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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, 1999
----------------------
[_] Transition Report Pursuant to Section 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From __________ to __________
Commission File Number
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1-956
Duquesne Light Company
----------------------
(Exact name of registrant as specified in its charter)
Pennsylvania 25-0451600
------------ ----------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
-------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 393-6000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such report), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
DQE, Inc. is the holder of all shares of common stock, $1 par value, of Duquesne
Light Company consisting of 10 shares as of September 30, 1999 and October 31,
1999.
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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,
----------------------------- --------------------------------
1999 1998 1999 1998
---------- ---------- ----------- ------------
<S> <C> <C> <C> <C>
Operating Revenues
Sales of Electricity:
Customers - net $ 296,043 $ 303,971 $ 790,410 $ 841,811
Utilities 27,283 10,722 56,414 24,764
------------ ------------ ------------- -------------
Total Sales of Electricity 323,326 314,693 846,824 866,575
Other 12,839 13,328 45,328 33,936
------------ ------------ ------------- -------------
Total Operating Revenues 336,165 328,021 892,152 900,511
------------ ------------ ------------- -------------
Operating Expenses
Fuel and purchased power 84,341 85,335 180,921 216,443
Other operating 65,373 67,760 187,363 193,502
Maintenance 18,425 23,321 62,196 59,273
Depreciation and amortization 60,779 35,163 160,677 146,947
Taxes other than income taxes 23,830 21,174 68,068 60,102
Income taxes 18,181 30,743 53,432 68,570
------------ ------------ ------------- -------------
Total Operating Expenses 270,929 263,496 712,657 744,837
------------ ------------ ------------- -------------
OPERATING INCOME 65,236 64,525 179,495 155,674
------------ ------------ ------------- -------------
Other Income and Deductions 4,465 6,907 18,085 26,579
Income Before Interest and Other Charges
and Extraordinary Item 69,701 71,432 197,580 182,253
Interest Charges 29,520 20,048 86,674 60,583
Monthly Income Preferred Securities
Dividend Requirements 3,141 3,141 9,422 9,422
------------ ------------ ------------- -------------
INCOME Before Extraordinary Item 37,040 48,243 101,484 112,248
Extraordinary Item (Net of Tax) -- -- -- (82,548)
------------ ------------ ------------- -------------
NET INCOME After Extraordinary Item $ 37,040 $ 48,243 $ 101,484 $ 29,700
============ ============ ============= =============
DIVIDENDS ON PREFERRED AND
PREFERENCE STOCK 1,036 994 3,016 2,983
------------ ------------ ------------- -------------
EARNINGS (LOSS) FOR COMMON STOCK
Before Extraordinary Item $ 36,004 $ 47,249 $ 98,468 $ 109,265
============ ============ ============= =============
EARNINGS (LOSS) FOR COMMON STOCK
After Extraordinary Item $ 36,004 $ 47,249 $ 98,468 $ 26,717
============ ============ ============= =============
</TABLE>
See notes to condensed consolidated financial statements.
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DUQUESNE LIGHT COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
-------------------- --------------------
<S> <C> <C>
ASSETS
Property, plant and equipment $ 4,535,482 $ 4,589,140
Less: Accumulated depreciation and amortization (3,111,266) (3,141,841)
---------------- ----------------
Property, plant and equipment - net 1,424,216 1,447,299
---------------- ----------------
Long-term investments 178,595 202,256
---------------- ----------------
Current assets:
Cash and temporary cash investments 19,508 53,151
Receivables 86,982 125,956
Other current assets, principally material and supplies 159,512 92,119
---------------- ----------------
Total current assets 266,002 271,226
---------------- ----------------
Other non-current assets:
Transition costs 1,977,305 2,132,980
Regulatory assets 61,031 64,568
Other 77,955 56,799
---------------- ----------------
Total other non-current assets 2,116,291 2,254,347
---------------- ----------------
TOTAL ASSETS $ 3,985,104 $ 4,175,128
================ ================
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock - $1 par value (shares - 90,000,000
authorized; 10 issued) $ -- $ --
Capital surplus 746,462 813,528
Retained earnings 18,431 27,646
Accumulated other comprehensive income 20,440 27,326
---------------- ----------------
Total common stockholder's equity 785,333 868,500
---------------- ----------------
Preferred and preference stock 229,237 227,782
---------------- ----------------
Long-term debt 1,060,530 1,160,348
---------------- ----------------
Total capitalization 2,075,100 2,256,630
---------------- ----------------
Obligations under capital leases 16,937 36,596
---------------- ----------------
Current liabilities:
Notes payable and current maturities 211,664 96,137
Other current liabilities 213,351 268,141
---------------- ----------------
Total current liabilities 425,015 364,278
---------------- ----------------
Deferred income taxes - net 566,645 610,272
---------------- ----------------
Deferred income 102,935 117,508
---------------- ----------------
Beaver Valley lease liability 475,570 475,570
---------------- ----------------
Other non-current liabilities 322,902 314,274
---------------- ----------------
Commitments and contingencies (Note 4)
---------------- ----------------
TOTAL CAPITALIZATION AND LIABILITIES $ 3,985,104 $ 4,175,128
================ ================
</TABLE>
See notes to condensed consolidated financial statements.
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DUQUESNE LIGHT COMPANY
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
----------------------------------------
1999 1998
------------- -------------
<S> <C> <C>
Cash Flows From Operating Activities
Operations $ 257,328 $ 318,375
Purchase of nuclear fuel (40,109) --
Changes in working capital other than cash 17,073 (65,862)
Increase in ECR -- (19,219)
Other (1,115) 2,886
-------------- --------------
Net Cash Provided By Operating Activities 233,177 236,180
-------------- --------------
Cash Flows From Investing Activities
Construction expenditures (57,954) (69,050)
Long-term investments (4,022) (25,497)
Other (20,873) 161
-------------- --------------
Net Cash Used in Investing Activities (82,849) (94,386)
-------------- --------------
Cash Flows From Financing Activities
Dividends on capital stock (179,633) (94,672)
Reductions of long-term obligations - net (70,946) (36,732)
Increase in notes payable 66,000 --
Other 608 (7,064)
-------------- --------------
Net Cash Used in Financing Activities (183,971) (138,468)
-------------- --------------
Net (decrease) increase in cash and temporary cash investments (33,643) 3,326
Cash and temporary cash investments at beginning of period 53,151 165,169
-------------- --------------
Cash and temporary cash investments at end of period $ 19,508 $ 168,495
============== ==============
Non-Cash Investing and Financing Activities
Capital lease obligations recorded $ 6,470 $ 5,011
============== ==============
</TABLE>
See notes to condensed consolidated financial statements.
4
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Duquesne Light Company
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
----------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
NET INCOME AFTER EXTRAORDINARY ITEM $ 37,040 $ 48,243 $ 101,484 $ 29,700
Other Comprehensive Income (Loss):
Unrealized holding (losses) gains
net of tax of $(1,710), $1,328, $(3,908)
and $2,341, respectively (2,383) 1,873 (5,483) 3,301
Less: reclassification adjustment for
gains included in net income, net of
tax of $0, $0, $756 and $0, respectively -- -- (1,404) --
------------ ------------ ------------ ------------
Total Other Comprehensive (Loss) Income (2,383) 1,873 (6,887) 3,301
------------ ------------ ------------ ------------
Comprehensive Income $ 34,657 $ 50,116 $ 94,597 $ 33,001
============ ============ ============ ============
</TABLE>
See notes to condensed consolidated financial statements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES
Duquesne Light Company (Duquesne) is a wholly owned subsidiary of DQE, Inc.
(DQE), a multi-utility delivery and services company. Duquesne is engaged in the
generation, transmission, distribution and sale of electric energy. Duquesne has
one wholly owned subsidiary, Monongahela Light and Power Company, which makes
long-term investments.
Duquesne plans to divest itself of its generation assets through the
pending exchange of certain power station assets with FirstEnergy Corporation
(FirstEnergy), and the pending sale of generation assets to Orion Power
Holdings, Inc. (Orion). Final agreements governing the sale to Orion must be
approved by various regulatory agencies, including the Pennsylvania Public
Utility Commission (PUC). Duquesne currently expects these transactions to close
in December 1999 and the second quarter of 2000, respectively. (See "Rate
Matters," Note 2, on page 7.)
The condensed consolidated financial statements include the accounts of
Duquesne and its wholly owned subsidiary. All material intercompany balances
and transactions have been eliminated in the preparation of the condensed
consolidated financial statements.
In the opinion of management, the unaudited condensed consolidated
financial statements included in this report reflect all adjustments that are
necessary for a fair presentation of the results of interim periods and are
normal, recurring adjustments. Prior periods have been reclassified to conform
with current accounting presentations.
