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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 1997
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From to
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Commission File Number
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1-956
Duquesne Light Company
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-0451600
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 393-6000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such report), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
DQE is the holder of all shares of common stock, $1 par value, of Duquesne Light
Company consisting of 10 shares as of March 31, 1997 and April 30, 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
March 31,
--------------------
1997 1996
--------- ---------
<S> <C> <C>
Operating Revenues
Sales of Electricity:
Customers - net $265,349 $266,583
Utilities 8,731 15,965
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Total Sales of Electricity 274,080 282,548
Other 8,929 8,309
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Total Operating Revenues 283,009 290,857
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Operating Expenses
Fuel and purchased power 51,654 59,165
Other operating 63,017 60,930
Maintenance 17,749 20,504
Depreciation and amortization 53,262 55,062
Taxes other than income taxes 20,244 21,706
Income taxes 22,041 17,950
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Total Operating Expenses 227,967 235,317
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OPERATING INCOME 55,042 55,540
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Other Income and (Deductions)
Interest and dividend income 3,938 1,722
Income taxes (350) 911
Other - net 2,320 1,529
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Total Other Income 5,908 4,162
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INCOME BEFORE INTEREST AND
OTHER CHARGES 60,950 59,702
INTEREST CHARGES 21,394 22,953
MONTHLY INCOME PREFERRED
SECURITIES DIVIDEND
REQUIREMENTS 3,141 -
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NET INCOME 36,415 36,749
DIVIDENDS ON PREFERRED AND
PREFERENCE STOCK 1,009 1,018
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EARNINGS FOR COMMON STOCK $ 35,406 $ 35,731
========= =========
</TABLE>
See notes to condensed consolidated financial statements.
2
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DUQUESNE LIGHT COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1997 1996
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ASSETS
<S> <C> <C>
Property, plant and equipment $ 4,619,136 $ 4,608,773
Less: Accumulated depreciation and amortization (1,938,883) (1,891,300)
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Property, plant and equipment - net 2,680,253 2,717,473
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Long-term investments:
Investment in DQE Common Stock 54,324 59,319
Other investments 104,172 102,948
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Total long-term investments 158,496 162,267
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Current assets:
Cash and temporary cash investments 221,844 154,414
Receivables 103,911 105,645
Other current assets, principally material and supplies 78,295 80,594
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Total current assets 404,050 340,653
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Other non-current assets:
Regulatory assets 625,226 636,816
Other 41,711 39,877
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Total other non-current assets 666,937 676,693
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TOTAL ASSETS $ 3,909,736 $ 3,897,086
============ ==============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock - $1 par value (shares - 90,000,000 $ - $ -
authorized; 10 issued)
Capital surplus 822,423 825,540
Retained earnings 160,859 163,884
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Total common stockholder's equity 983,282 989,424
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Non-redeemable preferred stock 63,608 63,608
Non-redeemable Monthly Income Preferred Securities 150,000 150,000
Non-redeemable preference stock 28,997 28,997
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Total preferred and preference stock before deferred employee stock
ownership plan (ESOP) benefit (involuntary liquidation values of
$242,467 exceed par by $28,180 for each period presented) 242,605 242,605
Deferred ESOP benefit (18,931) (19,533)
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Total preferred and preference stock 223,674 223,072
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Long-term debt 1,234,921 1,271,961
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Total capitalization 2,441,877 2,484,457
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Obligations under capital leases 24,150 28,407
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Current liabilities:
Current maturities and sinking fund requirements 105,229 70,912
Accounts payable 57,405 84,272
Accrued liabilities 72,859 59,020
