<PAGE>
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, 1997
----------------------
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From __________ to __________
Commission File Number
----------------------
1-956
Duquesne Light Company
----------------------
(Exact name of registrant as specified in its charter)
Pennsylvania 25-0451600
------------ ----------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
-------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 393-6000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such report), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
DQE, Inc. is the holder of all shares of common stock, $1 par value, of Duquesne
Light Company consisting of 10 shares as of September 30, 1997 and October 31,
1997.
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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,
------------------------------- -------------------------------
1997 1996 1997 1996
------------ ------------- ------------ ------------
<S> <C> <C> <C> <C>
Operating Revenues
Sales of Electricity:
Customers - net $307,113 $295,788 $824,248 $822,557
Utilities 6,212 14,599 21,232 45,641
---------- ---------- ---------- ----------
Total Sales of Electricity 313,325 310,387 845,480 868,198
Other 9,513 9,888 32,643 27,456
---------- ---------- ---------- ----------
Total Operating Revenues 322,838 320,275 878,123 895,654
---------- ---------- ---------- ----------
Operating Expenses
Fuel and purchased power 63,031 61,126 165,201 178,986
Other operating 62,337 61,400 189,779 186,121
Maintenance 21,229 19,554 61,529 58,922
Depreciation and amortization 60,493 51,574 171,591 161,532
Taxes other than income taxes 21,140 22,145 60,905 64,403
Income taxes 29,835 34,267 64,012 70,216
---------- ---------- ---------- ----------
Total Operating Expenses 258,065 250,066 713,017 720,180
---------- ---------- ---------- ----------
OPERATING INCOME 64,773 70,209 165,106 175,474
---------- ---------- ---------- ----------
OTHER INCOME 6,028 5,734 18,460 16,575
---------- ---------- ---------- ----------
INCOME BEFORE INTEREST AND
OTHER CHARGES 70,801 75,943 183,566 192,049
INTEREST CHARGES 21,586 21,950 64,499 67,096
MONTHLY INCOME PREFERRED
SECURITIES DIVIDEND
REQUIREMENTS 3,141 3,141 9,422 4,781
---------- ---------- ---------- ----------
NET INCOME 46,074 50,852 109,645 120,172
DIVIDENDS ON PREFERRED AND
PREFERENCE STOCK 1,006 1,004 3,020 3,036
---------- ---------- ---------- ----------
EARNINGS FOR COMMON STOCK $ 45,068 $ 49,848 $106,625 $117,136
========== ========== ========== ==========
</TABLE>
See notes to condensed consolidated financial statements.
2
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DUQUESNE LIGHT COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
1997 1996
------------------- -------------------
ASSETS
<S> <C> <C>
Property, plant and equipment $ 4,670,259 $ 4,608,773
Less: Accumulated depreciation and amortization (2,029,836) (1,891,300)
------------- -------------
Property, plant and equipment - net 2,640,423 2,717,473
------------- -------------
Long-term investments:
Investment in DQE Common Stock 55,425 59,319
Nuclear decommissioning trust 43,589 34,586
Other long-term investments 63,450 68,362
------------- -------------
Total long-term investments 162,464 162,267
------------- -------------
Current assets:
Cash and temporary cash investments 259,242 154,414
Receivables 101,587 105,645
Other current assets, principally material and supplies 100,730 80,594
------------- -------------
Total current assets 461,559 340,653
------------- -------------
Other non-current assets:
Regulatory assets 595,940 636,816
Other 44,214 39,877
------------- -------------
Total other non-current assets 640,154 676,693
------------- -------------
TOTAL ASSETS $ 3,904,600 $ 3,897,086
============= =============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock - $1 par value (shares - 90,000,000
authorized; 10 issued) $ - $ -
Capital surplus 829,494 825,540
Retained earnings 168,001 163,884
------------- -------------
Total common stockholder's equity 997,495 989,424
------------- -------------
Preferred and preference stock before deferred employee stock
ownership plan (ESOP) benefit 242,116 242,605
Deferred ESOP benefit (17,220) (19,533)
------------- -------------
Total preferred and preference stock 224,896 223,072
------------- -------------
Long-term debt 1,200,043 1,271,961
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Total capitalization 2,422,434 2,484,457
------------- -------------
Obligations under capital leases 30,496 28,407
------------- -------------
Current liabilities:
Current maturities and sinking fund requirements 141,148 70,912
Other current liabilities 180,531 150,276
------------- -------------
Total current liabilities 321,679 221,188
------------- -------------
Deferred income taxes - net 693,662 726,517
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Deferred investment tax credits 99,887 106,201
------------- -------------
Deferred income 124,560 139,075
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Other non-current liabilities 211,882 191,241
------------- -------------
Commitments and contingencies (Note 4)
------------- -------------
TOTAL CAPITALIZATION AND LIABILITIES $ 3,904,600 $ 3,897,086
============= =============
</TABLE>
See notes to condensed consolidated financial statements.
3
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DUQUESNE LIGHT COMPANY
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-------------
1997 1996
---- ----
<S> <C> <C>
Cash Flows From Operating Activities
Operations $ 251,704 $ 259,518
Changes in working capital other than cash 14,177 15,913
Other 23,941 28,933
---------- ----------
Net Cash Provided By Operating Activities 289,822 304,364
---------- ----------
Cash Flows From Investing Activities
Construction expenditures (61,681) (53,339)
Long-term investments (7,428) (3,623)
Other 4,867 (3,587)
---------- ----------
Net Cash Used in Investing Activities (64,242) (60,549)
---------- ----------
Cash Flows From Financing Activities
Issuance of preferred stock - 150,000
Dividends on capital stock (106,732) (129,036)
Reductions of long-term obligations - net (16,310) (63,878)
Other 2,290 (7,963)
---------- ----------
Net Cash Used in Financing Activities (120,752) (50,877)
---------- ----------
Net increase in cash and temporary cash investments 104,828 192,938
Cash and temporary cash investments at beginning of period 154,414 2,490
---------- ----------
Cash and temporary cash investments at end of period $ 259,242 $ 195,428
========== ==========
</TABLE>
See notes to condensed consolidated financial statements.
4
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve
risks and uncertainties including, but not limited to, economic, competitive,
governmental and technological factors affecting Duquesne Light Company's
(Duquesne's) operations, markets, products, services and prices, and other
factors discussed in Duquesne's filings with the Securities and Exchange
Commission (SEC).
1. CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES
Duquesne Light Company (Duquesne) is a wholly owned subsidiary of DQE, Inc.
(DQE), an energy services holding company formed in 1989. Duquesne is engaged
in the production, transmission, distribution and sale of electric energy.
Duquesne was formed under the laws of Pennsylvania by the consolidation and
merger in 1912 of three constituent companies. Duquesne has one wholly owned
subsidiary, Monongahela Light and Power Co., also a Pennsylvania corporation,
which makes long term investments.
On August 7, 1997, the shareholders of DQE and Allegheny Energy, Inc.
(AYE), approved a proposed tax-free, stock-for-stock merger. Upon consummation
of the merger, DQE will be a wholly owned subsidiary of AYE. Immediately
following the merger, Duquesne will remain a wholly owned subsidiary of DQE. The
transaction is expected to close in the first half of 1998, subject to approval
of applicable regulatory agencies.
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-period financial statements were
reclassified to conform with the 1997 presentation.
These statements should be read with the financial statements and notes
included in the Annual Report on Form 10-K filed with the SEC for the year ended
December 31, 1996, and the Quarterly Reports on Form 10-Q filed with the SEC for
the quarters ended March 31 and June 30, 1997. The results of operations for
the three and nine months ended September 30, 1997, are not necessarily
indicative of the results that may be expected for the full year. The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements. The
reported amounts of revenues and expenses during the reporting period may also
be affected by the estimates and assumptions management is required to make.
Actual results could differ from those estimates.
Duquesne is subject to the accounting and reporting requirements of the
SEC. In addition, Duquesne's operations are subject to the regulation of the
Pennsylvania Public Utility Commission (PUC) and the Federal Energy Regulatory
Commission (FERC) with respect to rates for interstate sales, transmission of
electric power, accounting and other matters.
5
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Duquesne's consolidated financial statements report regulatory assets and
liabilities in accordance with Statement of Financial Accounting Standards No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71), and
reflect the effects of the current ratemaking process. In accordance with SFAS
No. 71, Duquesne's consolidated financial statements reflect regulatory assets
and liabilities consistent with cost-based, pre-competition ratemaking
regulations. (See "Rate Matters," Note 3, on page 7.)