These statements should be read with the financial statements and notes
included in the Annual Report on Form 10-K filed with the Securities and
Exchange Commission (SEC) for the year ended December 31, 1998. The results of
operations for the three and nine months ended September 30, 1999, are not
necessarily indicative of the results that may be expected for the full
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year. The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements. The reported amounts of revenues and expenses during the reporting
period may also be affected by the estimates and assumptions management is
required to make. Actual results could differ from those estimates.
Duquesne is subject to the accounting and reporting requirements of the
SEC. In addition, Duquesne's electric utility operations are subject to
regulation by the PUC, including regulation under the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Customer Choice Act), and the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters.
As a result of the PUC's May 29, 1998, final order regarding Duquesne's
restructuring plan under the Customer Choice Act (see "Rate Matters," Note 2, on
page 7), the electricity generation portion of Duquesne's business does not meet
the criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, 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 and for Long-Lived Assets to Be Disposed Of
(SFAS No. 121). Pursuant to the PUC's final restructuring order, certain of
Duquesne's generation-related regulatory assets are being recovered through a
competitive transition charge (CTC) collected in connection with providing
transmission and distribution services (the electricity delivery business
segment), and have been reclassified accordingly. Additionally, pursuant to the
PUC's final restructuring order, Duquesne is recovering its above-market
investment in generation assets through the CTC, subject to receipt of the
proceeds from the generation asset auction. The electricity delivery business
segment continues to meet 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," Note 2, on page 7.)
Through the Energy Cost Rate Adjustment Clause (ECR), Duquesne previously
recovered (to the extent that such amounts were not included in base rates)
nuclear fuel, fossil fuel and purchased power expenses. Also through the ECR,
Duquesne 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 order regarding Duquesne's restructuring plan (see "Rate Matters," Note 2,
on page 7), such costs are no longer recoverable through the ECR. Instead,
effective May 29, 1998 (the date of the PUC's final restructuring order), such
costs are expensed as incurred and thus impact net income. (See "Restructuring
Plan" discussion, Note 2, on page 8.)
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
$34.9 million ($20.4 million, net of tax) at September 30, 1999, and $46.5
million ($27.3 million, net of tax) at December 31, 1998. (See "Power Station
Exchange" discussion, Note 2, on page 8.)
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2. RATE MATTERS
Competition and the Customer Choice Act
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 process,
utilities had assets recorded on their balance sheets at above-market costs,
thus creating transition costs.
In Pennsylvania, the Customer Choice Act went into effect on 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, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act 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 (which ended in December
1998) and a phase-in to competition period (which began in January 1999).
Phase-In to Competition
Currently 66 percent of customers are eligible to participate in customer
choice (including customers covered by the pilot program); all customers will
have customer choice in January 2000. As of September 30, 1999, approximately 17
percent of Duquesne's customers had chosen alternative generation suppliers,
representing approximately 22 percent of Duquesne's non-coincident peak load.
Customers that have chosen an electricity generation supplier other than
Duquesne pay that supplier for generation charges, and pay Duquesne the CTC
(discussed below) and charges for transmission and distribution. Customers that
continue to buy their generation from Duquesne pay for their service at current
regulated tariff rates divided into generation, transmission and distribution
charges, and the CTC. Under the Customer Choice Act, an electric distribution
company, such as Duquesne, remains a regulated utility and may only offer PUC-
approved rates, including generation rates. Also under the Customer Choice Act,
electricity delivery (including transmission, distribution and customer service)
remains regulated in substantially the same manner as under historical
regulation.
In an effort to "jumpstart" competition, Duquesne had made 600 megawatts
(MW) of power available through the first six months of 1999 to licensed
electric generation suppliers, to be used to supply electricity to Duquesne's
customers who had chosen alternative generation suppliers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, was
originally imposed on the transmission and distribution charges of Pennsylvania
electric utility companies under the Customer Choice Act. As part of a
settlement regarding recovery of deferred fuel costs (discussed below), Duquesne
has agreed to extend this rate cap for an additional six months through the end
of 2001. 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 Plan
In its May 29, 1998, final restructuring order, the PUC determined that
Duquesne should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The $1.49 billion, net of tax, of transition costs
was originally to be recovered over a seven-year period ending in 2005.
However, by applying expected net proceeds of the generation asset auction
(discussed below) to reduce transition costs, Duquesne currently anticipates
early termination of the CTC collection period in 2001 for most major rate
classes. In addition, the transition costs as reflected on the consolidated
balance sheet are being amortized over the same period that the CTC revenues are
being recognized. Duquesne is allowed to earn an 11 percent pre-tax return on
the unrecovered, net of tax balance of transition costs, as adjusted following
the generation asset auction.
As part of its restructuring plan filing, Duquesne requested recovery of
$11.5 million ($6.7 million, net of tax) through the CTC for energy costs
previously deferred under the ECR. Recovery of this amount was approved in the
PUC's final restructuring order. Duquesne also requested recovery of an
additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On
December 18, 1998, the PUC denied recovery of this additional amount. Duquesne
appealed the PUC's denial of recovery to the Pennsylvania Commonwealth Court. On
October 26, 1999, Duquesne and the Pennsylvania Office of the Consumer Advocate
reached a settlement on this issue which would permit recovery of the entire
$42.7 million ($24.9 million, net of tax) in deferred fuel costs. The PUC's
decision on this settlement is pending.
Auction Plan. On December 18, 1998, the PUC approved Duquesne's auction
plan, including a purchased power agreement covering Duquesne's obligations for
its provider of last resort service, as well as an agreement in principle to
exchange certain generation assets with FirstEnergy. On September 24, 1999,
Duquesne and the winning auction bidder, Orion, entered into definitive
agreements pursuant to which Orion will purchase Duquesne's wholly owned
Cheswick, Elrama, Phillips and Brunot Island power stations, and the stations to
be received from FirstEnergy in the power station exchange described below, for
approximately $1.71 billion. Under the purchased power agreement, Orion will
supply all of the electric energy requirements for Duquesne's customers who have
not chosen an alternative generation supplier (provider of last resort
services). This arrangement, which expires upon Duquesne's final collection of
the CTC, effectively transfers to Orion all of the financial risks and rewards
associated with electricity supply. The purchase must be approved by various
regulatory agencies, including the PUC, the FERC, and the Federal Trade
Commission. Duquesne currently expects the sale to close in the second quarter
of 2000. Although Duquesne expects to apply the net auction proceeds to reduce
transition costs, until the divestiture is complete, Duquesne has been ordered
to use an interim CTC and price to compare for each rate class based on the
methodology approved in its pilot program (on average, approximately 2.9 cents
per kilowatt hour (KWH) for the CTC and approximately 3.8 cents per KWH for the
price to compare).
Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in
certain power stations. Duquesne will receive 100 percent ownership rights in
three fossil-fired power plants located in Avon Lake and Niles, Ohio and New
Castle, Pennsylvania (totaling approximately 1,300 MW), which Duquesne plans to
sell as part of the auction of generation assets. FirstEnergy will 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 MW). In connection with the power
station exchange, Duquesne anticipates terminating the BV Unit 2 lease in the
fourth quarter of 1999. (See "Financing" discussion on page 21.) Pursuant to the
December 18, 1998, PUC order and subject to final approval, the proceeds from
the sale to Orion of the power stations received in the exchange will be used to
offset the transition costs associated with Duquesne's currently-held generation
assets and costs associated with completing the exchange. Benefits of this
exchange include the resolution of all joint ownership issues, and other ongoing
risks and costs associated with the jointly-owned units. The Federal Trade
Commission approved the exchange on June 30, 1999. The PUC approved the
definitive exchange agreement on July 15, 1999,
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having found the exchange to be in the public interest. On September 15, 1999,
the FERC approved the exchange. On September 30, 1999, the NRC approved the
transfer of the BV Unit 1 and BV Unit 2 operating licenses, as well as
Duquesne's ownership interest in Perry, to FirstEnergy. The Public Utilities
Commission of Ohio approved the exchange agreement on October 28, 1999. The
power station exchange is expected to occur in December 1999. (See "Legal
Proceedings" on page 27.)
Termination of the AYE Merger
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement with Allegheny Energy, Inc. (AYE). DQE believes that AYE suffered a
material adverse effect as a result of the PUC's final restructuring order
regarding AYE's utility subsidiary, West Penn Power Company. AYE 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. Trial was held from October 20 through 28, 1999. Post-trial pleadings
were filed November 10, 1999, and closing arguments are scheduled for November
23, 1999. Duquesne expects the judge's decision prior to the scheduled closing
of the power station exchange in December. (See "Legal Proceedings" on page 27.)
In a letter dated February 24, 1999, the PUC informed DQE that the merger
application was deemed withdrawn and the docket was closed.
