, Note 2, on page 8.) Certain of those obligations, which currently
remain with Duquesne, are discussed below.
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 was not permitted to recover any potential shortfall in decommissioning
funding as part of either its Merger Plan or its Stand-Alone Plan. (See "Rate
Matters," Note 2, on page 6.)
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
June 30, 1998, totaled approximately $53.9 million.
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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 (increasing to $9.9 billion effective August 20, 1998). The maximum
available private primary insurance of $200 million has been purchased by
Duquesne. Additional protection of $8.7 billion (increasing to $9.7 billion)
would be provided by an assessment of up to $79.3 million (increasing to $88.1
million) per incident on each licensed nuclear unit in the United States.
Duquesne's maximum total possible assessment, $59.4 million (increasing to $66.1
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). 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 fall of 2001.
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 currently scheduled to begin in the spring of 2000; however, Duquesne
may be required to perform an earlier inspection of BV Unit 1's tubes and other
equipment during a mid-cycle outage in 1999, in order to comply with Nuclear
Regulatory Commission (NRC) requirements to conduct such inspections at BV Unit
1 at least every 20 months. Duquesne plans to inspect BV Unit 2's tubes during
the current forced outage in order to comply with
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NRC requirements to conduct such inspections at BV Unit 2 at least every 24
months. The next refueling outage for BV Unit 2 is currently scheduled to begin
in March 1999. 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 NRC. Duquesne is one of many utilities
faced with similar issues, some of which date back to the initial start-up of
BVPS. Duquesne has completed a series of meetings with the NRC to review its
action plans. As of the date of this report, BV Unit 1 is in its start-up mode
and is expected to be at full power shortly. Although BV Unit 2 is expected to
remain off-line until the action plans have been satisfactorily completed,
Duquesne and the NRC have been discussing proposed plans to return the unit to
service during the third quarter of 1998. The foregoing sentences contain
forward-looking statements (within the meaning of the Private Securities
Litigation Act of 1995). Actual results may differ materially from those implied
due to such risks as unforeseen mechanical difficulties arising in the normal
course of starting up the Units following the current outages, additional
technical specifications issues being identified, or unforeseen difficulties
arising as a consequence of the tube inspection at BV Unit 2.
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
United States Department of Energy (DOE) for the permanent disposal of spent
nuclear fuel and high-level radioactive waste in compliance with this
legislation. The DOE has indicated that its repository under these contracts
will not be available for acceptance of spent 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 and affirmed on rehearing May 5, 1998, 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.
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 June 30, 1998 and December 31, 1997, Duquesne's liability for
contributions was approximately $7.2 million (subject to an inflation
adjustment). (See "Rate Matters," Note 2, on page 6.)
Fossil Decommissioning
Based on studies conducted in 1997, the 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
unit's final operations. Duquesne was not permitted to recover these costs as
part of either its Merger Plan or its Stand-Alone Plan. (See "Rate Matters",
Note 2, on page 6.)
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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 June 30, 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
June 30, 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.
___________________________
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Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in
conjunction with 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 13 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.
As previously reported, in August 1997 the shareholders of DQE and
Allegheny Energy, Inc. (AYE), approved a proposed tax-free, stock-for-stock
merger, pursuant to which DQE would have become a wholly owned subsidiary of
AYE. On May 29, 1998, the Pennsylvania Public Utility Commission (PUC) issued
its final order (modified on July 23) approving the proposed merger, subject to
certain preconditions and stranded cost calculations. On July 28, DQE announced
its decision not to consummate the merger under the circumstances associated
with the final order. (See "Restructuring Plans and PUC Proceedings" discussion
on page 21.)
Service Territory
Duquesne provides electric service to customers in Allegheny County,
including the City of Pittsburgh, Beaver County and Westmoreland County. (See
"Rate Matters" on page 20.) 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 20.)
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.
As a result of the PUC's final order regarding Duquesne's Stand-Alone Plan and
Merger Plan under the Customer Choice Act (see "Rate Matters" on page 20), the
electricity generation portion of Duquesne's business no longer meets the
criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, application of SFAS No. 71 to this portion of Duquesne's business
has been 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) as interpreted by EITF 97-4, Deregulation of the Pricing
of Electricity--Issues Related to the Application of FASB Statements No. 71 and
101. Under SFAS No. 101, the regulatory assets and liabilities of the
generation portion of Duquesne are 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 final restructuring order,
certain of Duquesne's
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generation-related regulatory assets will 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 Duquesne's
business are evaluated in accordance with SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets to Be Disposed Of (SFAS No. 121). Under SFAS No.