Duquesne's long-term investments include investments in assets of nuclear
decommissioning trusts and marketable securities accounted for in accordance
with Statement of Financial Accounting Standards No. 115, Accounting for Certain
Investments in Debt and Equity Securities. These investments are classified as
available-for-sale and are stated at market value. The amounts of unrealized
holding gains on investments at September 30, 1997, and December 31, 1996, were
$23.4 million and $19.8 million ($13.7 million and $11.6 million net of tax,
respectively).
Through the Energy Cost Rate Adjustment Clause (ECR), Duquesne recovers (to
the extent that such amounts are not included in base rates) nuclear fuel,
fossil fuel and purchased power expenses and, also through the ECR, passes to
its customers the profits from short-term power sales to other utilities
(collectively, ECR energy costs). Under Duquesne's mitigation plan approved by
the PUC in June 1996, the level of energy cost recovery is capped at 1.47 cents
per kilowatt-hour (KWH) through May 2001. To the extent that current fuel and
purchased power costs, in combination with previously deferred fuel and
purchased power costs, are not projected to be recoverable through this pricing
mechanism, these costs would become transition costs subject to recovery through
a competitive transition charge (CTC). (See "Customer Choice Act" discussion,
Note 3, on page 7.)
2. RECEIVABLES
Components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
September 30, September 30, December 31, 1996
1997 1996
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 94,844 $107,419 $ 92,475
Other utility receivables 18,595 36,626 22,402
Other receivables 7,738 9,143 9,062
Less: Allowance for uncollectible accounts (19,590) (19,073) (18,294)
- --------------------------------------------------------------------------------------------------------------
Total Receivables $101,587 $134,115 $105,645
==============================================================================================================
</TABLE>
Duquesne and an unaffiliated corporation have an agreement that entitles
Duquesne to sell, and the corporation to purchase, on an ongoing basis, up to
$50 million of accounts receivable. At September 30, 1997, September 30, 1996
and December 31, 1996, Duquesne had not sold any receivables to the unaffiliated
corporation. The accounts receivable sales agreement, which expires in June
1998, is one of many sources of funds available to Duquesne. Duquesne may
attempt to extend the agreement, replace it with a similar facility, or
eliminate the agreement, upon expiration.
6
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3. RATE MATTERS
Customer Choice Act
Under the Electricity Generation Customer Choice and Competition Act
(Customer Choice Act), which went into effect on January 1, 1997, Pennsylvania
has become a leader in customer choice. The Customer Choice Act will enable
Pennsylvania's electric utility customers to purchase electricity at market
prices from a variety of electric generation suppliers (customer choice).
Electric utility restructuring will be accomplished through a two-stage process
consisting of a pilot period (running through 1998) and a phase-in period (1999
through 2001). Before the phase-in to customer choice begins in 1999, the PUC
expects utilities to take vigorous steps to mitigate transition costs as much as
possible without increasing the price they currently charge customers. The PUC
will determine what portion of a utility's remaining transition costs will be
recoverable from customers through a CTC. This charge will be paid by consumers
who choose alternative generation suppliers as well as customers who choose
their franchised utility. The CTC could last as long as 2005, providing a
utility a total of up to nine years to recover transition costs, unless extended
as part of a utility's PUC-approved transition plan. An overall four-and-one-
half year price cap will be imposed on the transmission and distribution charges
of electric utility companies. Additionally, electric utility companies may not
increase the generation charge component of prices as long as transition costs
are being recovered, with certain exceptions. If a utility ultimately is unable
to recover its transition costs within the pricing structure and timeframe
approved by the PUC, such stranded costs will be written off.
On August 1, 1997, Duquesne filed its restructuring and merger plan (the
Restructuring Plan) and its stand-alone restructuring plan (the Stand-Alone
Plan) with the PUC. Although the provisions of the Competition Act require a PUC
decision nine months from the filing date (which would be April 30, 1998), the
Pennsylvania Attorney General's Office requested an extension in order to
conduct an investigation into certain competition issues relating to the
Restructuring Plan. Pursuant to an arrangement among Duquesne, the PUC and the
Attorney General, Duquesne anticipates a decision by the PUC (with respect to
the Restructuring Plan if the merger with AYE is approved, or with respect to
the Stand-Alone Plan if the merger is not approved) on or before May 29, 1998.
Both the Restructuring Plan and the Stand-Alone Plan use a market-based
valuation of generation to determine stranded costs. During each year of the
transition period, Duquesne will conduct a competitive solicitation to sell a
substantial block of generation with the resulting market values used to
determine each year's CTC. The CTCs paid by customers will therefore be known
and measurable, as required by the Customer Choice Act. Duquesne also proposes
a valuation to determine the final market value of its generation assets as of
December 31, 2005. This valuation will be performed in mid-2003 by an
independent board of experts and based on the best available market evidence.
The valuation may be triggered prior to 2003 if market prices rise to specified
levels, or if the minimum depreciation and amortization commitment is reached,
thereby ensuring that there will be no over-recovery of stranded costs.
Duquesne is committed to a minimum of $1.7 billion in depreciation and
amortization during the transition period while maintaining rates capped at
current levels. In addition, if revenues exceed expectations or additional cost
savings are available, Duquesne has proposed a return on equity "spillover"
mechanism that will ensure that the related revenues are used to further
mitigate stranded costs. Finally, both the Restructuring Plan and the Stand-
Alone Plan redesign rates to encourage more efficient electricity consumption
and to provide for additional stranded cost mitigation. Duquesne has long
encouraged economic development. Customers will have the opportunity to benefit
from a reduction in the cost of electricity for incremental consumption. This
rate redesign will be combined with the CTC mechanism to increase the potential
to maximize mitigation of stranded costs during the transition period.
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In addition to the common elements in both plans, the Restructuring Plan
also incorporates the expected benefits of the merger with AYE, such as the
anticipated savings to Duquesne, on a nominal basis, of $365 million in
generation-related costs over 20 years, and $9 million in transmission-related
costs and $173 million in distribution-related costs over 10 years. Duquesne
plans to use the generation-related portion of its share of net operating
synergy savings to shorten the stranded cost recovery period. In addition, the
anticipated cost savings are expected to permit Duquesne to increase its minimum
depreciation and amortization commitment by an estimated $160 million, reduce
distribution rates by $25 million in 2001, and freeze distribution rates at this
reduced level until 2005. The merger-related synergies are expected to enable
Duquesne to reduce its stranded costs in 2005 by $200 million.
The foregoing paragraphs contain forward-looking statements (within the
meaning of the Private Securities Litigation Reform Act of 1995) regarding the
results and benefits of restructuring and the merger with AYE. Such forward-
looking statements involve known and unknown risks and uncertainties that may
cause the actual results and benefits to materially differ from those implied by
such statements. Such risks and uncertainties include, but are not limited to,
general economic and business conditions, industry capacity, changes in
technology, integration of the operations of AYE and Duquesne, regulatory
conditions to the merger, the loss of any significant customers, and changes in
business strategy or development plans.
Any estimate of the ultimate level of transition costs depends on, among
other things, the extent to which such costs are deemed recoverable by the PUC,
the ongoing level of Duquesne's costs of operations, regional and national
economic conditions, and growth of Duquesne's sales. Duquesne believes, based
upon prior rulings of the PUC, that it is entitled to recover substantially all
of its transition costs, but cannot predict the outcome of this regulatory
process. In the event the PUC rules that any or all of these transition costs
cannot be recovered through a CTC mechanism or Duquesne fails to satisfy the
requirements of SFAS No. 71, these stranded costs will be written off. (See
"Regulatory Assets and Emerging Issues Task Force" discussion below.) As
Duquesne has substantial exposure to transition costs relative to its size,
significant stranded cost write-offs could have a materially adverse effect on
Duquesne's financial position, results of operations and cash flows. Various
financial covenants and restrictions could be violated if substantial write-off
of assets or recognition of liabilities occurs.
Regulatory Assets and Emerging Issues Task Force
As a result of the application of SFAS No. 71, Duquesne records regulatory
assets on its consolidated balance sheet. The regulatory assets represent
probable future revenue to Duquesne because provisions for these costs are
currently included, or are expected to be included, in charges to electric
utility customers through the ratemaking process.