3. RECEIVABLES
Components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
September 30, September 30, December 31,
1999 1998 1998
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 97,005 $ 99,608 $ 87,262
Other utility receivables 27,733 28,306 25,412
Other receivables 21,764 29,430 22,419
Less: Allowance for uncollectible accounts (9,520) (15,281) (9,137)
- --------------------------------------------------------------------------------------------------------
Receivables less allowance for uncollectible accounts 136,982 142,063 125,956
Less: Receivables sold (50,000) -- --
========================================================================================================
Total Receivables $ 86,982 $142,063 $125,956
========================================================================================================
</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. The accounts receivable sales agreement, the
expiration of which has been extended until February 2000, is one of many
sources of funds available to Duquesne. Duquesne currently anticipates further
extending the agreement or replacing it with a similar arrangement upon
expiration. At September 30, 1999, Duquesne had sold $50 million of
receivables. At September 30 and December 31, 1998, Duquesne had not sold any
receivables.
4. COMMITMENTS AND CONTINGENCIES
Duquesne anticipates divesting itself of its generation assets through the
power station exchange with FirstEnergy in December 1999, and the sale to Orion
in the second quarter of 2000 and, depending on the regulatory approvals of the
final agreements regarding the divestiture, expects certain obligations related
to the divested assets will be transferred to the future owners. (See
"Restructuring Plan" discussion, Note 2, on page 8.)
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Construction
Duquesne currently estimates that during 1999 it will spend, excluding the
Allowance for Funds Used During Construction and nuclear fuel, approximately
$110 million (including $30 million for generation) for electric utility
construction.
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. As part of the power station exchange, FirstEnergy
has agreed to assume the decommissioning liability for each of the nuclear
plants in exchange for the balance in the decommissioning trust funds described
below, plus the decommissioning costs to be collected through the CTC, as
approved by the PUC. Duquesne expects BV Unit 1, BV Unit 2 and Perry Unit 1
will be decommissioned 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, would be $170 million, $55 million and $90 million,
respectively. The amount currently used to determine Duquesne's cost of service
related to decommissioning all three nuclear units is $224 million. 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, 1999, totaled approximately $69.8 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 $9.7
billion. The maximum available private primary insurance of $200 million has
been purchased by Duquesne. Additional protection of $9.5 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 $7.9 million. Duquesne also 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 a period of approximately three years,
starting 12 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 $2.9 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
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the steam generator tubes of both units. BV Unit 1, which was placed in service
in 1976, has removed approximately 17 percent of its steam generator tubes from
service through a process called "plugging." However, BV Unit 1 still has the
capability to operate at 100 percent reactor power and has the ability to return
tubes to service by repairing them through a process called "sleeving." No tubes
at either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was
placed in service 11 years after BV Unit 1, has not yet exhibited the degree of
ODSCC experienced at BV Unit 1. Approximately 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 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. Based on its current ownership interest in BV Unit 1, Duquesne
would be responsible for $59 million of this total, which includes the cost of
equipment removal and replacement steam generators, but excludes replacement
power costs. The earliest that the BV Unit 1 steam generators could be replaced
during a currently scheduled refueling outage is the spring of 2003.
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 2018, 2012 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, denied the relief requested by
the utilities and states and permitted the DOE to pursue alternative dispute
resolution, but prohibited the DOE from using its lack of a spent fuel
repository as a defense. The United States Supreme Court declined to review the
decision. The utilities' remaining remedies are to sue the DOE in federal court
for money damages caused by the DOE's delay in fulfilling its obligations, or to
pursue an equitable contract adjustment before the DOE contracting officer.
Duquesne has elected not to participate in further litigation regarding this
matter. Pursuant to the power station exchange, FirstEnergy will assume
responsibility for disposal of the spent fuel.
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, and are to be paid by such utilities over a 15-year period.
At September 30, 1999, Duquesne's liability for contributions is being recovered
through the CTC as part of transition costs.
11
<PAGE>
Guarantees
Duquesne and the other owners of Bruce Mansfield Power Station (Bruce
Mansfield) have guaranteed certain debt and lease obligations related to a coal
supply contract for Bruce Mansfield. At September 30, 1999, Duquesne's share of
these guarantees was $4.5 million. These guarantees expire in January 2000.
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.
On November 3, 1999, the Environmental Protection Agency and the Department
of Justice filed suit against seven electric utility companies, including
FirstEnergy. The suit alleges that the companies made illegal modifications to
certain power plants, including Sammis, which is operated by FirstEnergy.
Although not a party to the suit, Duquesne is currently a partial owner of
Sammis Unit 7 (one of the interests to be acquired by FirstEnergy in the power
station exchange). The ultimate outcome of this suit, and any potential impact
it may have on Duquesne, cannot be determined at this time.
Employees
As previously reported, in connection with the anticipated divestiture,
Duquesne has developed early retirement programs and enhanced separation
packages. To date, approximately 250 eligible employees have elected to
participate in early retirement.
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.
5. BUSINESS SEGMENTS AND RELATED INFORMATION
Historically, Duquesne has been treated as a single integrated business
segment due to its regulated operating environment. The PUC authorized a
combined rate for supplying and delivering electricity to customers which was
cost-based and was designed to recover Duquesne's operating expenses and
investment in electric utility assets and to provide a return on the investment.
As a result of the Customer Choice Act, generation of electricity is deregulated
and charged at a separate rate from the delivery of electricity beginning in
1999. For the purposes of complying with SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information (SFAS No. 131), Duquesne is
required to disclose information about its business segments separately.
Accordingly, Duquesne has used the PUC-approved separate rates for 1999 to
develop the financial information of the business segments for the three and
nine months ended September 30, 1998 (or as of December 31, 1998, with respect
to assets).
Beginning in 1999, Duquesne has three principal business segments
(determined by products, services and regulatory environment) which consist of
the transmission and distribution by Duquesne of electricity (electricity
delivery business segment); the generation by Duquesne of electricity
(electricity generation business segment); and the collection of transition
costs (CTC business segment). To comply with SFAS No. 131, Duquesne has reported
the results for 1999 by these business segments and an "all other" category. The
all other category in the following table includes Duquesne investments below
the quantitative threshold for separate disclosure. However, as Duquesne was not
yet collecting transition costs prior to 1999, the 1998 results are reported by
the electricity delivery and electricity generation business segments.
Financial data for business segments is provided as follows:
12
<PAGE>
Business Segments for the Three Months Ended
- -----------------------------------------------------------------------------
<TABLE>
<CAPTION>
September 30, 1999 (Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------------
Electricity Electricity All
Delivery Generation CTC Other Consolidated
------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 95,848 $ 129,742 $ 107,840 $ 2,735 $ 336,165
Operating expenses 53,467 125,606 23,466 7,611 210,150
Depreciation and
amortization expense 7,670 2,176 46,075 4,858 60,779
- -----------------------------------------------------------------------------------------------------------
Operating income (loss) 34,711 1,960 38,299 (9,734) 65,236
Other income (loss) (1,653) (1,767) -- 7,885 4,465
Interest and other charges 9,065 11,772 11,908 952 33,697
- -----------------------------------------------------------------------------------------------------------
Earnings (loss) for
common stock $ 23,993 $ (11,579) $ 26,391 $ (2,801) $ 36,004
===========================================================================================================
Assets $ 1,297,693 $ 561,111 $ 1,977,305 $ 148,995 $ 3,985,104
===========================================================================================================
Capital expenditures $ 10,446 $ 6,748 $ -- $ -- $ 17,194
===========================================================================================================
</TABLE>
<TABLE>
<CAPTION>
September 30, 1998 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------
Electricity Electricity All Other
Delivery Generation Consolidated
-----------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $ 89,250 $ 237,724 $ 1,047 $ 328,021
Operating expenses 50,954 176,325 1,054 228,333
Depreciation and
amortization expense 14,088 21,075 -- 35,163
- ------------------------------------------------------------------------------------------------------------
Operating income (loss) 24,208 40,324 (7) 64,525
Other income 829 1,955 4,123 6,907
Interest and other charges 9,332 14,506 345 24,183
- ------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ 15,705 $ 27,773 $ 3,771 $ 47,249
============================================================================================================
Assets(1) $ 1,314,266 $ 2,711,533 $ 149,329 $ 4,175,128
============================================================================================================
Capital expenditures $ 21,509 $ 12,920 $ -- $ 34,429
============================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1998.
