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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 September 30, 1998
----------------------
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From to
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Commission File Number
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1-956
Duquesne Light Company
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-0451600
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
-------------------------------
(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 September 30, 1998 and October 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 Nine Months Ended
September 30, September 30,
------------------------------- ----------------------------------
1998 1997 1998 1997
------------ ------------ ------------- -------------
<S> <C> <C> <C> <C>
Operating Revenues
Sales of Electricity:
Customers - net $ 301,221 $ 307,113 $ 833,561 $ 824,248
Utilities 10,722 6,212 24,764 21,232
------------ ------------ ------------- -------------
Total Sales of Electricity 311,943 313,325 858,325 845,480
Other 11,984 9,513 32,592 32,643
------------ ------------ ------------- -------------
Total Operating Revenues 323,927 322,838 890,917 878,123
------------ ------------ ------------- -------------
Operating Expenses
Fuel and purchased power 85,335 63,031 216,443 165,201
Other operating 65,010 62,337 185,252 189,779
Maintenance 23,321 21,229 59,273 61,529
Depreciation and amortization 39,663 60,493 151,447 171,591
Taxes other than income taxes 21,174 21,140 60,102 60,905
Income taxes 26,243 29,835 64,070 64,012
------------ ------------ ------------- -------------
Total Operating Expenses 260,746 258,065 736,587 713,017
------------ ------------ ------------- -------------
OPERATING INCOME 63,181 64,773 154,330 165,106
------------ ------------ ------------- -------------
Other Income and Deductions 8,251 6,028 27,923 18,460
Income Before Interest and Other Charges
and Extraordinary Item 71,432 70,801 182,253 183,566
Interest Charges 20,048 21,586 60,583 64,499
Monthly Income Preferred Securities
Dividend Requirements 3,141 3,141 9,422 9,422
------------ ------------ ------------- -------------
INCOME Before Extraordinary Item 48,243 46,074 112,248 109,645
Extraordinary Item (Net of Tax) -- -- (82,548) --
------------ ------------ ------------- -------------
NET INCOME After Extraordinary Item 48,243 46,074 29,700 109,645
DIVIDENDS ON PREFERRED AND
PREFERENCE STOCK 994 1,006 2,983 3,020
------------ ------------ ------------- -------------
EARNINGS for Common Stock $ 47,249 $ 45,068 $ 26,717 $ 106,625
============ ============ ============= =============
EARNINGS for Common Stock
Before Extraordinary Item $ 47,249 $ 45,068 $ 109,265 $ 106,625
Extraordinary Item (Net of Tax) -- -- (82,548) --
------------ ------------ ------------- -------------
EARNINGS for Common Stock
After Extraordinary Item $ 47,249 $ 45,068 $ 26,717 $ 106,625
============ ============ ============= =============
</TABLE>
See notes to condensed consolidated financial statements.
2
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DUQUESNE LIGHT COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
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<S> <C>
ASSETS
Property, plant and equipment $ 4,497,925 $ 4,510,738
Less: Accumulated depreciation and amortization (3,255,446) (1,947,819)
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Property, plant and equipment - net 1,242,479 2,562,919
---------------- ----------------
Long-term investments 197,989 186,564
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Current assets:
Cash and temporary cash investments 168,495 165,169
Receivables 142,063 121,975
Other current assets, principally material and supplies 86,419 80,984
---------------- ----------------
Total current assets 396,977 368,128
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Other non-current assets:
Generation-related assets 2,175,616 561,867
Transmission and distribution-related assets 111,995 119,018
Other deferred debits 34,610 41,683
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Total other non-current assets 2,322,221 722,568
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TOTAL ASSETS $ 4,159,666 $ 3,840,179
================ ================
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock - $1 par value (shares - 90,000,000
authorized; 10 issued) $ -- $ --
Capital surplus 833,894 831,151
Retained earnings 108,399 172,682
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Total common stockholder's equity 942,293 1,003,833
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Preferred and preference stock 228,118 226,503
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Long-term debt 1,183,459 1,218,276
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Total capitalization 2,353,870 2,448,612
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Obligations under capital leases 41,047 37,540
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Current liabilities:
Current maturities and sinking fund requirements 99,989 97,523
Other current liabilities 161,514 154,955
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Total current liabilities 261,503 252,478
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Deferred income taxes - net 585,101 599,811
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Deferred income 125,610 183,304
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Beaver Valley lease liability 487,565
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Other non-current liabilities 304,970 318,434
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Commitments and contingencies (Note 4)
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TOTAL CAPITALIZATION AND LIABILITIES $ 4,159,666 $ 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>
Nine Months Ended
September 30
------------------------------------
1998 1997
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<S> <C> <C>
Cash Flows From Operating Activities
Operations $ 318,375 $ 251,704
Changes in working capital other than cash (65,862) 28,043
Increase in ECR (19,219) (13,866)
Other 2,886 23,941
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Net Cash Provided By Operating Activities 236,180 289,822
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Cash Flows From Investing Activities
Construction expenditures (69,050) (61,681)
Long-term investments (25,497) (8,739)
Other 161 6,178
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Net Cash Used in Investing Activities (94,386) (64,242)
-------------- --------------
Cash Flows From Financing Activities
Dividends on capital stock (94,672) (106,732)
Reductions of long-term obligations - net (36,732) (16,310)
Other (7,064) 2,290
-------------- --------------
Net Cash Used in Financing Activities (138,468) (120,752)
-------------- --------------
Net increase in cash and temporary cash investments 3,326 104,828
Cash and temporary cash investments at beginning of period 165,169 154,414
-------------- --------------
Cash and temporary cash investments at end of period $ 168,495 $ 259,242
============== ==============
Non-Cash Investing and Financing Activities
Capital lease obligations recorded $ 5,011 $ 17,004
============== ==============
</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. However, on October 5, 1998, DQE unilaterally terminated the merger
agreement, and AYE filed suit in the United States District Court for the
Western District of Pennsylvania requesting enforcement of the merger agreement,
or in the alternative money damages for the termination. (See "Status of AYE
Merger" discussion, Note 2, page 9.)