121, all but approximately $46 million of Duquesne's generating fixed assets are
impaired. Pursuant to the PUC's final restructuring order, with the exception of
certain disallowances, the above-market generation costs also will be recovered
through the CTC. Accordingly, these above-market costs have been reclassified on
the condensed consolidated balance sheet from "Property, plant and equipment" to
"Regulatory assets". To the extent that Duquesne is able to recover more than
$46 million through the divestiture of its generating plants, any excess
recovery will be applied to reduce the costs to be recovered through the CTC.
The electricity transmission and distribution portion of Duquesne's business
continues to meet the SFAS No. 71 criteria and accordingly reflects regulatory
assets and liabilities consistent with cost-based 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. (See "Rate Matters" on page 20.)
Results of Operations
- --------------------------------------------------------------------------------
Earnings and Dividends
On May 29, 1998, the PUC issued an order related to each of Duquesne's
Merger Plan and Stand-Alone Plan. In June Duquesne recorded an extraordinary
charge (Restructuring Charge) against earnings for the stranded costs not
considered by the PUC's order to be recoverable from customers. Duquesne's
future financial condition and its future operating results are substantially
dependent upon the effects of competition. (See "Rate Matters" on page 20.)
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: In the
second quarter of 1998 Duquesne recognized a net loss in earnings for common
stock of $53.0 million due to the Restructuring Charge recorded in June 1998
for $142.3 million ($82.5 million net of tax). Earnings for common stock were
$26.2 million in the second quarter of 1997.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: For the
six months ended June 30, 1998, Duquesne's net loss in earnings for common stock
was $20.5 million and for the six months ended June 30, 1997, Duquesne's
earnings for common stock were $61.6 million. The reduction in earnings for
common stock for the six months ended June 30, 1998, can also be attributed to
the Restructuring Charge.
Revenues
Total operating revenues in the second quarter of 1998 increased $12.3
million or 4.5 percent as compared to the second quarter of 1997. Total
operating revenues in the six months ended June 30, 1998, increased $11.7
million or 2.1 percent as compared to the six months ended June 30, 1997.
<TABLE>
<CAPTION>
------------------------------------------------------------
(Revenues in Millions of Dollars) Increase(Decrease) from Prior Year
------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, 1998 June 30, 1998
------------------------------------------------------------
Bundled Bundled
KWH Revenues KWH Revenues
------------------------------------------------------------
<S> <C> <C> <C> <C>
Residential (1.4)% $ 4.6 (4.8)% $ 3.6
Commercial (0.2)% 8.9 (3.8)% 8.3
Industrial (4.0)% 1.4 0.1% 3.2
Less: Provision for Doubtful Accounts 0.0 0.0
- --------------------------------------------------------------------------------------------------------
Sales to Electric Utility Customers (1.6)% 14.9 (3.0)% 15.1
- --------------------------------------------------------------------------------------------------------
Sales to Other Utilities (9.2)% 0.7 (19.0)% (0.9)
Other Revenues (3.3) (2.5)
- --------------------------------------------------------------------------------------------------------
Total Sales (2.5)% $12.3 (5.0)% $11.7
========================================================================================================
</TABLE>
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Sales of Electricity to Customers
Operating revenues are primarily derived from Duquesne's sales of
electricity. Previously, the PUC authorized rates for electricity sales that
were cost-based and were designed to recover Duquesne's operating expenses and
investment in electric utility assets and to provide a return on the investment.
On May 29, 1998, the PUC unbundled charges for transmission, distribution,
generation and a CTC for customers who are eligible to choose their generation
supplier. Transmission and distribution rates are subject to a rate cap through
June 2001. Under the PUC's final order regarding the Stand-Alone Plan,
Duquesne's CTC will be adjusted to reflect the proceeds from the divestiture of
its generating assets. Generation rates are unregulated and will fluctuate
based upon competitive factors. For customers who are not yet eligible to
choose their generation supplier, fully-bundled, cost-based rates will continue
to be charged. Under prior fuel cost recovery provisions, fuel revenues
generally equaled fuel expense as the costs were recoverable from customers
through the Energy Cost Rate Adjustment Clause (ECR), including the fuel
component of purchased power, and did not affect net income. Beginning May 29,
1998, for customers with bundled rates, fuel costs are expensed as incurred and
will now have an impact on net income to the extent fuel costs exceed recovery
amounts included in Duquesne's previously authorized rates. Beginning May 29,
1998, customer revenues fluctuate as a result of changes in sales volume. (See
"Rate Matters" on page 20.)
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.