13
<PAGE>
Business Segments for the Nine Months Ended
- -----------------------------------------------------------------------------
<TABLE>
<CAPTION>
September 30, 1999 (Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------
Electricity Electricity All
Delivery Generation CTC Other Consolidated
-----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 259,246 $ 339,155 $ 290,244 $ 3,507 $ 892,152
Operating expenses 145,724 326,108 71,167 8,981 551,980
Depreciation and
amortization expense 42,597 12,084 101,138 4,858 160,677
- ----------------------------------------------------------------------------------------------------------
Operating income (loss) 70,925 963 117,939 (10,332) 179,495
Other income 6 2,208 -- 15,871 18,085
Interest and other charges 27,108 35,294 35,623 1,087 99,112
- ----------------------------------------------------------------------------------------------------------
Earnings (loss) for
common stock $ 43,823 $ (32,123) $ 82,316 $ 4,452 $ 98,468
==========================================================================================================
Assets $ 1,297,693 $ 561,111 $ 1,977,305 $ 148,995 $ 3,985,104
==========================================================================================================
Capital expenditures $ 39,090 $ 18,864 $ -- $ -- $ 57,954
==========================================================================================================
</TABLE>
<TABLE>
<CAPTION>
September 30, 1998 (Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Electricity Electricity All Other
Delivery Generation Consolidated
------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $ 244,547 $ 654,620 $ 1,344 $ 900,511
Operating expenses 142,430 453,882 1,578 597,890
Depreciation and
amortization expense 38,593 108,354 -- 146,947
- -------------------------------------------------------------------------------------------------------------
Operating income (loss) 63,524 92,384 (234) 155,674
Other income 2,471 5,260 18,848 26,579
Interest and other charges 28,364 44,086 538 72,988
- -------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock,
before extraordinary item $ 37,631 $ 53,558 $ 18,076 $ 109,265
Extraordinary item, net of tax -- (82,548) -- (82,548)
- -------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock,
after extraordinary item $ 37,631 $ (28,990) $ 18,076 $ 26,717
=============================================================================================================
Assets(1) $ 1,314,266 $ 2,711,533 $ 149,329 $ 4,175,128
=============================================================================================================
Capital expenditures $ 40,620 $ 28,430 $ -- $ 69,050
=============================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1998.
14
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in
conjunction with Duquesne Light Company's Annual Report on Form 10-K filed with
the Securities and Exchange Commission (SEC) for the year ended December 31,
1998 and its condensed consolidated financial statements, which are set forth on
pages 2 through 14 in Part I, Item 1 of this Report.
General
- -------------------------------------------------------------------------------
Duquesne Light Company (Duquesne) is a wholly owned subsidiary of DQE, Inc.
(DQE), a multi-utility delivery and services company. Duquesne is engaged in the
generation, transmission, distribution and sale of electric energy. Duquesne has
one wholly owned subsidiary, Monongahela Light and Power Company, which makes
long-term investments.
Duquesne plans to divest itself of its generation assets through the
pending exchange of certain power station assets with FirstEnergy Corporation
(FirstEnergy), and the pending sale of generation assets to Orion Power
Holdings, Inc. (Orion). Final agreements governing the sale to Orion must be
approved by various regulatory agencies, including the Pennsylvania Public
Utility Commission (PUC). Duquesne currently expects these transactions to close
in December 1999 and the second quarter of 2000, respectively. (See "Rate
Matters" on page 22.)
Service Territory
Duquesne provides electric service to customers in Allegheny County
(including the City of Pittsburgh), Beaver County and, to a limited extent,
Westmoreland County. (See "Rate Matters" on page 22.) This territory represents
approximately 800 square miles in southwestern Pennsylvania. In addition to
serving approximately 580,000 direct customers, Duquesne also sells electricity
to other utilities.
Regulation
Duquesne is subject to the accounting and reporting requirements of the
SEC. In addition, Duquesne's electric utility operations are subject to
regulation by the PUC, including regulation under the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Customer Choice Act), and the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters. (See "Rate Matters" on page 22.)
Duquesne's electric utility operations are also subject to regulation by
the Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954, as
amended, with respect to the operation of its jointly owned/leased nuclear power
plants, Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and
Perry Unit 1.
As a result of the PUC's May 29, 1998, final order regarding Duquesne's
restructuring plan under the Customer Choice Act (see "Rate Matters" on page
22), the electricity generation portion of Duquesne's business does not meet the
criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, 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 and for Long-Lived Assets to Be Disposed Of
(SFAS No. 121). Pursuant to the PUC's final restructuring order, certain of
Duquesne's generation-related regulatory assets are being recovered through a
competitive transition charge (CTC) collected in connection with providing
transmission and distribution services (the electricity delivery business
segment), and have been reclassified accordingly. Additionally, pursuant to the
PUC's final restructuring order, Duquesne is recovering its above-market
investment in generation assets through the CTC, subject to receipt of the
proceeds from the generation asset auction. The electricity delivery business
segment continues to meet SFAS No. 71 criteria, and accordingly reflects
regulatory assets and liabilities consistent with cost-based ratemaking
15
<PAGE>
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 22.)
Results of Operations
- -------------------------------------------------------------------------------
Overall Performance
In the second quarter of 1998, the PUC issued an order related to
Duquesne's plan to recover its transition costs from electric utility customers.
As a result of the order, Duquesne recorded an extraordinary charge against
earnings of $82.5 million, or $1.06 per share of DQE common stock. The
following discussion of results of operations excludes the impact of such
charge.
Comparison of Three Months Ended September 30, 1999, and September 30,
1998. Duquesne's earnings available for common stock were $36.0 million in the
third quarter of 1999, a decrease of 23.8%. During the latter part of July 1999,
a prolonged, wide-spread heat wave in the eastern half of the United States,
combined with regional capacity constraints, resulted in unexpected net
purchased power costs of approximately $24 million. As a result of these
unprecedented purchased power prices, Duquesne's net revenues did not increase
enough to offset the anticipated increased depreciation and amortization expense
due to amortization of the CTC.
Comparison of Nine Months Ended September 30, 1999, and September 30, 1998.
Duquesne's earnings available for common stock were $98.5 million for the nine
months ended September 30, 1999, a decrease of 9.9%. This decrease is
attributable to the impact of the unprecedented July purchased power prices and
increased depreciation and amortization expense due to amortization of the CTC.
Results by Business Segment
Historically, Duquesne has been treated as a single integrated business
segment due to its regulated operating environment. The PUC authorized a
combined rate for supplying and delivering electricity to customers which was
cost-based and was designed to recover Duquesne's operating expenses and
investment in electric utility assets and to provide a return on the investment.
As a result of the Customer Choice Act, generation of electricity is deregulated
and charged at a separate rate from the delivery of electricity beginning in
1999. For the purposes of complying with SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information (SFAS No. 131), Duquesne is
required to disclose information about its business segments separately.
Accordingly, Duquesne has used the PUC-approved separate rates for 1999 to
develop the financial information of the business segments for 1998.
Beginning in 1999, Duquesne has three principal business segments
(determined by products, services and regulatory environment): (1) the
transmission and distribution by Duquesne of electricity (electricity delivery
business segment), (2) the generation by Duquesne of electricity (electricity
generation business segment), and (3) the collection of transition costs (CTC
business segment). Duquesne has reported the results for 1999 by these business
segments and an "all other" category. The all other category includes Duquesne
investments in leasing and gas reserve transactions. However, as Duquesne was
not yet collecting transition costs prior to 1999, the 1998 results are reported
by the electricity delivery and electricity generation business segments.
(Additional information regarding Duquesne's business segments is set forth in
"Business Segments and Related Information," Note 5 to the condensed
consolidated financial statements on page 12.)
In accordance with Accounting Principles Board Opinion No. 30, Reporting
the Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions (APB 30), a segment of a company's business is reported as
discontinued operations if a formal disposition plan has been approved and the
disposition is expected within 12 months. Duquesne believes that its
electricity generation business segment will meet the criteria of APB 30 for
discontinued operations upon completion of the power station exchange with
FirstEnergy. The allocation of certain costs to the electricity generation
business segment under APB 30 will differ from those allocations presented in
Note 5, Business Segments and Related Information.
16
<PAGE>
Electricity Delivery Business Segment
Comparison of Three Months Ended September 30, 1999, and September 30,
1998. The electricity delivery business segment contributed $24.0 million to
net income in the third quarter of 1999 compared to $15.7 million in the third
quarter of 1998, an increase of 52.9 percent. Operating revenues for this
business segment are primarily derived from Duquesne's delivery of electricity
and services provided to electric generation suppliers.
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.
Operating revenues increased by $6.6 million or 7.4 percent in the third
quarter of 1999 due to a 5.5 percent increase in electricity usage by customers.
The increased sales are driven primarily by the warm weather experienced in
Duquesne's service territory in July. The following table sets forth KWH
delivered to electric utility customers during the third quarter:
<TABLE>
<CAPTION>
KWH Delivered
(In Millions)
---------------------------------
Three Months Ended September 30, 1999 1998 Change
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 1,104.5 1,018.5 8.4 %
Commercial 1,720.8 1,664.8 3.4 %
Industrial 893.3 842.8 6.0 %
- --------------------------------------------------------------------
Sales to Electric Utility Customers 3,718.6 3,526.1 5.5 %
================================================================================
</TABLE>
Operating expenses for the electricity delivery business segment are
primarily made up of costs to operate and maintain the transmission and
distribution system; meter reading and billing costs; customer service;
collection; allocated administrative expenses; income taxes; and non-income
taxes, such as property and payroll taxes. Operating expenses increased $2.5
million or 4.9 percent in the third quarter of 1999.