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 nine months
ended September 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 Pennsylvania Public Utility Commission (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 EITF 97-4,
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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). Applying SFAS No. 121 to the non-regulated
generating assets, it has been determined that Duquesne's generating assets are
impaired. However, pursuant to the PUC's final restructuring order, Duquesne
will recover its above-market investment in generation assets through the CTC.
Under Duquesne's plan to auction its generating assets, the market value
utilized by the PUC in determining the value of the generating assets will be
the net after-tax proceeds received from the auction of its generating assets.
Accordingly, the amount of book value authorized to be recovered by the PUC has
been reclassified on the condensed consolidated balance sheet from "Property,
plant and equipment" to "Other non-current generation-related assets" until the
auction has been completed and all approvals for the final CTC accounting have
been granted. 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), fuel
costs are expensed as incurred and impact net income.
Under-recoveries from customers prior to May 29, 1998, were recorded on the
condensed consolidated balance sheet as a regulatory asset. At September 30,
1998, $42.7 million was receivable from customers. Duquesne expects to recover
this amount through the CTC. (See "Restructuring Plans and Regulatory Orders",
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 were
$32.3 million ($18.9 million, net of tax) at September 30, 1998 and $26.6
million ($15.6 million, net of tax) at December 31, 1997.
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. On November 6, 1998, Duquesne withdrew its appeal.
Phase-In to Competition
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 October
31, 1998, 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 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 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 generation rates (capped at
current levels so long as a CTC is being collected). Also under the Customer
Choice Act, delivery of electricity (including transmission, distribution and
customer service) will continue to be regulated in substantially the same manner
as under current regulation.
In an effort to "jump start" retail competition, Duquesne will make 600
megawatts of power available to licensed electric generation suppliers, to be
used in supplying electricity to Duquesne's customers who have chosen other
generation suppliers. The power will be available for the first six months of
1999 at a price of 2.6 cents per kilowatt-hour (KWH). This availability will be
structured to ensure the power is used to benefit Duquesne's retail customers.
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 rates as long as transition costs are being
recovered, with certain exceptions.
Restructuring Plans and Regulatory Orders
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
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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.
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. Until the
divestiture is complete, Duquesne has been ordered to use an interim system
average CTC and shopping credit based on the methodology approved in its pilot
program (approximately 2.9 cents per KWH for the CTC and approximately 3.8 cents
per KWH for the shopping credit). The PUC's order approves the auction only in
the context of the Stand-Alone Plan, not the Merger Plan.
On August 27, 1998, Duquesne filed its auction plan with the PUC. Duquesne
expects approval of the plan from the PUC by the end of 1998. The confidential
bidding process will begin in early 1999. Only companies with an established
record of owning and operating electric generating plants and with proof of
their financial ability to purchase the plants without financing will qualify to
bid. The transaction will have to be approved by various regulatory agencies,
including the PUC, the FERC, the Nuclear Regulatory Commission (NRC), the
Department of Justice and the Federal Trade Commission. Duquesne expects the
process to last approximately 12 to 18 months from the opening of bidding to the
closing of the sale.
To help facilitate the auction process, on October 14, 1998, Duquesne
entered into a non-binding agreement in principle with FirstEnergy Corp. to
exchange ownership interests in certain plants. As proposed, Duquesne would
acquire 100 percent ownership interests in three coal-fired power plants located
in Avon Lake and Niles, Ohio and New Castle, Pennsylvania (totaling
approximately 1,300 megawatts). In exchange, FirstEnergy Corp. would acquire
Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2
(BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield
Units 1, 2 and 3 (totaling approximately 1,400 megawatts). Duquesne's investment
in these plants at September 30, 1998, was $894.1 million which has been
reclassified to "Other non-current generation-related assets" on the condensed
consolidated balance sheet. Duquesne has requested the PUC to authorize the
investment in the acquired power plants to be accounted for in the final auction
proceeds accounting utilizing the previously authorized investment amount of the
plants transferred by Duquesne. Duquesne expects this exchange to enhance the
value received from the auction because participants will be able to bid on
plants that are wholly owned by Duquesne, rather than plants that are jointly
owned and/or operated by another entity. Additionally, the auction will include
only coal- and oil-fired plants, which are anticipated to have a higher market
value than nuclear plants. These value-enhancing features, along with a minimum
level of auction proceeds guaranteed by FirstEnergy Corp., will maximize auction
proceeds and thereby minimize transition costs required to be recovered through
the CTC and reduce customer bills as rapidly as possible. Other benefits of
this exchange for Duquesne include the resolution of all joint ownership issues,
and other risks and costs associated with the nuclear units. Duquesne expects
PUC approval of the exchange by the end of 1998. Certain aspects of the
exchange will have to be approved by the FERC, the NRC and the Department of
Justice. The closing of the exchange is expected to occur simultaneously with
the closing of the sale of Duquesne's generation through the auction.