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: In the
second quarter of 1998, net customer revenues reflected on the statement of
consolidated income increased by $14.9 million to $266.7 million from the second
quarter of 1997. The variance can be attributed to an increase in energy costs,
prior to the May 29, 1998 restructuring order, partially offset by a 1.6 percent
decrease in kilowatt-hour (KWH) sales to bundled electric utility customers.
Residential and commercial bundled sales decreased 13,223 KWH or 0.6 percent
when comparing the second quarter of 1998 and the second quarter of 1997. Due
to the implementation of the pilot program in November 1997, a reduction in
bundled electric utility customer sales resulted. Additionally, in response to
requirements of the retail customer choice, Duquesne completed a review of its
customer categorization during the second quarter of 1998. As a result,
approximately 400 customers were moved from the "industrial" to the "commercial"
category based upon historical maximum billed demand and Standard Industrial
Classification Codes. The change in categorization represents the reason for
the fluctuation in industrial sales.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: Net
customer revenues increased $15.2 million or 2.9 percent in the six months ended
June 30, 1998, as compared to the same period in 1997. The variance can be
attributed primarily to increased energy costs, prior to the May 29, 1998
restructuring order, partially offset by decreased bundled electric utility
customer KWH sales due to the implementation of the pilot program.
Additionally, in response to requirements of the retail customer choice,
Duquesne completed a review of its customer categorization during the second
quarter of 1998. As a result, approximately 400 customers were moved from the
"industrial" to the "commercial" category based upon historical maximum billed
demand and Standard Industrial Classification Codes. The change in
categorization represents the reason for the decrease in industrial sales, which
was offset by sales to a new customer, an industrial gas supplier.
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 and Duquesne's divestiture plan.
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Comparison of Three Months Ended June 30, 1998, and June 30, 1997:
Duquesne's electricity sales to other utilities in the second quarter of 1998
were $0.7 million or 10.8 percent greater than in the second quarter of 1997 due
to increased power market prices. This increase was offset by lower sales
volume due to reduced generating station availability as a result of an increase
in outage hours in 1998.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: In the
six months ended June 30, 1998, Duquesne's electricity sales to other utilities
were $0.9 million or 6.5 percent less than in the six months ended June 30,
1997, due to reduced generating station availability as a result of a 24.8
percent increase in outage hours in 1998. Partially offsetting this decrease
were increases due to power market prices in 1998.
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 the timing of scheduled
refueling and maintenance outages at BVPS when significant costs are incurred.
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: The
other operating revenue decrease of $3.3 million or 23.3 percent when comparing
the second quarter of 1998 and the second quarter of 1997 was primarily the
result of decreased administrative and general costs billed to the joint owners
of BV Unit 1 and BV Unit 2 due to the outages at those units. (See "Beaver
Valley Power Station" on page 22.)
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: The
decrease of $2.5 million or 10.9 percent in other operating revenues in the six
months ended June 30, 1998, as compared to the six months ended June 30, 1997,
is primarily due to decreased administrative and general costs billed to the
joint owners of BV Unit 1 and BV Unit 2 due to the outages at those units. (See
"Beaver Valley Power Station" on page 22.)
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 April or
May of 1998 or the second quarter of 1997. Beginning May 29, 1998, fuel costs
for bundled customers are being expensed as incurred and will now have an impact
on net income to the extent fuel costs exceed recovery amounts included in
Duquesne's previously authorized bundled rates. (See "Rate Matters" on page 20.)
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: Fuel
and purchased power expense increased $21.1 million or 41.7 percent in the
second quarter of 1998 as compared to the second quarter of 1997. The increase
resulted from higher energy costs of $23.5 million or 48.8 percent due to an
unfavorable power supply mix and higher purchased power prices. The increase
was partially offset by a $2.4 million decrease in energy volume supplied
primarily due to lower sales from the pilot program. Reduced availability of
generating stations due to an increase in outage hours forced Duquesne to
purchase power and generate power from the higher fuel cost fossil stations.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: The $28.9
million or 28.3 percent increase in fuel and purchased power expense for the six
months ended June 30, 1998, as compared to the six months ended June 30, 1997,
was the result of increased energy costs of $35.3 million or 36.9 percent due to
an unfavorable power supply mix and higher purchased power prices. Energy
volume supplied resulted in a $6.4 million reduction in fuel and purchased power
expenses primarily due to lower sales from the pilot program. Reduced
availability of generating stations due to a 24.8 percent increase in outage
hours forced Duquesne to purchase power and generate power from the higher fuel
cost fossil stations.