A company's electric utility operations or a portion of such operations
could cease to meet the SFAS No. 71 criteria for various reasons, including a
change in the FERC regulations or the competition-related changes in the PUC
regulations. (See "Customer Choice Act" discussion above.) Members of the
Emerging Issues Task Force of the Financial Accounting Standards Board (Task
Force) have discussed issues related to the impact of changes in the regulatory
environment for electric utilities. These changes have resulted from
initiatives which are intended to ultimately change the pricing of the
generation of electricity (but not of its transmission or distribution) to
competitive pricing. Although the arrangements vary from state to state, the
regulators are expected to provide (or are providing, such as in the Customer
Choice Act) for a transition period for the generation of electricity from a
fully regulated to a competitive environment. During these transition periods,
mechanisms are being provided for a utility to recover certain assets and
transition costs prior to (and, in some cases, subsequent to) the change to
competition, while at the same time the
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price of electricity generated after the change to competition will be based on
market rates. During this transition period and thereafter, for the foreseeable
future, the transmission and distribution portions of a utility's operations are
expected to continue to be cost of service based rate regulated.
The Task Force has determined that once a transition plan has been
approved, application of SFAS No. 71 to the generation portion of a utility must
be discontinued and replaced by the application of Statement of Financial
Accounting Standards No. 101, Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71 (SFAS No. 101). The
consensus reached by the Task Force provides further guidance that the
regulatory assets and liabilities of the generation portion of a utility to
which SFAS No. 101 is being applied should be determined on the basis of the
source from which the regulated cash flows to realize such regulatory assets and
settle such liabilities will be derived. Under the Customer Choice Act,
Duquesne believes that its generation-related regulatory assets will be
recovered through a CTC collected in connection with providing transmission and
distribution services and Duquesne will continue to apply SFAS No. 71. Fixed
assets related to the generation portion of a utility will be evaluated on the
cash flows provided by the CTC, in accordance with Statement of Financial
Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of (SFAS No. 121). Duquesne believes
that all of its regulatory assets continue to satisfy the SFAS No. 71 criteria
in light of the transition to competitive generation under the Customer Choice
Act and the ability to recover these regulatory assets through a CTC. Once any
portion of Duquesne's electric utility operations is deemed to no longer meet
the SFAS No. 71 criteria, or is not recovered through a CTC, Duquesne will be
required to write off any above-market cost assets, the recovery of which is
uncertain, and any regulatory assets or liabilities for those operations that no
longer meet these requirements. Any such write-off of assets could be
materially adverse to the financial position of Duquesne.
Duquesne's regulatory assets related to generation, transmission and
distribution as of September 30, 1997, were $463.1 million, $37.9 million and
$94.9 million, respectively. The components of all regulatory assets for the
periods presented are as follows:
<TABLE>
<CAPTION>
September 30, December 31,
1997 1996
(Amounts in Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------
<S> <C> <C>
Regulatory tax receivable (a) $356,869 $394,131
Unamortized debt costs (b) 89,229 93,299
Deferred rate synchronization costs (c) 38,285 41,446
Beaver Valley Unit 2 sale/leaseback premium (d) 28,930 30,059
Deferred employee costs (e) 26,949 29,589
Deferred coal costs (see below) 14,563 12,191
DOE decontamination and decommissioning receivable (Note 4) 9,083 9,779
Deferred nuclear maintenance outage costs (f) 4,758 13,462
Other (g) 27,274 12,860
- ---------------------------------------------------------------------------------------------------
Total Regulatory Assets $595,940 $636,816
===================================================================================================
</TABLE>
(a) The deferred tax liabilities that were recorded in accordance with Statement
of Financial Accounting Standards No. 109, Accounting for Income Taxes are
expected to be recovered from customers through rates. The amortization of
the regulatory tax receivable results from reversals of deferred taxes as
depreciation and amortization expense.
(b) The premiums paid to reacquire debt prior to scheduled maturity dates are
deferred for amortization over the life of the debt issued to finance the
reacquisitions.
(c) The deferral of costs incurred from November 1987, when BV Unit 2 and Perry
Unit 1 went into commercial operation, until March 1988, when a rate order
was issued.
(d) The premium paid to refinance the Beaver Valley Unit 2 lease was deferred
for amortization over the life of the lease.
(e) Includes amounts for recovery of accrued compensated absences and accrued
claims for workers' compensation.
(f) Incremental maintenance expense incurred for refueling outages at Duquesne's
nuclear units is deferred for amortization over the period between refueling
outages (generally 18 months).
(g) Includes $7.7 million of costs to achieve the merger savings.
9
<PAGE>
Deferred Coal Costs
The PUC has established two market price coal cost standards for Duquesne.
One applies only to coal delivered at the Bruce Mansfield Power Station (Bruce
Mansfield). The other, the system-wide coal cost standard, applies to coal
delivered to the remainder of Duquesne's system. Both standards are updated
monthly to reflect prevailing market prices of similar coal. The PUC has
directed Duquesne to defer recovery of the delivered cost of coal to the extent
that such cost exceeds generally prevailing market prices for similar coal, as
determined by the PUC. The PUC allows deferred amounts to be recovered from
customers when the delivered costs of coal fall below such PUC-determined
prevailing market prices.
In 1990, the PUC approved a joint petition for settlement that clarified
certain aspects of the system-wide coal cost standard. Duquesne has exercised
options to extend the coal cost standard through March 2000. The unrecovered
cost of Bruce Mansfield coal was $12.0 million and $9.6 million at September 30,
1997, and December 31, 1996. The unrecovered cost of the remainder of the
system-wide coal was $2.6 million at both September 30, 1997, and December 31,
1996. Duquesne believes that all deferred coal costs will be recovered.
Property Held for Future Use
In 1986, the PUC approved Duquesne's request to remove Phillips Power
Station (Phillips) and a portion of Brunot Island (BI) from service and from
rate base. In accordance with Duquesne's Mitigation Plan, 112 megawatts related
to BI Units 2a and 2b were moved from property held for future use to electric
plant in service in 1996. Reliability enhancements at BI are contingent upon
the projects meeting a least-cost test versus other potential sources of peaking
capacity. As part of both the Restructuring Plan and the Stand-Alone Plan,
Duquesne is seeking recovery of its investment and associated costs of Phillips
and BI through a CTC. (See "Customer Choice Act" discussion, Note 3, on page 7.)
In the event that market demand, transmission access or rate recovery do not
support the utilization of these plants, Duquesne may have to write off part or
all of these investments and associated costs. At September 30, 1997, Duquesne's
net of tax investment in Phillips and BI held for future use was $51.6 million
and $18.3 million.
4. COMMITMENTS AND CONTINGENCIES
Construction
Duquesne estimates that it will spend, excluding the Allowance for Funds
Used During Construction and nuclear fuel, approximately $110 million on
construction during 1997. This estimate also excludes any potential
expenditures for reliability enhancements to the BI combustion turbines.
Nuclear-Related Matters
Duquesne has an ownership or leasehold interest in three nuclear units, two
of which it operates. The operation of a nuclear facility involves special
risks, potential liabilities, and specific regulatory and safety requirements.
Specific information about risk management and potential liabilities is
discussed below.
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Nuclear Decommissioning. The PUC ruled that recovery of the
decommissioning costs for Beaver Valley Unit 1 (BV Unit 1) could begin in 1977,
and that recovery of the decommissioning costs for Beaver Valley Unit 2 (BV Unit
2) and Perry Unit 1 could begin in 1988. Duquesne expects to decommission BV
Unit 1, BV Unit 2 and Perry Unit 1 no earlier than the expiration of each
plant's operating license in 2016, 2027 and 2026, respectively. At the end of
its operating life, BV Unit 1 may be placed in safe storage until BV Unit 2 is
ready to be decommissioned, at which time the units may be decommissioned
together.
Based on preliminary site-specific studies conducted in 1997 for BV Unit 1
and BV Unit 2, and an update of the 1994 study for Perry Unit 1, Duquesne's
approximate share of the total estimated decommissioning costs, including
removal and decontamination costs, is $170 million, $55 million and $90 million,
respectively. The amount currently being used to determine Duquesne's cost of
service related to decommissioning all three nuclear units is $224 million.
Duquesne is seeking recovery of any potential shortfall in decommissioning
funding as part of either its Restructuring Plan or its Stand-Alone Plan. (See
"Customer Choice Act" discussion, Note 3, on page 7.)
On July 18, 1996, the PUC issued a Proposed Policy Statement Regarding
Nuclear Decommissioning Cost Estimation and Cost Recovery for the purpose of
obtaining comments from the public. The proposed policy includes guidelines for
site-specific studies to estimate the cost of decommissioning nuclear plants.