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.
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At June 30, 1998, Duquesne recorded a charge to its earnings of $142.3
million ($82.5 million, net of tax) to reflect the disallowance associated with
the investments in the cold reserved units and the disallowance of a portion of
the regulatory asset claim described above.
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 would require 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 merged company would be required immediately 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. The PUC would determine which 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,
Duquesne believes the Midwest ISO, as presently constituted and as approved by
the FERC, will not mitigate the PUC's concerns regarding market power.
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 Duquesne's 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 an average shopping
credit 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. Duquesne believes that as of
October 5, 1998, the relevant date under the merger agreement, AYE had suffered
a material adverse effect and, despite ample opportunity, had not corrected it.
Subsequent to the October 5, 1998 termination of the merger agreement, the PUC
tentatively approved a settlement of the West Penn restructuring case, which
settlement did not significantly increase the level of West Penn's allowed
stranded costs.
The FERC Order. The FERC issued its order regarding the proposed merger on
September 16, 1998. The order required the sale of Cheswick prior to
consummation of the merger, rejecting the proposal to relinquish control of 570
megawatts from that station in order to address market power concerns. Duquesne
does not believe such a divestiture could be accomplished quickly enough to
allow the proposed merger to occur within the timeframe contemplated in the
merger agreement. In addition, the FERC order does not address or alter the
financial effects on AYE of the PUC order discussed above.
Status of AYE Merger. 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, 1998, AYE informed DQE that it does not
believe DQE has the right to terminate the merger agreement under these
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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.
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement. AYE promptly filed suit in the United States District Court for the
Western District of Pennsylvania, seeking to compel DQE to proceed with the
merger and seeking a temporary restraining order and preliminary injunction to
prevent DQE from certain actions pending a trial, or in the alternative seeking
an unspecified amount of money damages. More information regarding this
termination is set forth in Duquesne's Current Report on Form 8-K dated October
5, 1998. A hearing was held on October 26, 1998, regarding AYE's motion for the
temporary restraining order and preliminary injunction. On October 28, 1998,
the judge denied the motion. On October 30, 1998, AYE appealed the judge's
decision to the United States Court of Appeals for the Third Circuit, asking for
an injunction pending the appeal and expedited treatment of the appeal. On
November 6, 1998, the Third Circuit denied the motion for an injunction and
granted the motion to expedite the appeal.
3. RECEIVABLES
Components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
September 30, September 30, December 31,
1998 1997 1997
(Amounts in Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 99,608 $ 94,844 $ 90,149
Other utility receivables 28,306 18,595 23,106
Other receivables 29,430 7,738 23,736
Less: Allowance for uncollectible accounts (15,281) (19,590) (15,016)
- ------------------------------------------------------------------------------------------------------
Total Receivables $142,063 $101,587 $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 September 30, 1998, September 30, 1997
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 through the auction and the power station exchange, which will impact the
obligations related to those assets. (See "Order on the Stand-Alone Plan"
discussion, Note 2, on page 8.)
Construction
Duquesne currently estimates that it will spend, excluding the Allowance
for Funds Used During Construction and nuclear fuel, approximately $110 million
on construction during 1998.
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Nuclear-Related Matters
Duquesne has an 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 BV Unit 1, BV
Unit 2 and Perry Unit 1 no earlier than the expiration of each plant's operating
license in 2016, 2027 and 2026, respectively. At the end of its operating life,
BV Unit 1 may be placed in safe storage until BV Unit 2 is ready to be
decommissioned, at which time the units may be decommissioned together.
Based on site-specific studies 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
September 30, 1998, totaled approximately $56.2 million.
Nuclear Insurance. The Price-Anderson Amendments to the Atomic Energy Act
of 1954 limit public liability from a single incident at a nuclear plant to $9.9
billion. The maximum available private primary insurance of $200 million has
been purchased by Duquesne. Additional protection of $9.7 billion would be
provided by an assessment of up to $88.1 million per incident on each licensed
nuclear unit in the United States. Duquesne's maximum total possible assessment,
$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 17 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
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service 11 years after BV Unit 1, has not yet exhibited the degree of ODSCC
experienced at BV Unit 1. Approximately 3 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. 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 NRC requirements to conduct
such inspections at BV Unit 1 at least every 20 months. Duquesne plans to
request permission from the NRC to postpone these inspections until BV Unit 1's
next refueling outage, currently scheduled to begin in the spring of 2000.
Duquesne completed its inspection of BV Unit 2's tubes during the recent forced
outage in order to comply with 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 at the end of February 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 remained
off-line due to other issues identified by a technical review similar to that
performed at BV Unit 1. These technical reviews, which were in response to a
1997 commitment made by Duquesne to the NRC, have been completed. Duquesne was
one of many utilities faced with similar issues, some of which date back to the
initial start-up of BVPS. BV Unit 1 returned to service on August 15, 1998, and
BV Unit 2 returned to service on September 28, 1998.
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 denied the relief requested by the utilities and
states and permitted the DOE to pursue alternative dispute resolution, but
prohibited the DOE from
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using its lack of a spent fuel repository as a defense. The states and the DOE
have both petitioned the United States Supreme Court for review of the decision.
The Supreme Court has not decided whether it will review the case. The utilities
did not join the states' petition.