Depreciation and amortization expense decreased $6.4 million due to less
amortization of a regulatory tax receivable and due to an adjustment recorded in
the third quarter related to new depreciation rates resulting from a life
service study effective January 1, 1999.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In the third quarter of
1999, there was $0.3 million or 2.9 percent less in interest and other charges
compared to the third quarter of 1998. The decrease was the result of the
refinancing of long-term debt at lower interest rates and the maturity of
approximately $75 million of long-term debt during 1998.
Comparison of Nine Months Ended September 30, 1999, and September 30, 1998.
The electricity delivery business segment contributed $43.8 million to net
income in the first nine months of 1999 compared to $37.6 million in the first
nine months of 1998, an increase of 16.5 percent.
Operating revenues increased by $14.7 million or 6.0 percent in the first
nine months of 1999, due to a 3.2 percent increase in electricity usage by
customers. Sales to residential and commercial customers increased due to
weather conditions, while industrial sales were relatively consistent between
years. The following table sets forth KWH delivered to electric utility
customers during the first nine months of 1999 and 1998:
17
<PAGE>
<TABLE>
<CAPTION>
KWH Delivered
(In Millions)
--------------------------------
Nine Months Ended September 30, 1999 1998 Change
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 2,772.9 2,617.8 5.9 %
Commercial 4,618.5 4,478.7 3.1 %
Industrial 2,617.1 2,597.1 0.8 %
- -------------------------------------------------------------------
Sales to Electric Utility Customers 10,008.5 9,693.6 3.2 %
===============================================================================
</TABLE>
Operating expenses for the electricity delivery business segment increased
$3.3 million or 2.3 percent in the first nine months of 1999, primarily due to
the timing of non-recurring charges related to meter reading in both 1999 and
1998.
Depreciation and amortization expense increased $4.0 million or 10.4
percent in the first nine months of 1999 due to additions to the plant and
equipment.
In the first nine months of 1999, there was $1.3 million or 4.4 percent
less in interest and other charges compared to the first nine months of 1998.
The decrease was the result of the refinancing of long-term debt at lower
interest rates and the maturity of approximately $75 million of long-term debt
during 1998.
Electricity Generation and CTC Business Segments
Comparison of Three Months Ended September 30, 1999, and September 30,
1998. In the third quarter of 1999, the electricity generation and CTC business
segments reported net income of $14.8 million compared to $27.8 million for the
third quarter of 1998, a decrease of 46.8 percent.
During 1998, five percent of Duquesne's electric utility customers
participated in the customer choice pilot program under the Customer Choice Act,
and purchased electricity from alternative generation suppliers. Beginning in
1999, up to 66 percent of Duquesne's electric utility customers are eligible to
participate in customer choice. As of September 30, 1999, approximately 17
percent of Duquesne's customers are purchasing electricity from alternative
generation suppliers.
For the electricity generation and CTC business segments, operating
revenues are primarily derived from Duquesne's supply of electricity for
delivery to retail customers, the supply of electricity to wholesale customers
and, beginning in 1999, the collection of generation-related transition costs
from electricity delivery customers. Under fuel cost recovery provisions
effective through May 29, 1998, fuel revenues generally equaled fuel expense, as
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. In 1999, due to the PUC's final restructuring order, fuel
costs are expensed as incurred, and impact net income to the extent fuel costs
exceed amounts included in Duquesne's authorized generation rates. (See "Rate
Matters" on page 22.)
Energy requirements for electric utility customers are reduced as more
customers participate in customer choice. Energy requirements for residential
and commercial customers are also influenced by weather conditions. Warmer
summer and colder winter seasons lead to increased customer use of electricity
for cooling and heating. Commercial energy requirements are also affected by
regional development. Energy requirements for industrial customers are also
influenced by national and global economic conditions.
Short-term sales to other utilities 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, the level of
participation in customer choice, and Duquesne's divestiture of its generation
assets. (See "Rate Matters" on page 22.)
18
<PAGE>
Operating revenues decreased by $0.1 million or 0.1 percent in the third
quarter of 1999. The decrease in revenues can be attributed to a decrease in
energy supplied to electric utility customers due to increased participation in
customer choice, offset by an 80.1 percent increase in energy supplied to other
utilities. As of September 30, 1999, 17.0 percent of residential non-coincident
peak load, 31.0 percent of commercial load, and 9.8 percent of industrial load
have selected alternative generation suppliers. The increase in energy supplied
to other utilities is due to increased capacity available to sell as a result of
participation in customer choice and improved generating station availability.
The following table sets forth KWH supplied for customers who have not chosen an
alternative generation supplier and sales to other utilities:
<TABLE>
<CAPTION>
KWH Supplied
---------------------------------
(In Millions)
Three Months Ended September 30, 1999 1998 Change
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 911.9 956.5 (4.7)%
Commercial 1,241.7 1,575.4 (21.2)%
Industrial 866.9 827.0 4.8 %
- -------------------------------------------------------------------
Sales to Electric Utility Customers 3,020.5 3,358.9 (10.1)%
- -------------------------------------------------------------------
Sales to Other Utilities 919.1 510.2 80.1 %
- -------------------------------------------------------------------
Total Sales 3,939.6 3,869.1 1.8 %
================================================================================
</TABLE>
Operating expenses for the electricity generation and CTC business segments
are primarily made up of energy costs; costs to operate and maintain the power
stations; allocated administrative expenses; and non-income taxes, such as
property and payroll taxes.
Fluctuations in energy costs generally result from changes in the cost of
fuel, the mix between coal and nuclear generation, total KWH supplied, 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.
Operating expenses decreased $27.3 million or 15.5 percent in the third
quarter of 1999 as a result of the reclassification of the interest component of
Beaver Valley lease costs to interest expense and decreased maintenance costs.
In the third quarter of 1999, fuel and purchased power expense decreased by
$1.0 million or 1.2 percent compared to the third quarter of 1998. During the
third quarter of 1998, Duquesne's BV Units 1 and 2 were undergoing outages and
the purchased power volumes were unusually large. The anticipated reduction in
energy costs in 1999 did not occur due to power market conditions during late
July. While purchased power volumes decreased substantially, unprecedented
prices prevented a decline in costs.
Depreciation and amortization expense includes the depreciation of the
power stations' plant and equipment, accrued nuclear decommissioning costs and
the amortization of transition costs. An increase of $27.2 million or 128.9
percent in the third quarter of 1999 was the result of amortization of
transition costs. In 1999, Duquesne began to recover transition costs through an
interim CTC. The total transition costs to be recovered was $1.49 billion, net
of tax, over a seven-year period, as may be adjusted to account for the proceeds
of the generation asset auction (see "Rate Matters" on page 22). Duquesne
records amortization expense for transition costs reflected on the consolidated
balance sheet over the same period as the CTC revenues are being recognized.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In the third quarter of 1999
there was a $9.2 million or 63.2 percent increase in interest and other charges
compared to the third quarter of 1998. The increase reflected the
reclassification of the interest component of Beaver Valley lease costs to
interest expense.
19
<PAGE>
Comparison of Nine Months Ended September 30, 1999, and September 30, 1998.
In the first nine months of 1999, the electricity generation and CTC business
segments reported net income of $50.2 million compared to $53.6 million for the
first nine months of 1998, a decrease of 6.3 percent.
Operating revenues decreased by $25.2 million or 3.9 percent in the first
nine months of 1999. The decrease in revenues can be attributed to a decrease in
energy supplied to electric utility customers due to increased participation in
customer choice and the 1998 recognition of $23.3 million of revenues related to
deferred energy costs. Partially offsetting this decrease was a 91.7 percent
increase in energy supplied to other utilities in the first nine months of 1999,
due to Duquesne's decision to make 600 MW available during the first six
months of 1999 to licensed generation suppliers to stimulate competition, and
increased capacity available to sell as a result of participation in customer
choice. The following table sets forth KWH supplied for customers who have not
chosen an alternative generation supplier and sales to other utilities:
<TABLE>
<CAPTION>
KWH Supplied
---------------------------------
(In Millions)
Nine Months Ended September 30, 1999 1998 Change
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 2,368.6 2,470.1 (4.1)%
Commercial 3,381.1 4,241.0 (20.3)%
Industrial 2,527.0 2,555.9 (1.1)%
- --------------------------------------------------------------------
Sales to Electric Utility Customers 8,276.7 9,267.0 (10.7)%
- --------------------------------------------------------------------
Sales to Other Utilities 2,369.6 1,236.1 91.7 %
- --------------------------------------------------------------------
Total Sales 10,646.3 10,503.1 1.4 %
================================================================================
</TABLE>
Operating expenses decreased $56.6 million or 12.5 percent in the first
nine months of 1999 as a result of decreased energy costs and the
reclassification of the interest component of Beaver Valley lease costs to
interest expense.