The guidelines require that decommissioning studies be performed at least every
five years, address radiological and non-radiological costs, and include a
contingency factor of not more than 10 percent. Under the proposed policy,
annual decommissioning funding levels are based on an annuity calculation
recognizing inflation in the cost estimates and earnings on fund assets. With
respect to the transition to a competitive generation market, the Customer
Choice Act requires that utilities include a plan to mitigate any shortfall in
decommissioning trust fund payments for the life of the facility with any future
decommissioning filings. Duquesne increased its annual funding level by
approximately $5 million earlier in 1997. The annual contributions to the
decommissioning funds (as increased) are approximately $9 million. Funding for
nuclear decommissioning costs is deposited in external, segregated trust
accounts and may be invested in a portfolio of corporate common stock and debt
securities, municipal bonds, certificates of deposit and United States
government securities. Trust fund earnings increase the fund balances and the
related recorded liability. The market value of the aggregate trust fund
balances at September 30, 1997, totaled approximately $43.8 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 $8.9
billion. The maximum available private primary insurance of $200 million has
been purchased by Duquesne. Additional protection of $8.7 billion would be
provided by an assessment of up to $79.3 million per incident on each nuclear
unit in the United States. Duquesne's maximum total possible assessment, $59.4
million, which is based on its ownership or leasehold interests in three nuclear
generating units, would be limited to a maximum of $7.5 million per incident per
year. This assessment is subject to indexing for inflation and may be subject to
state premium taxes. If funds prove insufficient to pay claims, the United
States Congress could impose other revenue-raising measures on the nuclear
industry.
Duquesne's share of insurance coverage for property damage, decommissioning
and decontamination liability is $1.2 billion. Duquesne would be responsible for
its share of any damages in excess of insurance coverage. In addition, if the
property damage reserves of Nuclear Electric Insurance Limited (NEIL), an
industry mutual insurance company that provides a portion of this coverage, are
inadequate to cover claims arising from an incident at any United States nuclear
site covered by that insurer, Duquesne could be assessed retrospective premiums
totaling a maximum of $7.3 million.
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In addition, Duquesne participates in a NEIL program that provides
insurance for the increased cost of generation and/or purchased power during an
unscheduled outage resulting from an insured accident at a nuclear unit. Subject
to the policy deductible, terms and limit, the coverage provides for a weekly
indemnity of the estimated incremental costs during the three-year period
starting 21 weeks after an accident, with no coverage thereafter. If NEIL's
losses for this program ever exceed its reserves, Duquesne could be assessed
retrospective premiums totaling a maximum of $3.4 million.
Beaver Valley Power Station (BVPS) Steam Generators. BVPS's two units are
equipped with steam generators designed and built by Westinghouse Electric
Corporation (Westinghouse). Similar to other Westinghouse nuclear plants,
outside diameter stress corrosion cracking (ODSCC) has occurred in the steam
generator tubes of both units. BV Unit 1, which was placed in service in 1976,
has required removal of approximately 15 percent of its steam generator tubes
from service through a process called "plugging." However, BV Unit 1 continues
to have 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." To date, no tubes at either BV Unit 1 or BV Unit 2 have been
sleeved. BV Unit 2, which was placed in service in 1987, has not yet exhibited
the degree of ODSCC experienced at BV Unit 1. Approximately 2 percent of BV Unit
2's tubes are plugged; however, it is too early in the life of the unit to
determine the extent to which ODSCC may become a problem.
Duquesne has undertaken certain measures, such as increased inspections,
water chemistry control and tube plugging, to minimize the operational impact of
and to reduce susceptibility to ODSCC. Although Duquesne has taken these steps
to allay the effects of ODSCC, the inherent potential for future ODSCC in steam
generator tubes of the Westinghouse design still exists. Material acceleration
in the rate of ODSCC could lead to a loss of plant efficiency, significant
repairs or the possible replacement of the BV Unit 1 steam generators. The total
replacement cost of the BV Unit 1 steam generators is currently estimated at
$125 million. Duquesne would be responsible for $59 million of this total, which
includes the cost of equipment removal and replacement steam generators but
excludes replacement power costs. The earliest that the BV Unit 1 steam
generators could be replaced during a scheduled refueling outage is the fall of
2000.
Duquesne continues to explore all viable means of managing ODSCC, including
new repair technologies, and plans to continue to perform 100 percent tube
inspections during future refueling outages. The most recent refueling outage
for BV Unit 1 began on September 27, 1997. The next refueling outage for BV
Unit 2 is scheduled to begin in March 1998. Duquesne will continue to monitor
and evaluate the condition of the BVPS steam generators. Perry Unit 1 completed
a refueling outage on October 23, 1997. This outage lasted only 40 days, a
record for Perry Unit 1.
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
U.S. Department of Energy (DOE) for the permanent disposal of spent nuclear fuel
and other 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. On
July 23, 1996, the U.S. Court of Appeals for the District of Columbia Circuit,
in response to a suit brought by 25 electric utilities and 18 states and state
agencies, unanimously ruled that the DOE has a legal obligation to begin taking
spent nuclear fuel by January 31, 1998. The DOE has not yet established an
interim or permanent storage facility, and has indicated that it will be unable
to begin acceptance of spent nuclear fuel for disposal by January 31, 1998.
Further, Congress is considering amendments to the Nuclear Waste Policy Act of
1982 that could give the DOE authority to proceed with the development of a
federal interim storage facility. In the event the DOE does not begin accepting
spent nuclear fuel, 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 2016 (end
of operating license), 2013 and 2011, respectively.
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On January 31, 1997, Duquesne joined 35 other electric utilities in filing
a suit in the U.S. Court of Appeals for the District of Columbia against the
DOE. On March 19, 1997, a similar suit filed by 46 states, state agencies and
regulatory commissions was subsequently consolidated with the utilities' suit.
The suits request that the court suspend the utilities' payments into the
Nuclear Waste Fund and place future payments into an escrow account until the
DOE fulfills its obligation to accept spent nuclear fuel. The DOE has requested
that the court delay the litigation while it pursues alternative
dispute resolution under the terms of its contracts with the utilities, which
could further delay the fulfillment by the DOE of its obligations to accept
spent nuclear fuel. The Court is currently considering arguments presented by
the parties on September 25, 1997. Significant additional expenditures for the
storage of spent nuclear fuel at BV Unit 2 and Perry Unit 1 could be required if
the DOE does not fulfill its obligation to accept spent nuclear fuel.
Uranium Enrichment Decontamination and Decommissioning. Nuclear reactor
licensees in the United States are assessed annually for the decontamination and
decommissioning of DOE uranium enrichment facilities. Assessments are based on
the amount of uranium a utility had processed for enrichment prior to enactment
of the National Energy Policy Act of 1992 (NEPA) and are to be paid by such
utilities over a 15-year period. At September 30, 1997, Duquesne's liability for
contributions was approximately $9.3 million (subject to an inflation
adjustment). Contributions, when made, are currently recovered from customers
through the ECR. (See the discussion of the ECR on page 6.)
Fossil Decommissioning
In Pennsylvania, current ratemaking does not allow utilities to recover
future decommissioning costs through depreciation charges during the operating
life of fossil-fired generating stations. Based on studies conducted in 1997,
this amount for fossil decommissioning is currently estimated to be $130 million
for Duquesne's interest in 17 units at six sites. Each unit is expected to be
decommissioned upon the cessation of the final unit's operations. Duquesne has
submitted these estimates to the PUC, and is seeking to recover these costs as
part of either its Restructuring Plan or its Stand-Alone Plan. (See "Customer
Choice Act" discussion, Note 3, on page 7.)
Guarantees
Duquesne and the other owners of Bruce Mansfield have guaranteed certain
debt and lease obligations related to a coal supply contract for Bruce
Mansfield. At September 30, 1997, Duquesne's share of these guarantees was $15.1
million. The prices paid for the coal by the companies under this contract are
expected to be sufficient to meet debt and lease obligations to be satisfied in
the year 2000. The minimum future payments to be made by Duquesne solely in
relation to these obligations are $16.6 million at September 30, 1997.
Residual Waste Management Regulations
In 1992, the Pennsylvania Department of Environmental Protection (DEP)
issued Residual Waste Management Regulations governing the generation and
management of non-hazardous residual waste, such as coal ash. Duquesne is
assessing the sites it utilizes and has developed compliance strategies that are
currently under review by the DEP. Capital costs of $2.5 million were incurred
by Duquesne in 1996 to comply with these DEP regulations. Based on information
currently available,
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an additional $2.8 million will be spent in 1997. The additional capital cost of
compliance through the year 2000 is estimated, based on current information, to
be $17 million. This estimate is subject to the results of groundwater
assessments and DEP final approval of compliance plans.
Environmental Matters
Various federal and state authorities regulate Duquesne with respect to air
and water quality and other environmental matters. Duquesne believes it is in
current compliance with all material applicable environmental regulations.