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 September 30, 1998 and December 31, 1997, Duquesne's
liability for contributions was approximately $7.2 million (subject to an
inflation adjustment).
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.)
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 September 30, 1998, Duquesne's share of
these guarantees was $9.9 million.
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. However, on October 5, 1998, DQE unilaterally terminated the merger
agreement, and AYE filed suit in the United States District Court for the
Western District of Pennsylvania requesting enforcement of the merger agreement,
or in the alternative money damages for the termination. (See "Status of AYE
Merger" discussion on page 24.)
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 Pennsylvania Public Utility Commission (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). Applying SFAS
No. 121 to the non-regulated generating assets, it has been determined that
Duquesne's generating assets are impaired. However, pursuant to the PUC's final
restructuring order, Duquesne will recover its above-market investment in
generation assets through the CTC. Under Duquesne's plan to auction its
generating assets, the market value utilized by the PUC in determining the value
of the generating assets will be the net after-tax proceeds received from the
auction of its generating assets. Accordingly, the amount of book value
authorized to be recovered by the PUC has been reclassified on the condensed
consolidated balance sheet from "Property, plant and equipment" to "Other non-
current generation-related assets" until the auction has been completed and all
approvals for the final CTC accounting have been granted. 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. (See "Rate
Matters" on page 20.)
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: During the third quarter of 1998, Duquesne increased its net income by
$2.2 million to $47.2 million from $45.1 million in the third quarter of 1997
primarily as a result of decreased generating plant depreciation due to the PUC
order.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
As a result of the Restructuring Charge recorded in June 1998 for $142.3 million
($82.5 million net of tax), Duquesne's net income was $26.7 million in the nine
months ended September 1998 as compared to $106.6 million in the nine months
ended September 1997.
Revenues
Total operating revenues in the third quarter of 1998 increased $1.1
million or 0.3 percent as compared to the third quarter of 1997. Total
operating revenues in the nine months ended September 30, 1998, increased $12.8
million or 1.5 percent as compared to the nine months ended September 30, 1997.
The following table sets forth operating revenues and KWH delivered for
residential, commercial and industrial customers who have not chosen different
generation suppliers.
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<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------
(Revenues in Millions of Dollars) Increase(Decrease) from Prior Year
- -------------------------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, 1998 September 30, 1998
--------------------------------------------------------
KWH Revenues KWH Revenues
--------------------------------------------------------
<S> <C> <C> <C> <C>
Residential 3.6% $ 5.2 (1.7)% $ 8.8
Commercial (2.2)% (6.1) (3.2)% 2.4
Industrial (6.1)% (5.0) (2.0)% (1.9)
Less: Provision for Doubtful Accounts 0.0 0.0
- -------------------------------------------------------------------------------------------------------
Sales to Electric Utility Customers (1.6)% (5.9) (2.5)% 9.3
- -------------------------------------------------------------------------------------------------------
Sales to Other Utilities 43.5% 4.5 (1.3)% 3.5
Other Revenues 2.5 0.0
Total 2.6% $ 1.1 (2.4)% $12.8
=======================================================================================================
</TABLE>
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 date of the PUC's final restructuring order), the PUC
approved separate 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, historical, 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, 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.
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 September 30, 1998, and September 30,
1997: In the third quarter of 1998, net customer revenues reflected on the
statement of consolidated income decreased by $5.9 million or 1.9 percent to
$301.2 million from the third quarter of 1997. In 1997, $10.8 million of fuel
costs were deferred for subsequent recovery through the ECR resulting in an
increase in revenues. Excluding the deferred fuel from 1997 revenues, the net
increase in revenues can be attributed to a 3.6 percent increase in residential
sales due to warmer temperatures. Commercial and industrial sales decreased by
2.2 percent and 6.1 percent due in part to the implementation of the pilot
program in November 1997, which resulted in a reduction in electric utility
customer sales. Additionally, in response to requirements of 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. Absent the change
in categorization and the effects of the pilot program, industrial sales were
consistent with the 1997 level.
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Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
Net customer revenues increased $9.3 million or 1.1 percent in the nine months
ended September 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 electric utility customer
KWH sales due primarily to the implementation of the pilot program.
Additionally, in response to requirements of 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. Absent the change in categorization
and the effects of the pilot program, industrial sales would have increased
compared to 1997, due to 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, Duquesne's decision to sell 600 megawatts to licensed generation
suppliers and Duquesne's divestiture plan. (See "Rate Matters" on page 20.)
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Duquesne's revenues from electricity sales to other utilities in the
third quarter of 1998 were $4.5 million or 72.6 percent greater than in the
third quarter of 1997, due to increased demand from the other utilities as a
result of warmer temperatures during the third quarter of 1998 and increased
market power prices in 1998.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
In the nine months ended September 30, 1998, Duquesne's revenues from
electricity sales to other utilities were $3.5 million or 16.6 percent more than
in the nine months ended September 30, 1997, due to greater demand from the
other utilities as a result of warmer temperatures during the third quarter of
1998 and increased market power prices in 1998. Partially offsetting the
increases was a decrease through the first six months of 1998 due to reduced
generating station availability as a result of an increase in outage hours in
the first six months of 1998 as compared to 1997.
Other Operating Revenues
Duquesne's non-KWH revenues comprise other operating revenues in Duquesne's
statement of consolidated income. Other operating revenues are primarily
comprised of revenues from joint owners of BV Unit 1 and BV Unit 2 for their
shares of the administrative and general costs of operating these units. Other
operating revenues, therefore, fluctuate depending on the timing of scheduled
refueling and maintenance outages at BVPS when significant costs are incurred.