Dividends declared 41,434 2,371
Other 2,852 4,613
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Total current liabilities 279,779 221,188
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Deferred income taxes - net 726,303 726,517
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Deferred investment tax credits 104,096 106,201
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Deferred income 134,236 139,075
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Other 199,295 191,241
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Commitments and contingencies (Note 4)
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TOTAL CAPITALIZATION AND LIABILITIES $ 3,909,736 $ 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>
Three Months Ended
March 31,
---------
1997 1996
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<S> <C> <C>
Cash Flows From Operating Activities
Operations $ 87,078 $ 86,041
Changes in working capital other than cash 28,307 2,613
Other 17,611 8,415
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Net Cash Provided By Operating Activities 132,996 97,069
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Cash Flows From Investing Activities
Construction expenditures (14,309) (14,916)
Long-term investments - net (4,230) (563)
Other 2,251 (979)
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Net Cash Used In Investing Activities (16,288) (16,458)
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Cash Flows From Financing Activities
Dividends on capital stock (40,247) (37,018)
Reductions of long-term obligations (7,540) (4,495)
Other (1,491) (1,588)
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Net Cash Used In Financing Activities (49,278) (43,101)
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Net increase in cash and temporary cash investments 67,430 37,510
Cash and temporary cash investments at beginning of period 154,414 2,490
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Cash and temporary cash investments at end of period $221,844 $40,000
========= ========
</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 April 7, 1997, DQE and Allegheny Power System, Inc. (APS), announced a
proposed tax-free, stock-for-stock merger. Upon consummation of the merger, DQE
will be a wholly owned subsidiary of APS, and the combined company's name will
be Allegheny Energy, Inc. Following the merger, Duquesne will remain a wholly
owned subsidiary of DQE. The transaction is expected to close within 12 to 18
months, subject to approval of the shareholders of both companies and applicable
regulatory agencies. (See "Subsequent Event," Note 5, on page 13.)
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. The results of operations for the three months ended March
31, 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). Duquesne's consolidated financial statements report
regulatory assets and liabilities in accordance with Statement of Financial
5
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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 other investments are primarily in assets of nuclear
decommissioning trusts and marketable securities. 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 March 31, 1997, and December 31, 1996, were $16.5 million and
$19.0 million ($9.7 million and $11.1 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 PUC-approved Mitigation
Plan, the level of energy cost recovery is capped at 1.47 cents per kilowatt-
hour (KWH) through May 2001. To the extent that projections do not support
recovery of previously deferred costs through this pricing mechanism, these
costs would become transition costs subject to recovery through a competitive
transition charge (CTC). (See "Customer Choice Act" and "Mitigation Plan"
discussions, Note 3, on page 7.)
2. RECEIVABLES
Components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
March 31, March 31, December 31,
1997 1996 1996
<S> <C> <C> <C>
(Amounts in Thousands of Dollars)
- ----------------------------------------------------------------------------------------------
Electric customer accounts receivable $ 97,655 $103,263 $ 92,475
Other utility receivables 16,534 16,258 22,402
Other receivables 9,288 15,573 9,062
Less: Allowance for uncollectible accounts (19,566) (19,689) (18,294)
- ----------------------------------------------------------------------------------------------
Total Receivables $103,911 $115,405 $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
$50.0 million of accounts receivable. At March 31, 1997, and December 31, 1996,
Duquesne had not sold any receivables to the unaffiliated corporation. The
accounts receivable sales agreement, which expires in June 1997, is one of many
sources of funds available to Duquesne. Duquesne has not determined, but may
attempt to extend the agreement or to replace the facility with a similar
arrangement or to eliminate it upon expiration.
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. 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 this pricing
structure and timeframe, the costs will be written off.