On July 18, 1997, the Environmental Protection Agency announced new
national ambient air quality standards for ozone and fine particulate matter. To
allow each state time to determine what areas may not meet the standards and to
adopt control strategies to achieve compliance, the ozone standards will not
be implemented until 2004, and the fine particulate matter standards will not be
implemented until 2007 or later. Because appropriate state ambient air
monitoring and implementation plans have not been developed, the costs of
compliance with these new standards cannot be determined by Duquesne at this
time.
Other
Duquesne is involved in various other legal proceedings and environmental
matters. Duquesne believes that such proceedings and matters, in total, will not
have a materially adverse effect on its financial position, results of
operations or cash flows.
___________________________
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Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in
conjunction with Duquesne's Annual Report on Form 10-K filed with the Securities
and Exchange Commission (SEC) for the year ended December 31, 1996 and
Duquesne's condensed consolidated financial statements, which are set forth on
pages 2 through 14 in Part I, Item 1 of this Report.
General
Duquesne Light Company (Duquesne) is a wholly owned subsidiary of DQE, Inc.
(DQE), an energy services holding company formed in 1989. Duquesne is engaged
in the production, transmission, distribution and sale of electric energy.
Duquesne was formed under the laws of Pennsylvania by the consolidation and
merger in 1912 of three constituent companies. Duquesne has one wholly owned
subsidiary, Monongahela Light and Power Co., also a Pennsylvania corporation,
which currently holds energy-related lease investments.
On August 7, 1997, the shareholders of DQE and Allegheny Energy, Inc.
(AYE), approved a proposed tax-free, stock-for-stock merger. Upon consummation
of the merger, DQE will be a wholly owned subsidiary of AYE. Immediately
following the merger, Duquesne will remain a wholly owned subsidiary of DQE.
The transaction is expected to close in the first half of 1998, subject to
approval of applicable regulatory agencies. (See "Proposed Merger" discussion
on page 20.)
Service Territory
Duquesne provides electric service to customers in Allegheny County,
including the City of Pittsburgh, Beaver County and Westmoreland County. (See
"Competition" discussion on page 20.) This represents approximately 800 square
miles in southwestern Pennsylvania, located within a 500-mile radius of one-half
of the population of the United States and Canada. The population of the area
served by Duquesne, based on 1990 census data, is approximately 1,510,000, of
whom 370,000 reside in the City of Pittsburgh. In addition to serving
approximately 580,000 direct customers, Duquesne also sells electricity to other
utilities.
Regulation
Duquesne is subject to the accounting and reporting requirements of the
SEC. In addition, Duquesne's operations are subject to regulation by the
Pennsylvania Public Utility Commission (PUC) 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.
The Electricity Generation Customer Choice and Competition Act (Customer
Choice Act) went into effect in Pennsylvania on January 1, 1997. This
legislation provides for a gradual deregulation of the generation of
electricity, while maintaining regulation of the transmission and distribution
of electricity and related services to customers. On August 1, 1997, Duquesne
filed its restructuring plan with the PUC, setting forth its plan to enable
customers to choose their electric generation supplier. (See "Competition"
discussion on page 20.)
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Duquesne's 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.
Duquesne's consolidated financial statements report regulatory assets and
liabilities in accordance with Statement of Financial Accounting Standards No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71), and
reflect the effects of the current ratemaking process. In accordance with SFAS
No. 71, Duquesne's consolidated financial statements reflect regulatory assets
and liabilities consistent with cost-based, pre-competition ratemaking
regulations. The regulatory assets represent probable future revenue to Duquesne
because provisions for these costs are currently included, or are expected to be
included, in charges to electric utility customers through the ratemaking
process.
Duquesne's operations or a portion of such operations could cease to meet
the SFAS No. 71 criteria for various reasons, including a change in the FERC
regulations or the competition-related changes in the PUC regulations described
above. (See "Competition" discussion on page 20.) Members of the Emerging
Issues Task Force of the Financial Accounting Standards Board (Task Force) have
discussed issues related to the impact of changes in the regulatory environment
for electric utilities. Although the arrangements vary from state to state, the
regulators are expected to provide (or are providing, such as in the Customer
Choice Act) for a transition period for the generation of electricity from a
fully regulated to a competitive environment. During these transition periods,
mechanisms are being provided for a utility to recover certain assets and
transition costs prior to (and, in some cases, subsequent to) the change to
competition, while at the same time the price of electricity generated after the
change to competition will be based on market rates. The Task Force has
determined that once a transition plan has been approved, application of SFAS
No. 71 to the generation portion of a utility must be discontinued and replaced
by the application of Statement of Financial Accounting Standards No. 101,
Regulated Enterprises - Accounting for the Discontinuation of Application of
FASB Statement No. 71 (SFAS No. 101). The consensus reached by the Task Force
provides further guidance that the regulatory assets and liabilities of the
generation portion of a utility to which SFAS No. 101 is being applied should be
determined on the basis of the source from which the regulated cash flows to
realize such regulatory assets and settle such liabilities will be derived.
Under the Customer Choice Act, Duquesne believes that its generation-related
regulatory assets will be recovered through a competitive transition charge
(CTC) collected in connection with providing transmission and distribution
services and Duquesne will continue to apply SFAS No. 71. Fixed assets related
to the generation portion of a utility will be evaluated on the cash flows
provided by the CTC, in accordance with Statement of Financial Accounting
Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of (SFAS No. 121). Duquesne believes that all
of its regulatory assets continue to satisfy the SFAS No. 71 criteria in light
of the transition to competitive generation under the Customer Choice Act and
the ability to recover these regulatory assets through a CTC. Once any portion
of Duquesne's electric utility operations is deemed to no longer meet the SFAS
No. 71 criteria, or is not recovered through a CTC, Duquesne will be required to
write off any above-market cost assets, the recovery of which is uncertain, and
any regulatory assets or liabilities for those operations that no longer meet
these requirements. Any such write-off of assets could be material to the
financial position of Duquesne.
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Results of Operations
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Sales of Electricity to Customers
The third quarter of 1997 increase in total operating revenues was $2.6
million or 0.8 percent, as compared to the third quarter of 1996. Total
operating revenues decreased $17.5 million or 2.0 percent, when comparing the
nine months ended September 30, 1997, to the same period in 1996. Operating
revenues are primarily derived from Duquesne's sales of electricity. The PUC
authorizes rates for electricity sales which are cost-based and are designed to
recover Duquesne's operating expense and investment in electric utility assets
and to provide a return on the investment. (See "Regulation" and "Competition"
discussions on pages 15 and 20.)
Sales to residential and commercial customers are influenced by weather
conditions. Warmer summer and cooler winter seasons lead to increased customer
use of electricity for cooling and heating. Commercial sales are also affected
by regional economic development. Customer revenues fluctuate as a result of
changes in sales volume and changes in fuel and other energy costs, as these
costs are generally recoverable from customers through the Energy Cost Rate
Adjustment Clause (ECR).
Through the ECR, Duquesne recovers (to the extent that such amounts are not
included in base rates) nuclear fuel, fossil fuel and purchased power expenses
and, also through the ECR, passes to its customers the profits from short-term
power sales to other utilities (collectively, ECR energy costs). Under
Duquesne's mitigation plan approved by the PUC in June 1996, the level of energy
cost recovery is capped at 1.47 cents per kilowatt-hour (KWH) through May 2001.
To the extent that current fuel and purchased power costs, in combination with
previously deferred fuel and purchased power costs, are not projected to be
recoverable through this pricing mechanism, these costs would become transition
costs subject to recovery through a competitive transition charge. (See
"Competition" discussion on page 20.)
Net Customer Revenues
Net customer revenues, reflected on the statement of consolidated income,
increased $11.3 million or 3.8 percent in the third quarter of 1997, as compared
to the same period in 1996. The variance can be attributed primarily to an
increase in energy costs, the result of a less favorable generation mix and a
higher cost purchased power market. To a lesser extent, customer revenues were
favorably impacted by an increase of 7.5 percent in industrial (KWH) sales.
Sales to a new customer, an industrial gas supplier, represented 72 percent of
the increase while the remaining industrial increase was due to expansion of one
of Duquesne's largest customers' facilities. Residential and commercial sales
were relatively unchanged when comparing the third quarters of 1997 and 1996.
In the nine months ended September 30, 1997, as compared to the same period in
1996, net customer revenues increased $1.7 million or 0.2 percent. This increase
was due to higher energy costs. For the nine months ended September 30,
1997, industrial KWH sales increased 6.5 percent, as compared to the same period
in 1996. The increase was the result of sales to a new customer, an industrial
gas supplier, and improved business for several of Duquesne's largest industrial
customers. Offsetting the increase in industrial sales were decreases in
residential and commercial sales. Reduced residential and commercial customer
KWH sales of 2.5 percent and 1.7 percent were due to mild temperatures, as
compared to 1996, and resulted in a $3.7 million or 0.6 percent decrease in
revenues.