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: The other operating revenues increase of $2.5 million or 26.0 percent
when comparing the third quarter of 1998 and the third quarter of 1997 was
primarily the result of increased 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 24.)
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
Other operating revenues for the nine months ended September 1998 were
consistent with levels from the nine months ended September 1997.
Operating Expenses
Fuel and Purchased Power Expense
Fluctuations in fuel and purchased power expense generally result from
changes in the cost of fuel, the mix between coal and nuclear generation, the
total KWHs sold, and generating station availability. Because of the ECR,
changes in fuel and purchased power costs did not impact earnings for the first
five months of 1998 or any of 1997. Beginning May 29, 1998, fuel costs for
customers
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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 rates. (See "Rate Matters" on page 20.)
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Fuel and purchased power expense increased $22.3 million or 35.4 percent
in the third quarter of 1998 as compared to the third quarter of 1997. The
increase resulted from higher energy costs of $19.8 million or 29.8 percent due
to an unfavorable power supply mix and higher purchased power prices. The
remaining increase of $2.5 million was due to a higher volume of energy supplied
due to warmer temperatures during 1998. Reduced availability of generating
stations due to an increase in outage hours required Duquesne to purchase power
and generate power from the higher fuel cost fossil stations. (See "Beaver
Valley Power Station" on page 24.)
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
The $51.2 million or 31.0 percent increase in fuel and purchased power expense
for the nine months ended September 30, 1998, as compared to the nine months
ended September 30, 1997, was the result of increased energy costs of $55.9
million due to an unfavorable power supply mix and higher purchased power
prices. Energy volume supplied resulted in a $4.7 million reduction in fuel and
purchased power expenses primarily due to lower sales from the pilot program.
Reduced availability of generating stations due to an increase in outage hours
required Duquesne to purchase power and generate power from the higher fuel cost
fossil stations. (See "Beaver Valley Power Station" on page 24.)
BV Unit 1 and BV Unit 2 continued to be off-line into the third quarter,
with BV Unit 1 returning to service on August 15, 1998, and BV Unit 2 returning
to service September 28, 1998. These outages, combined with various fossil
station outages, caused Duquesne to continue to purchase larger than normal
quantities of electricity. Additionally, the market price for purchased power
continues to be higher than recent historical levels. As a result of these
higher costs and the discontinuance of the ECR, fuel costs had a negative impact
on third quarter earnings. This impact was 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 September 30, 1998, and September 30,
1997: Other operating expenses increased $2.7 million or 4.3 percent to $65.0
million in the third quarter of 1998 as compared to the third quarter of 1997.
Increased labor and outside service costs related to the outages at Beaver
Valley Power Station partially offset by decreased BV Unit 2 lease costs are the
reasons for the overall increase in other operating expense. As a result of the
PUC's final restructuring order, the present value of 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.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
Other operating expenses decreased $4.5 million or 2.4 percent to $185.3 million
when comparing the nine months ended September 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 September 30, 1998, and September 30,
1997: Maintenance expense increased $2.1 million or 9.9 percent when comparing
the third quarter of 1998 to the same period in 1997. The increase is primarily
attributable to tree trimming and storm-related
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maintenance of overhead lines partially offset by reduced nuclear station outage
cost amortization in 1998.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
Maintenance expense decreased $2.3 million or 3.7 percent when comparing the
nine months ended September 30, 1998, to the same period in 1997. The decrease
is primarily related to the timing of the Cheswick Power Station (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. Additionally, Elrama
Power Station had higher costs in 1997 due to scrubber outages.
Depreciation and Amortization Expense
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Depreciation and amortization decreased $20.8 million or 34.4 percent
during the third quarter of 1998 as compared to the third quarter of 1997. The
decrease was primarily the result of reduced depreciation of generating plant in
connection with the PUC's final restructuring order.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
The decrease in depreciation and amortization in the nine months ended September
30, 1998, as compared to the same period in 1997 was $20.1 million or 11.7
percent. The decrease was primarily the result of reduced depreciation of
generating plant in connection with the PUC's final restructuring order.
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 September 30, 1998, and September 30,
1997: A $2.2 million or 36.9 percent increase in other income in the third
quarter of 1998 as compared to the third quarter of 1997 resulted from long-term
investment income. The greater long-term investment income was the result of an
investment made in the fourth quarter of 1997.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
A $9.5 million or 51.3 percent increase in other income in the first nine months
of 1998 as compared to the first nine months of 1997 resulted from long-term
investment income. The greater long-term investment income was the result of an
investment made in the fourth quarter of 1997.
Interest Charges
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Interest and other charges decreased $1.5 million or 7.1 percent during
the third quarter of 1998 as compared to the third 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 $120 million of long-term debt
subsequent to the third quarter of 1997.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
The decrease in interest and other charges in the nine months ended September
30, 1998 from the nine months ended September 30, 1997, was $3.9 million or 6.1
percent. The reason for the decrease in 1998 was primarily the result of the
refinancing of long-term debt at lower interest rates and the retirement of
long-term debt.
Extraordinary 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, Brunot Island 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).
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Liquidity and Capital Resources
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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 September 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 73/8 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" below.)
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. The accounts receivable sale arrangement
expires in 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 was
extended during the third quarter to October 1999. 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
September 30, 1998.