In the first nine months of 1999, fuel and purchased power expense
decreased by $35.5 million or 16.4 percent compared to the first nine months of
1998, primarily a result of decreased purchased power volumes and a favorable
power supply mix.
An increase in depreciation and amortization expense of $4.9 million or 4.5
percent in the first nine months of 1999 was primarily the result of the
amortization of transition costs. The total of transition costs to be recovered
was $1.49 billion, net of tax, over a seven-year period, as may be adjusted to
account for the proceeds of the generation asset auction (see "Rate Matters" on
page 22). Duquesne records amortization expense for transition costs reflected
on the consolidated balance sheet over the same period as the CTC revenues are
being recognized.
In the first nine months of 1999 there was a $26.8 million or 60.9 percent
increase in interest and other charges compared to the first nine months of
1998. The increase primarily reflected the reclassification of the interest
component of Beaver Valley lease costs to interest expense.
All Other
Comparison of Three Months Ended September 30, 1999, and September 30,
1998. The all other category reported a $2.8 million loss in the third quarter
of 1999 compared to $3.8 million of earnings in the third quarter of 1998. The
decrease is primarily attributable to decreased investment income due to the
disposition of certain of Duquesne's affordable housing investments.
Comparison of Nine Months Ended September 30, 1999, and September 30, 1998.
The all other category contributed $4.5 million to net income in the first nine
months of 1999 compared to $18.1 million in the first nine months of 1998, a
decrease of 75.4 percent. The decrease is primarily attributable to decreased
investment income due to the disposition of certain of Duquesne's affordable
housing investments and decreased interest income due to a smaller amount of
cash available for investing.
20
<PAGE>
Liquidity and Capital Resources
- --------------------------------------------------------------------------------
Financing
Duquesne expects to meet its current obligations and debt maturities
through the year 2003 with funds generated from operations, through new
financings and short-term borrowings, and through the proceeds from the sale of
generation assets to Orion. At September 30, 1999, Duquesne was in compliance
with all of its debt covenants.
Mortgage bonds in the amount of $75 million matured in July 1999, and were
retired using available cash and short term borrowings.
As discussed previously, Duquesne has entered into an agreement to sell its
generation assets to Orion for approximately $1.71 billion. Duquesne
anticipates using the net proceeds from this sale (currently estimated to be
$1.1 billion) to recapitalize Duquesne and for general corporate purposes.
In connection with the power station exchange with FirstEnergy, Duquesne
anticipates terminating the BV Unit 2 lease in the fourth quarter of 1999; the
lease liability recorded on the consolidated balance sheet would be eliminated,
however the underlying collateralized lease bonds ($370.7 million at September
30, 1999, and anticipated to be $359.2 million upon lease termination) would
become obligations of Duquesne and be recorded on the consolidated balance sheet
as debt. Duquesne anticipates redeeming the bonds on December 1, 2002 (the first
redemption date), using funds generated from operations, the generation asset
auction proceeds, the CTC, and/or through new financings. Duquesne would also
pay approximately $230 million in termination costs, which Duquesne expects to
recover through the proceeds of the generation asset auction and the CTC. (See
"Power Station Exchange" discussion on page 23.)
In connection with customer choice, Duquesne's customer revenues from
operations will be reduced by an amount equal to the generation rate applicable
to those customers choosing alternative generation suppliers (currently
approximately 17 percent of customers). This reduction is expected to be offset
by reduced cash requirements associated with supplying energy. A further impact
on customer revenues is anticipated when the purchased power agreement with
Orion takes effect, and all customers will be buying generation either directly
from alternative suppliers or indirectly from Orion. An additional impact on
customer revenues is expected to occur when the CTC has been fully collected,
which is currently expected to occur in 2001 for most major rate classes. The
foregoing statements are forward-looking regarding the impact on cash flows of
customer choice and Duquesne's divestiture. 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 timing of the receipt of sale
proceeds. (See "Restructuring Plan" on page 23.)
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. Duquesne currently anticipates extending or
replacing the accounts receivable sale arrangement upon its expiration, recently
extended to February 2000. At September 30, 1999, Duquesne had sold $50 million
of receivables.
Duquesne maintains a $225 million revolving credit facility which expires
in September 2000. 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. Facility fees are based on the 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, 1999.
At September 30, 1999, Duquesne had $66 million of commercial paper
borrowings outstanding. During the third quarter the maximum amount of such
borrowings was $126 million, the average daily borrowings was $87.2 million and
the weighted average daily interest rate was 5.34 percent.
21
<PAGE>
Investing
- --------------------------------------------------------------------------------
Duquesne's long-term investments consist of Duquesne's holdings of DQE
common stock, investments in affordable housing, lease investments, alternative
energy investments and nuclear decommissioning trust funds. A total of $8
million was invested in nuclear decommissioning trust funds during each of the
nine month periods ended September 30, 1999, and September 30, 1998.
Rate Matters
- --------------------------------------------------------------------------------
Competition and the Customer Choice Act
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 process,
utilities had assets recorded on their balance sheets at above-market costs,
thus creating transition costs.
In Pennsylvania, the Customer Choice Act went into effect on 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, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act 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 (which ended in December
1998) and a phase-in to competition period (which began in January 1999).
Phase-In to Competition
Currently 66 percent of customers are eligible to participate in customer
choice (including customers covered by the pilot program); all customers will
have customer choice in January 2000. As of September 30, 1999, approximately 17
percent of Duquesne's customers had chosen alternative generation suppliers,
representing approximately 22 percent of Duquesne's non-coincident peak load.
Customers that have chosen an electricity generation supplier other than
Duquesne pay that supplier for generation charges, and pay Duquesne the CTC
(discussed below) and charges for transmission and distribution. Customers that
continue to buy their generation from Duquesne pay for their service at current
regulated tariff rates divided into generation, transmission and distribution
charges, and the CTC. Under the Customer Choice Act, an electric distribution
company, such as Duquesne, remains a regulated utility and may only offer PUC-
approved rates, including generation rates. Also under the Customer Choice Act,
electricity delivery (including transmission, distribution and customer service)
remains regulated in substantially the same manner as under historical
regulation.
In an effort to "jumpstart" competition, Duquesne had made 600 megawatts
(MW) of power available through the first six months of 1999 to licensed
electric generation suppliers, to be used to supply electricity to Duquesne's
customers who had chosen alternative generation suppliers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, was
originally imposed on the transmission and distribution charges of Pennsylvania
electric utility companies under the Customer Choice Act. As part of a
settlement regarding recovery of deferred fuel costs (discussed below), Duquesne
has agreed to extend this rate cap for an additional six months through the end
of
22
<PAGE>
2001. 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 Plan
In its May 29, 1998, final restructuring order, the PUC determined that
Duquesne should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The $1.49 billion, net of tax, of transition costs
was originally to be recovered over a seven-year period ending in 2005.
However, by applying proceeds of the generation asset auction (discussed below)
to reduce transition costs, Duquesne currently anticipates early termination of
the CTC collection period in 2001 for most major rate classes. In addition, the
transition costs as reflected on the consolidated balance sheet are being
amortized over the same period that the CTC revenues are being recognized.
Duquesne is allowed to earn an 11 percent pre-tax return on the unrecovered, net
of tax balance of transition costs, as adjusted following the generation asset
auction.
As part of its restructuring plan filing, Duquesne requested recovery of
$11.5 million ($6.7 million, net of tax) through the CTC for energy costs
previously deferred under the ECR. Recovery of this amount was approved in the
PUC's final restructuring order. Duquesne also requested recovery of an
additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On
December 18, 1998, the PUC denied recovery of this additional amount. Duquesne
appealed the PUC's denial of recovery to the Pennsylvania Commonwealth Court. On
October 26, 1999, Duquesne and the Pennsylvania Office of the Consumer Advocate
reached a settlement on this issue which would permit recovery of the entire
42.7 million ($24.9 million, net of tax) in deferred fuel costs. The PUC's
decision on this settlement is pending.