Sales to Other Utilities
Short-term sales to other utilities are regulated by the FERC and are made at
market rates. Fluctuations in electricity sales to other utilities are related
to Duquesne's customer energy requirements, the energy market and transmission
conditions, and the availability of Duquesne's generating stations. Duquesne's
electricity sales to other utilities in the third quarter of 1997 were
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$8.4 million or 57.4 percent less than in the third quarter of 1996. In a
comparison of the nine months ended September 30, 1997, to the same period in
1996, sales to other utilities decreased $24.4 million or 53.5 percent. The
fluctuations were due to reduced availability of generating capacity as a result
of the sale of Duquesne's 50 percent interest in the Ft. Martin Power Station
(Ft. Martin) in October 1996 and to increased forced outages of the BV Units 1
and 2 and a scheduled refueling outage at Perry Unit 1. Future levels of
short-term sales to other utilities will be affected by market rates and by the
outcome of Duquesne's FERC filings requesting firm transmission access. (See
"Outlook" discussion on page 20.)
Other Operating Revenues
Other operating revenues include Duquesne's non-KWH utility revenues. The
variance in the nine months ended September 30, 1997, as compared to the same
period in 1996, was an increase of $5.2 million or 18.9 percent due in part to
revenues from a second quarter pole attachment settlement.
Operating Expenses
Fuel and Purchased Power Expense. Fluctuations in fuel and purchased power
expense generally result from changes in the cost of fuel, the mix between coal
and nuclear generation, the total KWHs sold, and generating station
availability. Because of the ECR, changes in fuel and purchased power costs did
not impact earnings in the third quarter of 1997 and 1996 or in the nine months
ended September 30, 1997 and 1996.
Fuel and purchased power expense increased $1.9 million or 3.1 percent in the
third quarter of 1997, as compared to the third quarter of 1996, as a result of
increases in purchased power and fossil fuel volumes due to reduced nuclear
availability from forced outages at BV Units 1 and 2 and a scheduled refueling
outage at Perry Unit 1. The increase was partially offset by a 9.2 percent
reduction in sales volume. The decrease of $13.8 million or 7.7 percent
for fuel and purchased power expense in the nine months ended September 30,
1997, as compared to the same period in 1996, was a reflection of the 10.4
percent decrease in sales volume. The decrease was partially offset by increased
purchased power prices.
Maintenance Expense. In comparing the third quarter of 1997 to the third
quarter of 1996, maintenance expense increased $1.7 million or 8.6 percent. In
the nine months ended September 30, 1997, there was an increase of $2.6 million
or 4.4 percent, as compared to the same period in 1996. During 1997 there were
approximately 45 percent more outage days at nuclear stations than in 1996 due
to forced outages at BV Units 1 and 2 and a scheduled refueling outage at Perry
Unit 1.
Depreciation and Amortization Expense. In the third quarter of 1997,
depreciation and amortization expense increased $8.9 million or 17.3 percent, as
compared to the third quarter of 1996. There was a $10.1 million or 6.2 percent
increase in the nine months ended September 30, 1997, when compared to the same
period in 1996. The increases were the result of accelerated nuclear lease
recovery which began in the second quarter of 1997, as well as increased funding
of the nuclear decommissioning trust, in accordance with the PUC-approved sale
of Ft. Martin.
Taxes Other Than Income Taxes. During the third quarter of 1997 and the first
nine months of 1997, taxes other than income taxes decreased $1.0 million or 4.5
percent and $3.5 million or 5.4 percent, respectively, from the same periods in
1996, due to the reduced West Virginia Business and Occupation taxes as a result
of the sale of Ft. Martin in the fourth quarter of 1996.
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Income Taxes. Income taxes decreased in the third quarter of 1997 and in the
first nine months of 1997, as compared to the same periods in 1996, by $4.4
million and $6.2 million. The variance was due to a decrease in the
Pennsylvania corporate net income tax and lower taxable income.
Interest Charges
There was a decrease of $0.4 million or 1.7 percent in interest charges during
the third quarter of 1997 as compared to the third quarter of 1996. In
comparing the first nine months of 1997 with the first nine months of 1996,
there was a $2.6 million or 3.9 percent decrease in interest charges. The
reason for the decreases was primarily the result of paying down debt of $50
million in the second quarter of 1996 with the proceeds of the Monthly Income
Preferred Securities (MIPS) issued in May 1996.
MIPS Dividend Requirements
The MIPS Dividend Requirements reflect dividend payments related to preferred
securities issued in May 1996. The nine months ended September 30, 1997,
included three full quarters of dividend payments, and the nine months ended
September 30, 1996, included only two full quarters of dividend payments as the
securities were not issued until May 1996.
Liquidity and Capital Resources
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Financing
Duquesne expects to meet its current obligations and debt maturities
through the year 2001 with funds generated from operations and through new
financings. At September 30, 1997, Duquesne was in compliance with all of its
debt covenants.
Mortgage bonds in the amounts of $50 million, $35 million and $35 million
will mature in November 1997, February 1998 and June 1998, respectively.
Duquesne expects to retire these bonds with available cash or to refinance the
bonds.
Duquesne and an unaffiliated corporation have an agreement that entitles
Duquesne to sell, and the corporation to purchase, on an ongoing basis, up to
$50 million of accounts receivable. This accounts receivable sale arrangement
extends through June 1998. Duquesne may attempt to extend the agreement,
replace it with a similar facility, or eliminate the agreement, upon expiration.
Duquesne maintains a $150 million revolving credit facility which expires
in October 1998. Interest rates can, in accordance with the option selected at
the time of the borrowing, be based on prime, Eurodollar or certificate of
deposit rates. Commitment fees are based on the unborrowed amount of the
commitments. The revolving credit facility contains a two-year repayment period
for any amounts outstanding at the expiration of the revolving credit period.
No amounts were outstanding at September 30, 1997.
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Investing
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Duquesne's long-term investments consist of its holdings of DQE common
stock, investments in affordable housing, leasing and other investments, and
Duquesne's nuclear decommissioning trusts. Duquesne invested approximately $7.4
million and $3.6 million in various investments in the nine months ended
September 30, 1997 and 1996, respectively.
Outlook
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Proposed Merger
On August 7, 1997, the shareholders of DQE and AYE approved a proposed tax-
free, stock-for-stock merger. Upon consummation of the merger, DQE will be a
wholly owned subsidiary of AYE. Immediately following the merger, Duquesne will
remain a wholly owned subsidiary of DQE. The transaction is intended to be
accounted for as a pooling of interests. Under the terms of the transaction,
DQE's shareholders will receive 1.12 shares of AYE common stock for each share
of DQE's common stock, and AYE's dividend in effect at the time of the closing
of the merger. The transaction is expected to close in the first half of 1998,
subject to approval of applicable regulatory agencies as discussed above.
Further details about the proposed merger are provided in DQE's report on Form
8-K, filed with the SEC on April 10, 1997, and the Joint Proxy
Statement/Prospectus of DQE and AYE, dated June 25, 1997, which has been
distributed to DQE's shareholders. Unless otherwise indicated, all information
presented in this Form 10-Q relates to Duquesne only and does not take into
account the proposed merger between DQE and AYE.
On August 1, 1997, Duquesne, DQE and AYE had previously filed their
restructuring and merger plans with the FERC, the PUC and the Maryland Public
Service Commission. At that time Duquesne also applied with the NRC for
approval of the indirect transfer of licenses to AYE. Additional filings
related to the merger will be made with other federal agencies, including the
SEC, the Department of Justice and the Federal Trade Commission. Duquesne
cannot predict the outcome of any of these filings.
Competition
The electric utility industry continues to undergo fundamental change in
response to open transmission access and increased availability of energy
alternatives. Under historical PUC ratemaking, 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. As a result of this historical ratemaking
process, utilities have assets recorded on their balance sheets at above-market
costs and have commitments to purchase power at above-market prices (transition
costs).
Under the Customer Choice Act, which went into effect on January 1, 1997,
Pennsylvania has become a leader in customer choice. The Customer Choice Act
will enable Pennsylvania's electric utility customers to purchase electricity at
market prices from a variety of electric generation suppliers (customer choice).