Investing
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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 nine
months of 1998. $8 million was invested in nuclear decommissioning trust funds
during the nine months ended September 30, 1998 and $9 million during the nine
months ended September 30, 1997. The remaining $12 million for the nine months
ended September 30, 1998 and 1997 was invested in other investments.
Cash flows, and the corresponding level of investing and financing
activities, are expected to be impacted by several factors during 1999. Cash
flows from operations, while expected to continue to be strong, will be reduced
from current levels as a result of customer choice (the level of customer
participation, the final shopping credit, etc.). Additionally, related to the
generation divestiture, substantial one-time cash inflows and payments may
result.
Rate Matters
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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.
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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. On November 6, 1998, Duquesne withdrew its appeal.
Phase-In to Competition
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 October
31, 1998, 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 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 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 generation rates (capped at
current levels so long as a CTC is being collected). Also under the Customer
Choice Act, delivery of electricity (including transmission, distribution and
customer service) will continue to be regulated in substantially the same manner
as under current regulation.
In an effort to "jump start" retail competition, Duquesne will make 600
megawatts of power available to licensed electric generation suppliers, to be
used in supplying electricity to Duquesne's customers who have chosen other
generation suppliers. The power will be available for the first six months of
1999 at a price of 2.6 cents per kilowatt-hour (KWH). This availability will be
structured to ensure the power is used to benefit Duquesne's retail customers.
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 rates as long as transition costs are being
recovered, with certain exceptions.
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Restructuring Plans and Regulatory Orders
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.
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. Until
the divestiture is complete, Duquesne has been ordered to use an interim system
average CTC and shopping credit based on the methodology approved in its pilot
program (approximately 2.9 cents per KWH for the CTC and approximately 3.8 cents
per KWH for the shopping credit). The PUC's order approves the auction only in
the context of the Stand-Alone Plan, not the Merger Plan.
On August 27, 1998, Duquesne filed its auction plan with the PUC. Duquesne
expects approval of the plan from the PUC by the end of 1998. The confidential
bidding process will begin in early 1999. Only companies with an established
record of owning and operating electric generating plants and with proof of
their financial ability to purchase the plants without financing will qualify to
bid. The transaction will have to be approved by various regulatory agencies
including the PUC, the FERC, the Nuclear Regulatory Commission (NRC), the
Department of Justice and the Federal Trade Commission. Duquesne expects the
process to last approximately 12 to 18 months from the opening of bidding to the
closing of the sale.
To help facilitate the auction process, on October 14, 1998, Duquesne
entered into a non-binding agreement in principle with FirstEnergy Corp. to
exchange ownership interests in certain plants. As proposed, Duquesne would
acquire 100 percent ownership interests in three coal-fired power plants located
in Avon Lake and Niles, Ohio and New Castle, Pennsylvania (totaling
approximately 1,300 megawatts). In exchange, FirstEnergy Corp. would acquire
Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2
(BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield
Units 1, 2 and 3 (totaling approximately 1,400 megawatts). Duquesne's investment
in these plants at September 30, 1998, was $894.1 million which has been
reclassified to "Other non-current generation-related assets" on the condensed
consolidated balance sheet. Duquesne has requested the PUC to authorize the
investment in the acquired power plants to be accounted for in the final auction
proceeds accounting utilizing the previously authorized investment amount of the
plants transferred by Duquesne. Duquesne expects this exchange to enhance the
value received from the auction because participants will be able to bid on
plants that are wholly owned by Duquesne, rather than plants that are jointly
owned and/or operated by another entity. Additionally, the auction will include
only coal- and oil-fired plants, which are anticipated to have a higher market
value than nuclear plants. These value-enhancing features, along with a minimum
level of auction proceeds guaranteed by FirstEnergy Corp., will maximize auction
proceeds and thereby minimize transition costs required to be recovered through
the CTC and reduce customer bills as rapidly as possible. Other benefits of
this exchange for Duquesne include the resolution of all joint ownership issues,
and other risks and costs associated with the nuclear units. Duquesne expects
PUC approval of the exchange by the end of 1998. Certain aspects of the
exchange will have to be approved by the FERC, the NRC and the Department of
Justice. The closing of the exchange is expected to occur simultaneously with
the closing of the sale of Duquesne's generation through the auction.
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
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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 tax) to reflect the disallowance associated with
the investments in the cold reserved units and the disallowance of a portion of
the regulatory asset claim described above.
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 would require 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 merged company would be required immediately to relinquish control of 570
megawatts of output from 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. The PUC would determine
which 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, Duquesne believes the Midwest ISO, as
presently constituted and as approved by the FERC, will not mitigate the PUC's
concerns regarding market power.
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 Duquesne's 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 an average shopping
credit 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. Duquesne believes that as of
October 5, 1998, 1998, the relevant date under the merger agreement, AYE had
suffered a material adverse effect and, despite ample opportunity, had not
corrected it. Subsequent to the October 5, 1998 termination of the merger
agreement, the PUC tentatively approved a settlement of the West Penn
restructuring case, which settlement did not significantly increase the level of
West Penn's allowed stranded costs.
The FERC Order. The FERC issued its order regarding the proposed merger on
September 16, 1998. The order required the sale of Cheswick prior to
consummation of the merger, rejecting the proposal to relinquish control of 570
megawatts from that station in order to address market power concerns. Duquesne
does not believe such a divestiture could be accomplished quickly enough to
allow the proposed merger to occur within the timeframe contemplated in the
merger agreement. In addition, the FERC order does not address or alter the
financial effects on AYE of the PUC order discussed above.