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BV Unit 1 and BV Unit 2 have continued to be off-line into the third
quarter. These outages, combined with various fossil station outages, have
caused Duquesne to continue to purchase larger than normal quantities of
electricity. Additionally, the market price for purchased power continues to be
higher than traditional levels. As a result of these higher costs and the
discontinuance of the ECR, fuel costs are expected to have a negative impact on
third quarter earnings. This impact has been partially mitigated by the fact
that during the second quarter of 1998 Duquesne entered into fixed-price firm
replacement power contracts.
Other Operating Expense
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: Other
operating expenses decreased $10.3 million or 15.9 percent in the second
quarter of 1998 as compared to the second quarter of 1997. As a result of the
PUC's final restructuring order, the BV Unit 2 lease costs will be recovered
through the CTC. The lease has been classified on the condensed consolidated
balance sheet as a liability with a corresponding regulatory asset. Due to this
recharacterization, certain BV Unit 2 lease costs are reflected as amortization
expense, resulting in reduced levels of other operating expenses. The decrease
was partially offset by increased labor and outside service costs related to the
outages at the BV units.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: Other
operating expenses decreased $7.2 million or 5.6 percent when comparing the six
months ended June 30, 1998, to the same period for 1997. As a result of the
PUC's final restructuring order, the BV Unit 2 lease costs will be recovered
through the CTC. The lease has been classified on the condensed consolidated
balance sheet as a liability with a corresponding regulatory asset. Due to this
recharacterization, certain BV Unit 2 lease costs are reflected as amortization
expense, resulting in reduced levels of other operating expenses. The decrease
was partially offset by increased labor and outside service costs related to the
outages at the BV units.
Maintenance Expense
Comparison of Three Months Ended June 30, 1998, and June 30, 1997:
Maintenance expense decreased $6.9 million or 30.5 percent when comparing the
second quarter of 1998 to the same period in 1997. The decrease is primarily
attributable to the timing of the Cheswick Power Station (Cheswick) maintenance
outage costs. Additionally, Elrama Power Station (Elrama) costs for scrubber
outages in 1997 were approximately $1.0 million. Partially offsetting the 1998
decreases were higher costs for tree trimming and storm-related maintenance of
overhead lines of $1.5 million.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997:
Maintenance expense decreased $4.3 million or 10.8 percent when comparing the
six months ended June 30, 1998, to the same period in 1997. The decrease is
primarily attributable to the timing of the Cheswick maintenance outage costs
and reduced nuclear station outage cost amortization in 1998. Partially
offsetting the 1998 decreases were higher costs for tree trimming and storm-
related maintenance of overhead lines of $3.3 million. Additionally Elrama had
higher costs in 1997 due to scrubber outages for approximately $1.0 million.
Income Taxes
Income taxes were higher in 1998 as compared to 1997 for both the three and
six months ended June 30 by $9.8 million and $3.7 million, respectively. The
variances were the result of the effect of higher pre-tax income in 1998.
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.
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: A $1.4
million or 22 percent increase in other income in the second quarter of 1998 as
compared to the second quarter of 1997 resulted from long-term investment
income. The greater long-term investment income was the result of investments
made throughout 1997.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: A $7.2
million or 58 percent increase in other income in the first six months of 1998
as compared to the first six months
18
<PAGE>
of 1997 resulted from long-term investment income. The greater long-term
investment income was the result of investments made throughout 1997.
Interest Charges
Comparison of Three Months Ended June 30, 1998, and June 30, 1997:
Interest and other charges decreased $1.4 million or 6.7 percent during the
second quarter of 1998 as compared to the second quarter of 1997. The decrease
was primarily the result of the refinancing of long-term debt at lower interest
rates and the maturity of approximately $100 million of long-term debt
subsequent to the second quarter of 1997.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: The
decrease in interest and other charges in the six months ended June 30, 1998
from the six months ended June 30, 1997, was $2.4 million or 5.5 percent. The
reason for the decrease in 1998 was primarily the result of the refinancing of
long-term debt at lower interest rates and approximately $100 million of long-
term debt maturities subsequent to the six months ended June 30, 1997.
Restructuring Charge
On May 29, 1998, the PUC issued its final order related to each of
Duquesne's Merger Plan and Stand-Alone Plan. In June Duquesne recorded the
Restructuring Charge against earnings for the stranded costs not considered by
the PUC's Order to be recoverable from customers. The Restructuring Charge
included Phillips Power Station, BI Power Station, deferred caretaker costs
related to the two stations and deferred coal costs for a total of $142.3
million ($82.5 million net of tax).
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 June 30, 1998, Duquesne was in compliance with all of its debt
covenants.