Auction Plan. On December 18, 1998, the PUC approved Duquesne's auction
plan, including a purchased power agreement covering Duquesne's obligations for
its provider of last resort service, as well as an agreement in principle to
exchange certain generation assets with FirstEnergy. On September 24, 1999,
Duquesne and the winning auction bidder, Orion, entered into definitive
agreements pursuant to which Orion will purchase Duquesne's wholly owned
Cheswick, Elrama, Phillips and Brunot Island power stations, and the stations to
be received from FirstEnergy in the power station exchange described below, for
approximately $1.71 billion. Under the purchased power agreement, Orion will
supply all of the electric energy requirements for Duquesne's customers who have
not chosen an alternative generation supplier (provider of last resort
services). This arrangement, which expires upon Duquesne's final collection of
the CTC, effectively transfers to Orion all of the financial risks and rewards
associated with electricity supply. The purchase must be approved by various
regulatory agencies, including the PUC, the FERC, and the Federal Trade
Commission. Duquesne currently expects the sale to close in the second quarter
of 2000. Although Duquesne expects to apply the net auction proceeds to reduce
transition costs, until the divestiture is complete, Duquesne has been ordered
to use an interim CTC and price to compare for each rate class based on the
methodology approved in its pilot program (on average, approximately 2.9 cents
per kilowatt hour (KWH) for the CTC and approximately 3.8 cents per KWH for the
price to compare).
Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in
certain power stations. Duquesne will receive 100 percent ownership rights in
three fossil-fired power plants located in Avon Lake and Niles, Ohio and New
Castle, Pennsylvania (totaling approximately 1,300 MW), which Duquesne plans to
sell as part of the auction of generation assets. FirstEnergy will 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 MW). In connection with the power
station exchange, Duquesne anticipates terminating the BV Unit 2 lease in the
fourth quarter of 1999. (See "Financing," discussion on page 21.) Pursuant to
the December 18, 1998, PUC order and subject to final approval, the proceeds
from the sale to Orion of the power stations received in the exchange will be
used to offset the transition costs associated with Duquesne's currently-held
generation assets and costs associated with completing the exchange. Benefits of
this exchange include the resolution of all joint ownership issues, and other
ongoing risks
23
<PAGE>
and costs associated with the jointly-owned units. The Federal Trade Commission
approved the exchange on June 30, 1999. The PUC approved the definitive
exchange agreement on July 15, 1999, having found the exchange to be in the
public interest. On September 15, 1999, the FERC approved the exchange. On
September 30, 1999, the NRC approved the transfer of the BV Unit 1 and BV Unit 2
operating licenses, as well as Duquesne's ownership interest in Perry, to
FirstEnergy. The Public Utilities Commission of Ohio approved the exchange
agreement on October 28, 1999. The power station exchange is expected to occur
in December 1999. (See "Legal Proceedings" on page 27.)
Termination of the AYE Merger
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement with Allegheny Energy, Inc. (AYE). DQE believes that AYE suffered a
material adverse effect as a result of the PUC's final restructuring order
regarding AYE's utility subsidiary, West Penn Power Company. AYE 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. Trial was held from October 20 through 28, 1999. Post-trial pleadings
were filed November 10, 1999, and closing arguments are scheduled for November
23, 1999. Duquesne expects the judge's decision prior to the scheduled closing
of the power station exchange in December. (See "Legal Proceedings" on page 27.)
In a letter dated February 24, 1999, the PUC informed DQE that the merger
application was deemed withdrawn and the docket was closed.
Year 2000
- --------------------------------------------------------------------------------
Duquesne has taken extensive and systematic steps to ensure a smooth
transition into the Year 2000. The transition to the Year 2000 became an issue
because many existing computer programs and embedded microprocessors use only
two digits to identify a year (for example, "99" is used to represent "1999").
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. Since 1994, Duquesne has been planning for the Year 2000
with an aggressive strategy to identify information needs, replace or upgrade
equipment and coordinate resources to anticipate the new millennium. Based on
the success to date of the Year 2000 program, Duquesne fully expects normal
operations into the Year 2000 and beyond. Duquesne assembled a Year 2000 team,
comprised of management representatives from all functional areas of Duquesne.
The goal of Duquesne's Year 2000 program is that all components and services
that in any material manner contribute to the operational reliability, customer
relations, safety, revenue, regulatory compliance and reputation of Duquesne be
Year 2000 ready. On June 30, 1999, Duquesne reported to the PUC, the NRC and
the North American Electric Reliability Council (NERC) that all of its mission
critical systems are Year 2000 ready. Duquesne has defined mission critical as
any system that supports the generation of electricity as well as transmission
and delivery of power to customers.
Duquesne's Year 2000 program also addresses all of the its business
critical systems, such as billings, processing orders, and various accounting
and business management functions. These systems have been declared ready as of
September 30, 1999. The Year 2000 team has focused on all three aspects of the
issue: computer software and hardware systems used to support day-to-day
operations; embedded microprocessors which are small electronic devices found in
a wide range of equipment and devices (such as plant components, substation
equipment, elevators, and heating and cooling systems); and 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.
In general, Duquesne's overall strategy to address the Year 2000 issue is
comprised of four phases that, in some cases, are performed simultaneously.
These phases are inventory, assessment, remediation, and testing and
implementation.
24
<PAGE>
Inventory consisted of identifying the various components, equipment,
hardware, and software used in Duquesne's operations that may potentially be
faced with Year 2000 issues. The inventory process, completed in 1998, involved
reviewing existing listings and subsequent verification through physical
inspections and walk-downs.
Assessment, completed in January 1999, consisted of evaluating all
inventoried items for Year 2000 compliance or readiness. This was accomplished
by contacting the vendors and manufacturers, inspecting software and code,
researching the results of other companies' assessment of like components, and
various other means.
Remediation, the third step in the process, addressed the activities
necessary to fix or replace those components that have Year 2000 issues that
will adversely affect Duquesne's operations. Remediation of all mission
critical systems was complete as of June 30, 1999. Of the more than 100,000
components which were inventoried, fewer than 5,000 displayed any Year 2000
issues, and fewer than 100 required any remediation. Remediation is in addition
to previously planned improvements to Duquesne's systems with benefits beyond
Year 2000 solutions, such as total system replacements discussed below.
Testing and implementation, the final step, consists of placing renovated
processes, systems, equipment, and other items into use within Duquesne's
operations. Testing has been performed on all mission critical and business
critical processes, whether or not remediation activities were involved in the
process.
Regulatory Review. Throughout the execution of its Year 2000 plan,
Duquesne has been providing and will continue to provide information on its
activities to regulatory agencies including the PUC, the NRC and the NERC. In
addition to complying with all regulatory requirements (discussed below),
Duquesne has undergone third party audits of mission critical systems. These
independent assessments have confirmed that Duquesne's Year 2000 program
appropriately addressed Year 2000 issues related to its systems and equipment.
. Following eight months of formal proceedings by the PUC during which
all Pennsylvania utilities, including Duquesne, were required to
demonstrate that they were ready for the Year 2000, the PUC
"investigation concludes that the lights will stay on..." (Motion of
PUC Chairman John M. Quain on Docket No. I-00980076, March 31, 1999)
. Duquesne has complied with the NRC's compliance guidelines and has
verified with the NRC that all systems related to power production,
safety and security are ready for Year 2000. In addition, the NRC
conducted a Year 2000 audit of the nuclear power station safety and
operations systems in May 1999.
. NERC, which coordinates the interconnection of all utilities across the
country, has been requested by the DOE to conduct a detailed review of
the national electric power production and delivery infrastructure to
ensure a reliable power supply during the Year 2000 transition period.
Duquesne has provided monthly status reports to NERC. Duquesne's June
30, 1999, report confirmed the Year 2000 readiness of all its
generation, transmission, and distribution systems. In addition,
Duquesne participated in the industry-wide NERC communication drills,
conducted on April 9 and September 9, 1999. All of Duquesne's
communications exercised in these drills performed as expected.
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 understands that many variables outside the
control of Duquesne may have an adverse affect on the ability of Duquesne to
perform its mission critical processes. Management believes that the most
reasonably likely worst case scenario would be a temporary disruption of service
to customers caused by potential disruptions in the operations of critical
suppliers, such as telecommunications. In the event such a scenario occurs, it
is not anticipated that Duquesne would incur a material adverse impact on its
financial position or the consolidated results of operations.
25
<PAGE>
In the normal course of business Duquesne has developed contingency plans
to minimize the risk of interrupted operations. As part of the Year 2000
program, Duquesne has reviewed these plans in terms of Year 2000 related risks,
and either refined the existing plans or developed new contingency plans for all
mission critical and business critical processes. These contingency plans
incorporate numerous mitigation strategies, such as the most appropriate
allocation of staffing resources, the need for additional equipment and
facilities, and special operating procedures, including manual operations and
use of non-computer dependent back-up equipment and procedures.
Duquesne continues to review its operations and its critical external
suppliers and service providers, in order to determine any adverse scenarios it
could face as a result of Year 2000 problems. To date, nothing has been found
that would prevent Duquesne from generating or providing electricity to the
public.