Electric utility restructuring will be accomplished through a two-stage process
consisting of a pilot period (running through 1998) and a phase-in period (1999
through 2001). The pilot period will give utilities an opportunity to examine a
wide range of technical and
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administrative details related to competitive markets, including metering,
billing, and cost and design of unbundled electric services. Duquesne filed a
pilot program with the PUC on February 27, 1997, which proposed unbundling
transmission, distribution, electricity and competitive transition charges and
offered participating customers the same options that were to be available in a
competitive generation market. The pilot program was designed to comprise
approximately 5 percent of Duquesne's residential, commercial and industrial
demand. The approximately 28,000 customers participating in the pilot may
choose unbundled service with their electricity provided by an alternative
electric generation supplier, and will be subject to unbundled distribution
charges approved by the PUC and unbundled transmission charges pursuant to
Duquesne's FERC-approved tariff. Each customer will also be required to pay a
non-bypassable access fee (competitive transition charge or CTC) that would
provide Duquesne with a reasonable opportunity to recover transition costs
during the period and subject to the generation cap discussed below. On May 9,
1997, the PUC issued a Preliminary Opinion and Order approving Duquesne's filing
in part, and requiring certain revisions. Duquesne and other utilities objected
to several features of the PUC's preliminary order. Hearings on several key
issues were held in July. The PUC issued its final order on August 29, 1997,
approving a revised pilot program for Duquesne. On September 8, 1997, Duquesne
appealed the determination of the market price of generation set forth in this
order to the Commonwealth Court of Pennsylvania. Although this appeal is still
pending, Duquesne has complied with the PUC's order to implement the pilot
program which began on November 1, 1997.
It is anticipated that the net financial impact of Duquesne's customers
choosing alternative generation suppliers during the pilot period will be a
reduction of operating revenue of approximately $1 million per month. Until the
PUC rules on Duquesne's Restructuring Plan or Stand-Alone Plan (each as defined
below), in which Duquesne is seeking to maintain its current rates, Duquesne
will establish a reserve for this shortfall. To the extent there is a revenue
shortfall between rates established for the pilot period and rates set upon
approval of the Restructuring Plan or Stand-Alone Plan, the PUC has authorized
Duquesne to establish a regulatory asset for any resulting income impact and
will rule on the recovery of this regulatory asset as part of its approval of
Duquesne's Restructuring Plan or Stand-Alone Plan. To the extent rates for the
Restructuring Plan or Stand-Alone Plan are below current rates, the difference
will be written-off.
The phase-in to competition begins on January 1, 1999, when 33 percent of
consumers will have customer choice (including consumers covered by the pilot
program); 66 percent of consumers will have customer choice by January 1, 2000;
and all consumers will have customer choice by January 1, 2001. Although the
Customer Choice Act will give customers their choice of electric generation
suppliers, delivery of the electricity from the generation supplier to the
customer will remain the responsibility of the existing franchised utility.
Delivery of electricity (including transmission, distribution and customer
service) will continue to be regulated in substantially the current manner.
Before the phase-in to customer choice begins in 1999, the PUC expects utilities
to take vigorous steps to mitigate transition costs as much as possible without
increasing the price they currently charge customers. The PUC will determine
what portion of a utility's remaining transition costs will be recoverable from
customers through a CTC. This charge will be paid by consumers who choose
alternative generation suppliers as well as customers who choose their
franchised utility. The CTC could last as long as 2005, providing a utility a
total of up to nine years to recover transition costs, unless extended as part
of a utility's PUC-approved transition plan. An overall four-and-one-half year
price cap will be imposed on the transmission and distribution charges of
electric utility companies. Additionally, electric utility companies may not
increase the generation price component of prices as long as transition costs
are being recovered, with certain exceptions. If a utility ultimately is unable
to recover its transition costs within the pricing structure and timeframe
approved by the PUC, such stranded costs will be written off.
On August 1, 1997, Duquesne filed its restructuring and merger plan (the
Restructuring Plan) and its stand-alone restructuring plan (the Stand-Alone
Plan) with the PUC. Although the provisions of the Competition Act require a PUC
decision nine months from the filing date (which would be April 30, 1998), the
Pennsylvania Attorney General's Office requested an extension in order to
conduct an investigation into certain competition issues relating to the
Restructuring Plan. Pursuant
21
<PAGE>
to an arrangement among Duquesne, the PUC and the Attorney General, Duquesne
anticipates a decision by the PUC (with respect to the Restructuring Plan if the
merger with AYE is approved, or with respect to the Stand-Alone Plan if the
merger is not approved) on or before May 29, 1998.
Both the Restructuring Plan and the Stand-Alone Plan use a market-based
valuation of generation to determine stranded costs. During each year of the
transition period, Duquesne will conduct a competitive solicitation to sell a
substantial block of generation with the resulting market values used to
determine each year's CTC. The CTCs paid by customers will therefore be known
and measurable, as required by the Customer Choice Act. Duquesne also proposes
a valuation to determine the final market value of its generation assets as of
December 31, 2005. This valuation will be performed in mid-2003 by an
independent board of experts and based on the best available market evidence.
The valuation may be triggered prior to 2003 if market prices rise to specified
levels, or if the minimum depreciation and amortization commitment is reached,
thereby ensuring that there will be no over-recovery of stranded costs.
Duquesne is committed to a minimum of $1.7 billion in depreciation and
amortization during the transition period while maintaining rates capped at
current levels. In addition, if revenues exceed expectations or additional cost
savings are available, Duquesne has proposed a return on equity "spillover"
mechanism that will ensure that the related revenues are used to further
mitigate stranded costs. Finally, both the Restructuring Plan and the Stand-
Alone Plan redesign rates to encourage more efficient electricity consumption
and to provide for additional stranded cost mitigation. Duquesne has long
encouraged economic development. Customers will have the opportunity to benefit
from a reduction in the cost of electricity for incremental consumption. This
rate redesign will be combined with the CTC mechanism to increase the potential
to maximize mitigation of stranded costs during the transition period.
In addition to the common elements in both plans, the Restructuring Plan
also incorporates the expected benefits of the merger with AYE, such as the
anticipated savings to Duquesne, on a nominal basis, of $365 million in
generation-related costs over 20 years, and $9 million in transmission-related
costs and $173 million in distribution-related costs over 10 years. Duquesne
plans to use the generation-related portion of its share of net operating
synergy savings to shorten the stranded cost recovery period. In addition, the
anticipated cost savings are expected to permit Duquesne to increase its minimum
depreciation and amortization commitment by an estimated $160 million, reduce
distribution rates by $25 million in 2001, and freeze distribution rates at this
reduced level until 2005. The merger-related synergies are expected to enable
Duquesne to reduce its stranded costs beginning in 2005 by $200 million.
The foregoing paragraphs contain forward-looking statements (within the
meaning of the Private Securities Litigation Reform Act of 1995) regarding the
results and benefits of restructuring and the merger with AYE. Such forward-
looking statements involve known and unknown risks and uncertainties that may
cause the actual results and benefits to materially differ from those implied by
such statements. Such risks and uncertainties include, but are not limited to,
general economic and business conditions, industry capacity, changes in
technology, integration of the operations of AYE and Duquesne, regulatory
conditions to the merger, the loss of any significant customers, and changes in
business strategy or development plans.
Any estimate of the ultimate level of transition costs depends on, among
other things, the extent to which such costs are deemed recoverable by the PUC,
the ongoing level of Duquesne's costs of operations, regional and national
economic conditions, and growth of Duquesne's sales. Duquesne believes that it
is entitled to recover substantially all of its transition costs, based upon
prior PUC rulings issued to Duquesne, but cannot predict the outcome of this
regulatory process. In the event the PUC rules that any or all of these
transition costs cannot be recovered through a CTC
22
<PAGE>
mechanism or Duquesne fails to satisfy the requirements of SFAS No. 71, these
stranded costs will be written off. (See "Regulation" discussion on page 15.)
As Duquesne has substantial exposure to transition costs relative to its size,
significant stranded cost write-offs could have a materially adverse effect on
Duquesne's financial position, results of operations and cash flows. Various
financial covenants and restrictions could be violated if substantial write-off
of assets or recognition of liabilities occurs.
In addition to the Restructuring Plan and the Stand-Alone Plan, on August
1, 1997, DQE and AYE filed their joint merger application with the FERC (the
FERC Filing). Pursuant to the FERC Filing, DQE and AYE have committed to
forming or joining an independent system operator (ISO) which meets their
requirements following the merger. In addition, DQE and AYE have stated in the
FERC Filing that following the merger Allegheny Energy's market share will not
violate the market power conditions and requirements set by the FERC.