During 1998, $70 million of mortgage bonds matured and were retired and
$100 million of 8.75 percent mortgage bonds due in May 2022 were redeemed. The
retirement and redemption were financed using available cash, the proceeds of
the $40 million of 6.45 percent mortgage bonds due in February 2008 and the
proceeds of the $100 million of 7 3/8 percent mortgage bonds due in April 2038
issued by Duquesne. Mortgage bonds in the amount of $5 million will mature in
November 1998. Duquesne expects to retire these bonds with available cash or to
refinance the bonds. (See "Rate Matters" on page 20.)
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. During the second quarter, the accounts
receivable sale arrangement was extended through June 1999. 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 June 30, 1998.
Investing
- --------------------------------------------------------------------------------
Duquesne's long-term investments consist of Duquesne's holdings of DQE
common stock, investments in affordable housing, lease investments, alternative
energy investments and nuclear decommissioning trust funds. Duquesne invested
approximately $5 million in alternative energy investments in the first six
months of 1998. $5 million was invested in nuclear decommissioning trust funds
during the six months ended June 30, 1998 and June 30, 1997. The remaining $2
million for the six months ended June 30, 1998 and 1997 was invested in other
investments.
19
<PAGE>
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).
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. The
28,000 customers participating in Duquesne's 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.
Although the pilot program was implemented, pursuant to the PUC's order, on
November 3, 1997, Duquesne earlier appealed the determination of the market
price of generation set forth in the PUC's order to the Commonwealth Court of
Pennsylvania. Argument has not yet been scheduled.
Financial Impact of Pilot Program Order
During the first six months of 1998, the net financial impact of Duquesne's
customers' choosing alternative generation suppliers was a reduction of
operating revenues of approximately $12 million. It is anticipated that the
level during the remainder of the year should be consistent with that level.
The net income impact has been a reduction of $6 million for the first six
months of 1998.
Phase-In to Competition
As required by the PUC in its restructuring orders (see "Restructuring Plans
and PUC Proceedings" discussion on page 21), the phase-in to competition begins
in January 1999, when 66 percent of customers will have customer choice
(including customers covered by the pilot program); all customers will have
customer choice in January 2000. As of the date of this report, approximately 41
percent of Duquesne's customers had elected to participate in the customer
choice program beginning in January 1999. 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. 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 (capped at
current levels so long as a CTC is being collected). Delivery of electricity
(including transmission, distribution and customer service) will continue to be
regulated in substantially the same manner as under current regulation.
20
<PAGE>
Rate Cap
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 bundled rates as long as transition costs are
being recovered, with certain exceptions.
Restructuring Plans and PUC Proceedings
On August 1, 1997, Duquesne filed its stand-alone restructuring plan
(Stand-Alone Plan) in the event the merger of DQE and AYE is not consummated,
and DQE and AYE filed their application to merge and restructuring plan (Merger
Plan). A more detailed discussion of each of these plans is set forth in the
Annual Reports on Form 10-K for the Year Ended December 31, 1997, of Duquesne
and DQE. On May 29, 1998, the PUC issued final orders on the Stand-Alone Plan
and Merger Plan. On June 18, Duquesne submitted its compliance filing, which
would implement the PUC's final order regarding the Stand-Alone Plan or the
Merger Plan, as the case may be. The compliance filing also included Duquesne's
request that the PUC recalculate the CTC and shopping credit determination set
forth in the final orders; Duquesne estimates that, correcting for computational
errors, the 1999 average CTC should be 2.73 cents per kilowatt-hour (KWH)
(resulting in a shopping credit of 3.49 cents per KWH). Duquesne, DQE and AYE
also petitioned the PUC to reconsider its final restructuring orders. The PUC
denied Duquesne's petition to reconsider its Stand-Alone Plan final order, and
recommended that any reconsideration could be better addressed in Duquesne's
compliance filing. The PUC accepted DQE's and AYE's petition to reconsider the
Merger Plan final order. The orders and reconsideration are discussed below.
Order on the Stand-Alone Plan. With respect to stranded cost recovery, the
PUC's final order on the Stand-Alone Plan approves Duquesne's proposal to
auction its generating assets and use the proceeds to offset stranded costs. The
remaining balance of such costs (with certain exceptions described below) will
be recovered from ratepayers through a CTC, collectible through 2005. As
required, Duquesne will submit a divestiture plan to the PUC by August 27, 1998.
Duquesne has been ordered to use an interim system average CTC set at 2.9 cents
per KWH (resulting in a shopping credit of 3.75 cents per KWH), the rate
approved in its pilot program. The final CTC determined by the auction will
remain constant over the recovery period. The PUC's order approves the auction
only in the context of the Stand-Alone Plan, not the Merger Plan.