Costs. The estimated total cost of implementing Duquesne's Year 2000 plan
is approximately $49 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 $43 million. Of this amount, approximately $35 million
are capital costs attributable to the licensing and installation of new software
for total system replacements. The remaining $8 million has been expensed as
incurred. Funds for Duquesne's Year 2000 plan have come from Duquesne's
operating and capital budgets. Approximately $4 million of the amount expensed
has come from the $10 million budgeted for 1999 to address Year 2000 issues.
Duquesne does not anticipate that Year 2000 issues and related costs will be
material to Duquesne's operations, financial condition and results of
operations.
The foregoing paragraphs contain forward-looking statements 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, 1999, totaled approximately $69.8 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
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, and include, among others,
the following: DQE's decision not to consummate the merger with AYE; the related
lawsuit initiated by AYE; the timing of the actual transfer of assets pursuant
to Duquesne's auction of its generating assets and the power station exchange;
the nature of the final regulatory approvals regarding the auction and power
station exchange; general and economic and business conditions; industry
capacity; changes in technology; changes in political, social and economic
conditions; the loss of any significant customers; and changes in business
strategy or development plans.
26
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Eastlake Unit 5
In September 1995, Duquesne commenced arbitration against The Cleveland
Electric Illuminating Company (CEI), seeking damages, termination of the
operating agreement for Eastlake Unit 5 (Eastlake) and partition of the parties'
interests in Eastlake through a sale and division of the proceeds. The
arbitration demand alleged, among other things, the improper allocation by CEI
of fuel and related costs; the mismanagement of the administration of the
Saginaw coal contract in connection with the closing of the Saginaw mine, which
historically supplied coal to Eastlake; and the concealment by CEI of material
information. CEI also seeks monetary damages from Duquesne for alleged unpaid
joint costs in connection with the operation of Eastlake. Duquesne removed the
action to the United States District Court for the Northern District of Ohio,
Eastern Division, where it is now pending (Eastlake Litigation). Pursuant to the
agreement regarding the power station exchange between Duquesne and FirstEnergy,
the parties have jointly sought and received a court order staying all
proceedings in the Eastlake Litigation pending the closing of the exchange. Upon
closing, the parties will enter into a settlement agreement dismissing the
Eastlake Litigation. (See "Power Station Exchange" discussion on page 23.)
Termination of the AYE Merger
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement with AYE. More information regarding this termination is set forth in
Duquesne's Current Report on Form 8-K dated October 5, 1998. 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. On October 28, 1998, the judge denied AYE's motion for
the temporary restraining order and preliminary injunction. AYE appealed 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.
On March 11, 1999, the Third Circuit vacated the October 28, 1998, denial
of a preliminary injunction. The Third Circuit remanded the case to the District
Court for further proceedings to address certain issues, including whether AYE
could demonstrate a reasonable likelihood of success on the merits, before
determining whether any injunctive relief is warranted. On March 12, 1999, AYE
filed a motion for a temporary restraining order with the district court, and a
hearing was held that same day. On March 16, 1999, AYE and DQE entered into a
consent agreement, which was approved by the district court on March 18.
Pursuant to the consent agreement, AYE and DQE have agreed, among other things,
that pending the consolidated hearing on AYE's application for a preliminary
injunction and/or an expedited trial on the merits, both parties will give each
other 10 business days' notice before taking or omitting to take any action
which would prevent the merger from qualifying for "pooling of interests"
accounting treatment. This would not prevent either party from entering into any
agreement, but would require the 10 business days' notice prior to closing any
transaction which prevents pooling. The consent agreement, originally scheduled
to terminate on September 16, 1999, was extended by mutual agreement for the
duration of the trial. On March 25, 1999, DQE petitioned the Third Circuit for
rehearing; this petition was denied on June 14, 1999. On June 1, 1999, AYE
informed the PUC that, given the procedural posture of the merger litigation, it
would seek a Federal court order enjoining the closing of the power station
exchange with FirstEnergy because, in its view, such a closing would prevent the
merger from qualifying for "pooling of interests" accounting.
DQE's motion for summary judgment, originally filed December 18, 1998, was
denied on October 19, 1999. DQE will continue to defend itself vigorously
against AYE's claims and intends to pursue a prompt resolution of the
litigation. Trial was held from October 20 through 28, 1999. Post-trial
pleadings were filed November 10, 1999, and closing arguments are scheduled for
November 23, 1999. Duquesne expects the judge's decision prior to the scheduled
closing of the power station exchange in December. The ultimate outcome of this
suit cannot be determined at this time.
27
<PAGE>
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 Report on Form 8-K was filed September 29, 1999, to report the execution
of agreements to sell Duquesne's power plants and provider of last resort
service. No financial statements were filed with this report.
______________________________
28
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
Duquesne Light Company
--------------------------------
(Registrant)
Date November 15, 1999 /s/ Gary L. Schwass
--------------------------- --------------------------------
(Signature)
Gary L. Schwass
Senior Vice President and
Chief Financial Officer
Date November 15, 1999 /s/ Stevan R. Schott
--------------------------- --------------------------------
(Signature)
Stevan R. Schott
Vice President and Controller
(Principal Accounting Officer)
29
<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, 1999 1998 1997 1996 1995 1994
------------------ ---- --------- --------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $ 53,970 $ 75,810 $ 81,592 $ 82,505 $ 89,139 $ 94,646
Other interest 2,837 1,290 752 1,632 2,599 1,095
Monthly Income Preferred Securities
dividend requirements 9,422 12,562 12,562 7,921 - -
Amortization of debt discount, premium
and expense - net 1,908 5,266 5,828 5,973 6,252 6,381
Portion of lease payments representing
an interest factor 35,755 44,146 44,208 44,357 44,386 44,839
-------- -------- -------- -------- -------- --------
Total Fixed Charges $103,892 $139,074 $144,942 $142,388 $142,376 $146,961
-------- -------- -------- -------- -------- --------
EARNINGS:
Income from continuing operations $101,484 $148,548 $141,820 $149,860 $151,070 $147,449
Income taxes 63,501* 74,912* 73,838* 83,008* 92,894* 84,191*
Fixed charges as above 103,892 139,074 144,943 142,388 142,376 146,961
-------- -------- -------- -------- -------- --------
Total Earnings $268,877 $362,534 $360,601 $375,256 $386,340 $378,601
-------- -------- -------- -------- -------- --------
RATIO OF EARNINGS TO FIXED CHARGES 2.59 2.61 2.49 2.64 2.71 2.58
======== ======== ======== ======== ======== ========
</TABLE>
Duquesne's share of the fixed charges of an unaffiliated coal
supplier, which amounted to approximately $1.8 million for the nine months ended
September 30, 1999, has been excluded from the ratio.
*Earnings related to income taxes reflect a $3.0 million decrease for the nine
months ended September 30, 1999, and a $12 million, $17 million, $12 million,
$13.5 million and $13.5 million decrease for the twelve months ended December
31, 1998, 1997, 1996, 1995 and 1994, 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 2.62 for the nine months ended September 30, 1999,
and 2.69, 2.61, 2.72, 2.81 and 2.67 for the twelve months ended December 31,
1998, 1997, 1996, 1995 and 1994, respectively.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,424,216
<OTHER-PROPERTY-AND-INVEST> 178,595
<TOTAL-CURRENT-ASSETS> 266,002
<TOTAL-DEFERRED-CHARGES> 2,116,291
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,985,104
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 766,902
<RETAINED-EARNINGS> 18,431
<TOTAL-COMMON-STOCKHOLDERS-EQ> 785,333
4,500
224,737<F1>
<LONG-TERM-DEBT-NET> 1,060,530
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 66,000
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 145,000
0
<CAPITAL-LEASE-OBLIGATIONS> 16,937
<LEASES-CURRENT> 664
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,681,403
<TOT-CAPITALIZATION-AND-LIAB> 3,985,104
<GROSS-OPERATING-REVENUE> 892,152
<INCOME-TAX-EXPENSE> 53,432
<OTHER-OPERATING-EXPENSES> 659,225
<TOTAL-OPERATING-EXPENSES> 712,657
<OPERATING-INCOME-LOSS> 179,495
<OTHER-INCOME-NET> 18,085
<INCOME-BEFORE-INTEREST-EXPEN> 197,580
<TOTAL-INTEREST-EXPENSE> 96,096<F2>
<NET-INCOME> 101,484
3,016
<EARNINGS-AVAILABLE-FOR-COMM> 98,468
<COMMON-STOCK-DIVIDENDS> 107,738
<TOTAL-INTEREST-ON-BONDS> 55,878
<CASH-FLOW-OPERATIONS> 233,177
<EPS-BASIC> 0
<EPS-DILUTED> 0
<FN>
<F1>Includes $14,129 of Preference Stock.
<F2>Includes $9,422 of Monthly Income Preferred Securities dividend requirements.
</FN>
</TABLE>