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Status of the AYE Merger. 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, 1998, 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.
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement. AYE promptly filed suit in the United States District Court for the
Western District of Pennsylvania, seeking to compel DQE to proceed with the
merger and seeking a temporary restraining order and preliminary injunction to
prevent DQE from certain actions pending a trial, or in the alternative seeking
an unspecified amount of money damages. More information regarding this
termination is set forth in Duquesne's Current Report on Form 8-K dated October
5, 1998. A hearing was held on October 26, 1998, regarding AYE's motion for the
temporary restraining order and preliminary injunction. On October 28, 1998,
the judge denied the motion. On October 30, 1998, AYE appealed the judge's
decision to the United States Court of Appeals for the Third Circuit, asking for
an injunction pending the appeal and expedited treatment of the appeal. On
November 6, 1998, the Third Circuit denied the motion for an injunction and
granted the motion to expedite the appeal.
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 remained
off-line due to other issues identified by a technical review similar to that
performed at BV Unit 1. These technical reviews, which were in response to a
1997 commitment made by Duquesne to the NRC, have been completed. Duquesne was
one of many utilities faced with similar issues, some of which date back to the
initial start-up of BVPS. BV Unit 1 returned to service on August 15, 1998, and
BV Unit 2 returned to service on September 28, 1998.
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 3 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.
Year 2000 Plan. 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 issues in computer software and in
devices and equipment (such as plant components, elevators, and heating and
cooling systems) containing embedded microprocessors that may not correctly
identify the year. The team is also exploring potential related issues that may
originate with third parties with whom Duquesne does business. To support the
planning, organization and management of its efforts, the team has retained Year
2000 consultants.
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In general, Duquesne's overall strategy to address the Year 2000 issue 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
completed it during the fourth quarter of 1998. Assessment consists of
evaluating the inventoried items for Year 2000 compliance by, among other
things, contacting vendors and inspecting software code and data. As of the
date of this report, Duquesne has completed substantially all of its assessment.
Duquesne is involved in ongoing discussions with its critical vendors, and will
continue working with them throughout their transition to Year 2000 readiness.
The remediation and testing and implementation components will concentrate first
on those systems, components and equipment that substantially impact Duquesne's
ability to perform its essential business functions ("mission critical").
During remediation, Duquesne will apply the solution selected for an item (e.g.,
whether to replace a product or vendor, employ a software upgrade, or revise
existing software code). Duquesne has completed approximately 25% of the
remediation it currently deems necessary. This remediation is in addition to
previously planned improvements to Duquesne's systems with benefits beyond Year
2000 solutions, such as the total system replacement discussed below. Testing
and implementation will consist of placing the renovated processes, systems,
equipment and other items into use within Duquesne's operations. Duquesne
expects remediation and testing and implementation to take place during the
first two quarters of 1999, with mission critical systems being compliant or
appropriate contingency plans, if necessary, being developed by that time.
Throughout the execution of its Year 2000 plan, Duquesne has been providing
and will continue to provide information on its activities to the PUC, the NRC
and the North American Electric Reliability Counsel (NERC), which coordinates
the network of interconnected utilities across the nation. Duquesne's plan is
in accordance with NRC guidelines, and Duquesne is working with the NRC to
certify that its nuclear power station safety and operations systems, and issues
related to suppliers, will be ready for the Year 2000. NERC has been requested
by the DOE to review the national electric power production and delivery
infrastructure to ensure a reliable power supply during the Year 2000 transition
period. Duquesne is working with NERC to address these issues. Duquesne also
participates in the Electric Power Research Institute's project to share
information about technical issues regarding the Year 2000 problem with other
entities in the electric utility industry.
Risks and Contingency Plans. Duquesne currently believes that
implementation of its plan will minimize the Year 2000 issues relating to its
systems and equipment. Duquesne's goal is to ensure that all components and
services that in any material manner contribute to operational reliability,
customer relations, safety, revenue, regulatory compliance and Duquesne's
reputation will fully satisfy criteria regarding date-recognition and general
integrity of such components and services, or be suitable for continued use with
appropriate work-arounds or contingency plans. Duquesne currently is assessing
its operations to determine the most likely worst-case scenario it could face as
a result of Year 2000. Similarly, Duquesne currently is developing contingency
plans in the event any part of its overall strategy should fail adequately to
address the Year 2000 problem.
Costs. The estimated total cost of implementing Duquesne's Year 2000 plan
is approximately $45 million, which includes costs related to total system
replacements (i.e., the Year 2000 solution comprises only a portion of the
benefit resulting from such replacements). These costs to date, primarily
incurred as a result of software and system changes and upgrades by Duquesne,
have been approximately $35 million. Of this amount, approximately $31 million
are capital costs attributable to the licensing and installation of new software
for total system replacements. The remaining $4 million has been expensed as
incurred. Funds for Duquesne's Year 2000 plan have come from Duquesne's
operating and capital budgets. Approximately $10 million has been budgeted for
1999 to address Year 2000 issues. Until Duquesne's remediation 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.
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The foregoing paragraphs contain forward-looking statements regarding the
timetable, effectiveness and ultimate cost 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, including, but 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.
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 September 30, 1998 totaled approximately $56.2 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; 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.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Eastlake Unit 5
In September 1995, Duquesne commenced arbitration against Cleveland
Electric Illuminating Company (CEI), a subsidiary of FirstEnergy, Corp.