Mitigation Plan
Duquesne has taken a number of steps to mitigate its potential transition
costs. In addition to the steps taken during the last 10 years to prepare for
competition, effective January 1, 1995, Duquesne accelerated its rate of
depreciation on its fixed nuclear assets without seeking a rate increase to
recover the additional costs. On October 31, 1996, Duquesne sold its 50 percent
ownership interest in the Ft. Martin Power Station (Ft. Martin). Under the PUC-
approved plan, Duquesne will not increase its base rates for a period of five
years through May 2001. In addition, Duquesne recorded in October 1996 a one-
time reduction of approximately $130 million in the book value of Duquesne's
nuclear plant investment. The proceeds from the sale are expected to be used to
fund reliability enhancements to the Brunot Island (BI) Unit 3 combustion
turbine and to reduce Duquesne's capitalization. The approved plan also provides
for incremental increases of $25 million in depreciation and amortization
expense in 1997 and 1998 related to Duquesne's nuclear investment, as well as
additional annual contributions to its nuclear plant decommissioning funds of $5
million, without any increase in existing electric rates. Also, Duquesne will
record an annual $5 million credit to the ECR during the plan period to
compensate Duquesne's customers for lost profits from any short-term power sales
foregone by the sale of its ownership interest in Ft. Martin. In addition,
Duquesne will cap energy costs, beginning April 1, 1997 through the remainder of
the plan period, at a historical five-year average of 1.47 cents per kilowatt
hour (KWH). Duquesne's approved plan provides for the amortization of the
remaining deferred rate synchronization costs over a 10-year period. At March
31, 1997, the unamortized portion of these costs totaled $40.4 million, net of
deferred fuel savings related to the two units. Finally, Duquesne's approved
plan also provides for annual assistance of $0.5 million to low-income
customers.
7
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Regulatory Assets
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 on page 7.) Duquesne
currently believes its electricity generating assets and related regulatory
assets continue to satisfy these criteria in light of the transition to
competitive generation under the Customer Choice Act. Should any portion of
Duquesne's electric utility operations be deemed to no longer meet the SFAS No.
71 criteria, Duquesne may 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.
The components of regulatory assets for the periods presented are as
follows:
<TABLE>
<CAPTION>
March 31, December 31,
1997 1996
(Amounts in Thousands of Dollars)
- ------------------------------------------------------------------------------
<S> <C> <C>
Regulatory tax receivable $383,971 $394,131
Unamortized debt costs (a) 91,943 93,299
Deferred rate synchronization costs 40,392 41,446
Beaver Valley Unit 2 sale/leaseback premium (b) 29,682 30,059
Deferred employee costs (c) 27,964 29,589
Deferred nuclear maintenance outage costs 9,228 13,462
Deferred coal costs (see below) 12,894 12,191
DOE decontamination and decommissioning receivable 9,547 9,779
Other 19,605 12,860
- ------------------------------------------------------------------------------
Total Regulatory Assets $625,226 $636,816
==============================================================================
</TABLE>
(a) 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.
(b) The premium paid to refinance the Beaver Valley Unit 2 lease was deferred
for amortization over the life of the lease.
(c) Includes amounts for recovery of accrued compensated absences and accrued
claims for workers' compensation.
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.
8
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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 $10.3 million and $9.6 million, and the
unrecovered cost of the remainder of the system-wide coal was $2.6 million at
March 31, 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 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. Duquesne expects to recover its investment in BI Units 3 and 4, which
remain in property held for future use through future electricity sales.
Duquesne believes its investment in BI will be necessary in order to meet future
business needs. A portion of the proceeds of the sale of Ft. Martin is expected
to be used to fund reliability enhancements to the BI Unit 3 combustion turbine.
The reliability enhancements are contingent upon the projects meeting a least-
cost test versus other potential sources of peaking capacity. (See "Mitigation
Plan" discussion on page 7.) Duquesne is analyzing the effects of customer
choice on its future generating requirements. Duquesne is planning to seek
recovery of its investment and associated costs of Phillips through a CTC. 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 March 31, 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 Unit 3 combustion turbine.
(See "Mitigation Plan" discussion, Note 3, on page 7).
Nuclear-Related Matters
Duquesne has an ownership 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. The PUC ruled that recovery of the
decommissioning costs for Beaver Valley Unit 1 (BV Unit 1) could begin in 1977,
and that recovery 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.