By conducting the auction, Duquesne expects to recover (through the auction
proceeds or the final CTC) or avoid the incurrence of all its stranded
generation costs, with the exception being a $65 million disallowance (net
present value, after tax) related to Duquesne's cold reserved units at the
Phillips Power Station and Brunot Island Power Station. The PUC's final order
also approves recovery of $339 million of the $357 million in regulatory assets
claimed by Duquesne. The disallowed regulatory assets relate primarily to
deferred coal costs under previously applied coal caps and deferred caretaker
costs associated with the cold reserved units.
At June 30, 1998, Duquesne recorded a charge to its earnings of $142.3
million ($82.5 million net of taxes) to reflect the disallowance associated with
the investments in cold reserved units and the disallowance of a portion of the
regulatory asset claim.
Order on the Merger Plan. The PUC's final order on the merger (as modified
during the reconsideration process) would allow the transaction to be
consummated but requires the parties, prior to closing, to agree to certain
conditions. The conditions relate to the mitigation of market power, including
membership in an independent system operator (ISO), an entity that would operate
the transmission facilities of Duquesne, AYE and other utilities in the region.
The PUC's final order would allow DQE and AYE to maintain their current
membership in the Midwest ISO, but the PUC held that the Midwest ISO must be
"fully functional" and it must satisfy seven criteria specified by the PUC no
later than June 30, 2000. In the meantime, the merged company would be required
to relinquish control of 570 megawatts of output from Duquesne's Cheswick Power
Station (Cheswick). Divestiture
21
<PAGE>
of a further 2,500 megawatts would be required if, based on a PUC evaluation in
January 2000, the merged company continued to fail certain market power tests
and the Midwest ISO had not progressed sufficiently toward a structure that
fully mitigates market power. The PUC would determine what generation assets
would be divested and who would be eligible to bid for them. DQE objects to the
PUC's having authority over all aspects of the divestiture, particularly the
lack of any provision to adjust stranded costs following the divestiture. In
addition, the Midwest ISO, as presently constituted and as proposed to the FERC,
does not meet the seven criteria specified by the PUC.
The PUC's final order regarding the Merger Plan also addressed the recovery
of stranded costs by Duquesne and AYE's wholly owned utility subsidiary West
Penn Power Company (West Penn) in the event the merger is consummated. The order
sets stranded costs at approximately $1.3 billion, using an administrative
forecast of generation market values and costs. Applied to Duquesne, and
compared to the Stand-Alone Plan, this methodology results in the disallowance
of an additional $370 million in stranded costs (net present value, pre-tax).
The PUC's final order also reduces Duquesne's recoverable stranded costs by $152
million for estimated generation-related merger synergies and reduces
distribution rates beginning January 1, 2000, by $15 million annually to reflect
estimated distribution-related merger synergies. The PUC's final order permits
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 4.00 cents per KWH).
With respect to West Penn, the PUC's final order disallows recovery of
approximately $1 billion of West Penn's stranded cost claim (net present value,
pre-tax). Of the disallowed amount, approximately $830 million relates to the
impact of the administrative determination of generation market value and costs.
The other disallowances relate to regulatory assets, non-utility generation and
other transition costs. In addition, the PUC's final order reduces West Penn's
recoverable stranded costs by $71 million for generation-related merger
synergies and reduces distribution rates beginning January 1, 2000, by $9
million for distribution-related merger synergies.
DQE Announcement. On July 28, 1998, DQE's Board of Directors concluded
that it could not consummate the merger under the circumstances described above.
On that same date, DQE informed AYE of this conclusion. More information
regarding this discussion is set forth in Duquesne's Current Report on Form 8-K
dated July 28, 1998.
On July 30, AYE informed DQE that it does not believe DQE has the right to
terminate the merger agreement under these circumstances, and that AYE will
continue to work toward consummation of the merger. AYE also stated it will
pursue all remedies available to protect the legal and financial interests of
AYE and its shareholders. With respect to the PUC's disallowance of
approximately $1 billion of stranded costs, AYE has filed an appeal in state
court and a complaint in federal court, challenging the order. In addition, a
settlement conference is scheduled for August 14 between AYE and the PUC
regarding the West Penn final order. Because various issues in West Penn's
restructuring order are related to Duquesne's Merger Plan (particularly with
respect to the recovery of stranded costs), and could impact DQE and its
shareholders, Duquesne plans to participate in the conference.