(FirstEnergy) 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. Pursuant to the agreement in principle
between Duquesne and FirstEnergy to exchange interests in certain power stations
(see "Restructuring Plans and Regulatory Orders" discussion above), the parties
jointly sought, and on October 26, 1998, received, a court order staying all
proceedings in the Eastlake litigation pending complete execution of the
exchange-related agreements.
AYE Merger
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement. AYE promptly filed suit in the United States District Court for the
Western District of Pennsylvania, seeking to compel DQE to proceed with the
merger and seeking a temporary restraining order and preliminary injunction to
prevent DQE from certain actions pending a trial, or in the alternative seeking
an unspecified amount of money damages. More information regarding this
termination is set forth in Duquesne's Current Report on Form 8-K dated October
5, 1998. A hearing was held on October 26, 1998, regarding AYE's motion for the
temporary restraining order and preliminary injunction. On October 30, 1998,
AYE appealed the judge's decision to the United States Court of Appeals for the
Third Circuit, asking for an injunction pending the appeal and expedited
treatment of the appeal . On November 6, 1998, the Third Circuit denied the
motion for an injunction and granted the motion to expedite the appeal.
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 October 5, 1998, to report DQE,
Inc.'s termination of the merger agreement with AYE. No financial
statements were filed with this report.
A Current Report on Form 8-K was filed October 15, 1998, to report the
execution by DQE and FirstEnergy of an agreement in principle to exchange
interests in certain power stations. No financial statements were filed
with this report.
______________________________
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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 November 16, 1998 /s/ Gary L. Schwass
--------------------- ---------------------------------------
(Signature)
Gary L. Schwass
Senior Vice President and
Chief Financial Officer
Date November 16, 1998 /s/ Morgan K. O'Brien
--------------------- ---------------------------------------
(Signature)
Morgan K. O'Brien
Vice President-Finance,
Treasurer and Controller
(Principal Accounting Officer)
28
<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,
Nine Months Ended -----------------------
September 30, 1998 1997 1996 1995 1994 1993
------------------ -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $ 57,166 $ 81,592 $ 82,505 $ 89,139 $ 94,646 $102,938
Other interest 1,008 752 1,632 2,599 1,095 2,387
Monthly Income Preferred Securities dividend
requirements 9,422 12,562 7,921 - - -
Amortization of debt discount, premium and
expense - net 3,976 5,828 5,973 6,252 6,381 5,541
Portion of lease payments representing an
interest factor 33,330 44,208 44,357 44,386 44,839 45,925
-------- -------- -------- -------- -------- --------
Total Fixed Charges $104,902 $144,942 $142,388 $142,376 $146,961 $156,791
-------- -------- -------- -------- -------- --------
EARNINGS:
Income from continuing operations $112,248 $141,820 $149,860 $151,070 $147,449 $144,787
Income taxes 68,670* 73,838* 83,008* 92,894* 84,191* 77,237*
Fixed charges as above 104,902 144,943 142,388 142,376 146,961 156,791
-------- -------- -------- -------- -------- --------
Total Earnings $285,820 $360,601 $375,256 $386,340 $378,601 $378,815
-------- -------- -------- -------- -------- --------
RATIO OF EARNINGS TO FIXED CHARGES 2.72 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 $1.9 million for the nine months ended September
30, 1998, has been excluded from the ratio.
* Earnings related to income taxes reflect a $13.5 million decrease for the nine
months ended September 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 a financial
statement reclassification related to Statement of Financial Accounting
Standards No. 109, Accounting for Income Taxes. The ratio of earnings to fixed
charges, absent this reclassification, equals 2.85 for the nine months ended
September 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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,242,479
<OTHER-PROPERTY-AND-INVEST> 197,989
<TOTAL-CURRENT-ASSETS> 396,977
<TOTAL-DEFERRED-CHARGES> 2,322,221
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,159,666
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 833,894
<RETAINED-EARNINGS> 108,399
<TOTAL-COMMON-STOCKHOLDERS-EQ> 942,293
4,500
223,618<F1>
<LONG-TERM-DEBT-NET> 1,183,459
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 80,000
0
<CAPITAL-LEASE-OBLIGATIONS> 41,047
<LEASES-CURRENT> 19,989
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,664,760
<TOT-CAPITALIZATION-AND-LIAB> 4,159,666
<GROSS-OPERATING-REVENUE> 890,917
<INCOME-TAX-EXPENSE> 64,070
<OTHER-OPERATING-EXPENSES> 672,517
<TOTAL-OPERATING-EXPENSES> 736,587
<OPERATING-INCOME-LOSS> 154,330
<OTHER-INCOME-NET> 27,923
<INCOME-BEFORE-INTEREST-EXPEN> 182,253
<TOTAL-INTEREST-EXPENSE> 70,005<F2>
<NET-INCOME> 112,248<F3>
2,983
<EARNINGS-AVAILABLE-FOR-COMM> 109,265
<COMMON-STOCK-DIVIDENDS> 91,000
<TOTAL-INTEREST-ON-BONDS> 61,142
<CASH-FLOW-OPERATIONS> 236,180
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0.00
<FN>
<F1>Includes $13,010 of Preference Stock
<F2>Includes $9,422 of Monthly Income Preferred Securities Dividend Requirements
<F3>Excludes $82,548 extraordinary restructuring charge
</FN>
</TABLE>