At the national level, in 1996 the FERC issued two related final rules that
address the terms on which electric utilities will be required to provide
wholesale suppliers of electric energy with non-discriminatory access to the
utility's wholesale transmission system. The first rule, Order No. 888, requires
each public utility that owns, controls or operates interstate transmission
facilities to file a tariff offering unbundled transmission services containing
non-rate terms that conform to the FERC's pro forma tariff. Order No. 888 also
allows full recovery of prudently incurred costs from departing customers. FERC
deferred to state regulators with respect to retail access, recovery of retail
transition costs and the scope of state regulatory jurisdiction. The second
rule, Order No. 889, prohibits transmission owners and their affiliates from
gaining preferential access to information concerning transmission and
establishes a code of conduct to ensure the complete separation of a utility's
wholesale power marketing and transmission operation functions.
Finally, the FERC simultaneously issued a new Notice of Proposed Rulemaking
(NOPR) on Capacity Reservation Open Access Transmission Tariffs (CRT), which
would require all market participants to reserve firm capacity rights between
designated receipt and delivery points. If adopted, the CRT would replace the
open access pro forma tariff implemented in Order No. 888.
Duquesne is aware of the foregoing state and federal regulatory and
business uncertainties and is attempting to position itself to effectively
operate in a more competitive environment.
Beaver Valley Power Station (BVPS) Steam Generators
BVPS's two units are equipped with steam generators designed and built by
Westinghouse Electric Corporation (Westinghouse). Similar to other Westinghouse
nuclear plants, outside diameter stress corrosion cracking (ODSCC) has occurred
in the steam generator tubes of both units. The units continue to have the
capability to operate at 100 percent reactor power although 15 percent of BV
Unit 1 and 2 percent of BV Unit 2 steam generator tubes have been removed from
service. Material acceleration in the rate of ODSCC could lead to a loss in
plant efficiency and significant repairs or replacement of BV Unit 1 steam
generators. The total replacement cost of the BV Unit 1 steam generators is
estimated at $125 million, $59 million of which would be Duquesne's
responsibility. The earliest that the BV Unit 1 steam generators could be
replaced during a scheduled refueling outage is the fall of 2000.
23
<PAGE>
Other
In September 1997, Duquesne amended its service contract with Itron, Inc.,
with respect to the Customer Advanced Reliability System (CARS). The amendment
extends by one year into 1998 the period during which Itron, Inc., will install
and finalize the system. As of September 30, 1997, more than 98 percent of
customers' meters had been adapted for CARS, and more than 450,000 meters were
being read automatically.
Duquesne owns Warwick Mine, an underground mine located in southwestern
Pennsylvania. In September 1997, Duquesne completed negotiations and entered
into an agreement with a new unaffiliated contract operator of the mine.
Production of coal under this agreement began in October 1997.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Currently not applicable.
______________________________
Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve
risks and uncertainties including, but not limited to, economic, competitive,
governmental and technological factors affecting Duquesne's operations, markets,
products, services and prices, and other factors discussed in Duquesne's filings
with the SEC.
24
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
In September 1995, Duquesne commenced arbitration against Cleveland
Electric Illuminating Company (CEI), seeking damages, termination of the
Operating Agreement for Eastlake Power Station Unit 5 (Unit) and partition of
the parties' interests in the Unit through a sale and division of the proceeds.
The arbitration demand alleged, among other things, the improper allocation by
CEI of fuel and related costs; the mismanagement of the administration of the
Saginaw coal contract in connection with the closing of the Saginaw mine, which
historically supplied coal to the Unit; and the concealment by CEI of material
information. In October 1995, CEI commenced an action against Duquesne in the
Court of Common Pleas, Lake County, Ohio seeking to enjoin Duquesne from taking
any action to effect a partition on the basis of a waiver of partition contained
in the deed to the land underlying the Unit. CEI also seeks monetary damages
from Duquesne for alleged unpaid joint costs in connection with the operation of
the Unit. Duquesne removed the action to the United States District Court for
the Northern District of Ohio, Eastern Division, where it is now pending.
Duquesne anticipates that a trial will commence in the third quarter of 1998.
On September 29, 1997, the City of Pittsburgh filed a federal antitrust
suit in the United States District Court for the Western District of
Pennsylvania, seeking to enjoin the proposed merger of DQE and AYE. The City is
also seeking unspecified monetary damages from DQE and AYE arising from AYE's
withdrawal of its proposal to provide power to two urban redevelopment sites in
Pittsburgh, both of which are within Duquesne's electric service territory. On
October 27, 1997, Duquesne filed a Motion to Dismiss the City's suit.
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. No Current Report on Form 8-K was filed during the three months ended
September 30, 1997.
______________________________
25
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
DUQUESNE LIGHT COMPANY
----------------------
(Registrant)
Date November 13, 1997 /s/ Gary L. Schwass
------------------------- -----------------------------
(Signature)
Gary L. Schwass
Senior Vice President and
Chief Financial Officer
Date November 13, 1997 /s/ Morgan K. O'Brien
------------------------- -----------------------------
(Signature)
Morgan K. O'Brien
Vice President and Controller
(Principal Accounting Officer)
26
<PAGE>
Exhibit 12.1
Duquesne Light Company and Subsidiary
Calculation of Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31
----------------------
Nine Months Ended
September 30, 1996 1995 1994 1993 1992
1997 ---- ---- ---- ---- ----
----
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $ 61,375 $ 82,505 $ 89,139 $ 94,646 $102,938 $119,179
Other interest 522 1,632 2,599 1,095 2,387 1,749
Monthly Income Preferred Securities dividend 9,422 7,921 - - - -
requirements
Amortization of debt discount, premium and expense - 4,410 5,973 6,252 6,381 5,541 4,223
net
Portion of lease payments representing an interest 33,263 44,357 44,386 44,839 45,925 60,721
factor -------- -------- -------- -------- -------- --------
Total Fixed Charges $108,992 $142,388 $142,376 $146,961 $156,791 $185,872
-------- -------- -------- -------- -------- --------
EARNINGS:
Income from continuing operations $109,645 $149,860 $151,070 $147,449 $144,787 $149,768
Income taxes 62,467* 83,008* 92,894* 84,191* 77,237* 110,993
Fixed charges as above 108,992 142,388 142,376 146,961 156,791 185,872
-------- -------- -------- -------- -------- --------
Total Earnings $281,104 $375,256 $386,340 $378,601 $378,815 $446,633
-------- -------- -------- -------- -------- --------
RATIO OF EARNINGS TO FIXED CHARGES 2.58 2.64 2.71 2.58 2.42 2.40
==== ==== ==== ==== ==== ====
</TABLE>
Duquesne's share of the fixed charges of an unaffiliated coal supplier,
which amounted to approximately $2.1 million for the nine months ended September
30, 1997, has been excluded from the ratio.
*Earnings related to income taxes reflect a $9.0 million decrease for the nine
months ended September 30, 1997, a $12 million, $13.5 million, $13.5 million and
$10.4 million decrease for the twelve months ended December 31, 1996, 1995, 1994
and 1993, respectively, due to a financial statement reclassification related to
Statement of Financial Accounting Standards No. 109, Accounting for Income
Taxes. The ratio of earnings to fixed charges, absent this reclassification,
equals 2.67 for the nine months ended September 30, 1997, and 2.72, 2.81, 2.67
and 2.48 for the twelve months ended December 31, 1996, 1995, 1994 and 1993,
respectively.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,640,423
<OTHER-PROPERTY-AND-INVEST> 162,464
<TOTAL-CURRENT-ASSETS> 461,559
<TOTAL-DEFERRED-CHARGES> 640,154
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,904,600
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 829,494
<RETAINED-EARNINGS> 168,001
<TOTAL-COMMON-STOCKHOLDERS-EQ> 997,495
3,000
221,896<F1>
<LONG-TERM-DEBT-NET> 1,200,043
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 120,000
0
<CAPITAL-LEASE-OBLIGATIONS> 30,496
<LEASES-CURRENT> 21,148
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,310,522
<TOT-CAPITALIZATION-AND-LIAB> 3,904,600
<GROSS-OPERATING-REVENUE> 878,123
<INCOME-TAX-EXPENSE> 64,012
<OTHER-OPERATING-EXPENSES> 649,005
<TOTAL-OPERATING-EXPENSES> 713,017
<OPERATING-INCOME-LOSS> 165,106
<OTHER-INCOME-NET> 18,460
<INCOME-BEFORE-INTEREST-EXPEN> 183,566
<TOTAL-INTEREST-EXPENSE> 73,921<F2>
<NET-INCOME> 109,645
3,020
<EARNINGS-AVAILABLE-FOR-COMM> 106,625
<COMMON-STOCK-DIVIDENDS> 103,000
<TOTAL-INTEREST-ON-BONDS> 65,784
<CASH-FLOW-OPERATIONS> 289,822
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1>Includes $11,287 of Preference Stock
<F2>Includes $9,422 of Monthly Income Preferred Securities Dividend Requirements
</FN>
</TABLE>