Beaver Valley Power Station (BVPS)
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. Duquesne has completed a series of meetings with the NRC to review its
action plans. As of the date of this report, BV Unit 1 is in its start-up mode
and is expected to be at full power shortly. Although BV Unit 2 is expected to
remain off-line until the action plans have been satisfactorily completed,
Duquesne and the NRC have been discussing proposed plans to return the unit to
service during the third quarter of 1998. The foregoing sentences contain
forward-looking statements
22
<PAGE>
(within the meaning of the Private Securities Litigation Act of 1995). Actual
results may differ materially from those implied due to such risks as unforeseen
mechanical difficulties arising in the normal course of starting up the units
following the current outages, additional technical specifications issues being
identified, or unforeseen difficulties arising as a consequence of the tube
inspection at BV Unit 2.
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 fall of 2001.
Year 2000
Many existing computer programs and embedded microprocessors 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 such as, among other things,
communicating with customers and vendors, calculating and processing bills and
payments, reading meters, managing and operating generating stations, operating
substations and distribution circuits, and maintaining internal financial and
accounting systems.
In 1994, Duquesne began reviewing its critical information systems that
impact operations and financial reporting in order to develop a strategy to
address required computer software and system changes and upgrades. Duquesne
has since assembled a Year 2000 team, comprised of management representatives
from all functional areas of Duquesne, which continues to explore the exposure
to Year 2000-related problems in computer software and 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. In general, Duquesne's overall strategy to address the Year
2000 issues is comprised of four components, which may overlap and be conducted
simultaneously: inventory, assessment, remediation and testing and
implementation. Inventory consists of identifying the various systems,
components, equipment and third parties used in Duquesne's operations which may
be faced with Year 2000 issues. Duquesne has been performing the inventory
since the plan's inception, and expects to complete this portion during the
fourth quarter of 1998. Assessment consists of evaluating the inventoried items
for Year 2000 compliance by, among other things, contacting vendors (Duquesne
has already submitted questionnaires to its vendors), inspecting software code
and data, and testing high priority items. Assessment is expected to be complete
during the fourth quarter of 1998. During remediation, Duquesne will apply the
solution selected for an item (e.g., whether to replace a product, employ a
software upgrade, or revise existing software code). Duquesne expects to
complete remediation during the first quarter of 1999. Testing and
implementation will consist of placing the renovated processes, systems,
equipment and other items into use within Duquesne's operations. Duquesne
expects this portion to take place during the first two quarters of 1999.
Duquesne currently believes that implementation of its plan will minimize
the Year 2000 issues relating to its systems and equipment. Duquesne has not yet
identified the need for contingency plans in the event any part of its overall
strategy should fail adequately to address the Year 2000 problem. However,
Duquesne believes that the methodology and timetables incorporated into its
strategy will ensure that should contingency plans become necessary, they will
be developed on a timely basis. Duquesne has retained a Year 2000 consultant to
assist the Year 2000 team in the
23
<PAGE>
planning, organization and management of its efforts. Duquesne also participates
in the Electric Power Research Institute's project to share information about
technical issues regarding the Year 2000 problem with other utilities in the
electric utility industry.
The costs to date of Duquesne's plan, primarily incurred as a result of
software and system changes and upgrades, have been approximately $35 million,
of which approximately $31million will be capitalized since those costs are
attributable to the purchase of new software for total system replacements
(i.e., the Year 2000 solution comprises only a portion of the benefit resulting
from such replacements). Given the fact that the various aspects of Duquesne's
strategy, as noted above, are currently in progress, Duquesne cannot estimate
the exact extent of any outstanding Year 2000 systems and equipment issues or
the ultimate 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.
The foregoing paragraphs contain forward-looking statements (within the
meaning of the Private Securities Litigation Reform Act of 1995) regarding the
timetable and effectiveness of Duquesne's Year 2000 strategy. Actual results
could materially differ from those implied by such statements due to known and
unknown risks and uncertainties. Such risks and uncertainties include, but are
not limited to, the possibility that changes and upgrades are not timely
completed, that corrections to the systems of other companies on which
Duquesne's systems rely may not be timely completed, and that such changes and
upgrades may be incompatible with Duquesne's systems; the availability and cost
of trained personnel; and the ability to locate and correct all relevant
computer code and microprocessors. There can be no guarantee that such risks
would not have a material adverse impact on Duquesne. The costs associated with
this potential impact are speculative and not currently quantifiable.
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 June 30, 1998 totaled approximately $53.9 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: DQE's decision not to
consummate the merger with AYE under the current circumstances; Duquesne's
upcoming plan to auction its generating assets; 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; the loss of any significant
customers; and changes in business strategy or development plans.
24
<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 trial is currently
scheduled to begin February 1, 1999.
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, which
was dismissed by the U.S. Court of Appeals for the Third Circuit on June 12,
1998. The City petitioned for a rehearing, but on July 8 entered into a
settlement agreement with AYE, pursuant to which the City has dropped its suit
and withdrawn its objections to the proposed merger.
Item 6. Exhibits and Reports on Form 8-K.
a. Exhibits:
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 June 12, 1998, to report the PUC's
final orders regarding the proposed merger and the restructuring plans. No
financial statements were filed with this report.
A Current Report on Form 8-K was filed July 28, 1998, to report a letter
from David D. Marshall to Alan J. Noia, and included the DQE, Inc. Earnings
Release for the quarter ended June 30, 1998.
______________________________
25
<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 August 14, 1998 /s/ Gary L. Schwass
--------------------- -------------------------------
(Signature)
Gary L. Schwass
Senior Vice President and
Chief Financial Officer
Date August 14, 1998 /s/ Morgan K. O'Brien
---------------------- ------------------------------
(Signature)
Morgan K. O'Brien
Vice President and Controller
(Principal Accounting Officer)
26
<PAGE>
Exhibit 12.1
Duquesne Light Company and Subsidiary
Calculation of Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
Six Months Ended -----------------------------------------------------------------
June 30, 1998 1997 1996 1995 1994 1993
---------------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $ 38,220 $ 81,592 $ 82,505 $ 89,139 $ 94,646 $102,938
Other interest 584 752 1,632 2,599 1,095 2,387
Monthly Income Preferred Securities
dividend requirements 6,281 12,562 7,921 - - -
Amortization of debt discount, premium
and expense - net 2,682 5,828 5,973 6,252 6,381 5,541
Portion of lease payments representing
an interest factor 22,773 44,208 44,357 44,386 44,839 45,925
------------- --------- --------- --------- --------- ---------
Total Fixed Charges $ 70,540 $144,942 $142,388 $142,376 $146,961 $156,791
------------- --------- --------- --------- --------- ---------
EARNINGS:
Income from continuing operations $ 64,005 $141,820 $149,860 $151,070 $147,449 $144,787
Income taxes 41,538* 73,838* 83,008* 92,894* 84,191* 77,237*
Fixed Charges as above 70,540 144,943 142,388 142,376 146,961 156,791
------------- --------- --------- --------- --------- ---------
Total Earnings $176,083 $360,601 $375,256 $386,340 $378,601 $378,815
------------- --------- --------- --------- --------- ---------
RATIO OF EARNINGS TO FIXED CHARGES 2.50 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 $1.3 million for the six months ended June 30,
1998, has been excluded from the ratio.
* Earnings related to income taxes reflect a $9.0 million decrease for the six
months ended June 30, 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 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 2.62 for the six months ended June 30, 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> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> JUN-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,289,198
<OTHER-PROPERTY-AND-INVEST> 186,980
<TOTAL-CURRENT-ASSETS> 389,714
<TOTAL-DEFERRED-CHARGES> 2,302,980
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,168,872
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 832,284
<RETAINED-EARNINGS> 95,151
<TOTAL-COMMON-STOCKHOLDERS-EQ> 927,435
3,000
223,077<F1>
<LONG-TERM-DEBT-NET> 1,258,398
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 47,703
0
<CAPITAL-LEASE-OBLIGATIONS> 40,826
<LEASES-CURRENT> 20,762
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,647,671
<TOT-CAPITALIZATION-AND-LIAB> 4,168,872
<GROSS-OPERATING-REVENUE> 566,990
<INCOME-TAX-EXPENSE> 37,827
<OTHER-OPERATING-EXPENSES> 438,014
<TOTAL-OPERATING-EXPENSES> 475,841
<OPERATING-INCOME-LOSS> 91,149
<OTHER-INCOME-NET> 19,672
<INCOME-BEFORE-INTEREST-EXPEN> 110,821
<TOTAL-INTEREST-EXPENSE> 46,816<F2>
<NET-INCOME> 64,005<F3>
1,989
<EARNINGS-AVAILABLE-FOR-COMM> 62,016<F3>
<COMMON-STOCK-DIVIDENDS> 57,000
<TOTAL-INTEREST-ON-BONDS> 40,902
<CASH-FLOW-OPERATIONS> 147,773
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0.00
<FN>
<F1>Includes $12,470 of Preference Stock
<F2>Includes $6,281 of Monthly Income Preferred Securities Dividend Requirements
<F3>Excludes $82,548 extraordinary restructuring charge (net of taxes)
</FN>
</TABLE>