9
<PAGE>
Based on site-specific studies finalized in 1992 for BV Unit 2, and in 1994
for BV Unit 1 and Perry Unit 1, Duquesne's share of the total estimated
decommissioning costs, including removal and decontamination costs, currently
being used to determine Duquesne's cost of service, is $122 million for BV Unit
1, $35 million for BV Unit 2, and $67 million for Perry Unit 1. A study will be
performed in 1997 to update Duquesne's estimated decommissioning costs of BV
Unit 1 and BV Unit 2.
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
a site-specific study to estimate the cost of decommissioning. Guidelines
require that 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. Consistent
with this requirement, Duquesne has increased its nuclear decommissioning
funding by $5 million under the PUC-approved plan for the sale of Duquesne's
ownership interest in Ft. Martin. (See "Mitigation Plan" discussion, Note 3, on
page 7.) These additional annual contributions bring the total annual funding to
approximately $9 million. Also, on October 17, 1996, the PUC adopted an
Accounting Order filed by Duquesne to recognize the increased funding as part of
Duquesne's cost of service. Duquesne has received approval from the Internal
Revenue Service for qualification of 100 percent of additional nuclear
decommissioning trust funding for BV Unit 2 and Perry Unit 1, and 69 percent for
BV Unit 1.
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 March 31, 1997 totaled approximately $36.4 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.
10
<PAGE>
In addition, Duquesne participates in a NEIL program that provides
insurance for the increased cost of generation and/or purchased power resulting
from an accidental outage of a nuclear unit. Subject to the policy limit, the
coverage provides for 100 percent of the estimated incremental costs per week
during the 52-week period starting 21 weeks after an accident and 80 percent of
such estimate per week for the following 104 weeks, 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 $3.5 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, which are anticipated to begin in
September 1997 for BV Unit 1 and in March 1998 for BV Unit 2. Duquesne will
continue to monitor and evaluate the condition of the BVPS steam generators.
Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982
established a 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 and 46
states, state agencies and regulatory commissions in filing a suit in the U.S.
Court of Appeals for the District of Columbia against the DOE. The suit requests
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. 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 March 31, 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.
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. In 1996, the Financial Accounting
Standard Board issued an exposure draft, Accounting for Certain Liabilities
Related to Closure or Removal of Long-Lived Assets. The primary effect of this
exposure draft would be to change the way Duquesne accounts for nuclear and
fossil decommissioning costs. The exposure draft calls for recording the present
value of estimated future cash flows to decommission Duquesne's nuclear and
fossil power plants as an increase to asset balances and as a liability. This
amount is currently estimated to be $299.5 million. Duquesne will seek to
recover these costs through a CTC.
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 March 31, 1997, Duquesne's share of these guarantees was $16.0
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 $16.0 million at March 31, 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, 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 $15 million. This estimate is subject to the
results of groundwater assessments and DEP final approval of compliance plans.
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Effective January 1, 1997, Duquesne adopted the provisions of Statement of
Position 96-1, Environmental Remediation Liabilities (SOP 96-1), which provides
authoritative guidance for recognition, measurement, display and disclosure of
environmental remediation liabilities in financial statements. Duquesne has
recorded a regulatory asset and liability of $6.8 million at March 31, 1997.
Adoption of SOP 96-1 is not expected to have a materially adverse effect on
Duquesne's financial position, results of operations or cash flows.
Employees
In November 1996, Duquesne reached an agreement on a three-year contract
extension through September 30, 2001, with the International Brotherhood of
Electrical Workers, which represents approximately 2,000 of Duquesne's
employees.
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. SUBSEQUENT EVENT
On April 7, 1997, DQE and APS, announced a proposed tax-free, stock-for-
stock merger. Upon consummation of the merger, DQE will be a wholly owned
subsidiary of APS, and the combined company's name will be Allegheny Energy,
Inc. 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 APS common stock for each share of DQE's common stock, and APS's dividend in
effect at the time of the closing of the merger. The transaction is expected to
close within 12 to 18 months, subject to approval of the shareholders of both
companies and applicable regulatory agencies, including the public utility
commissions in Pennsylvania and Maryland, the SEC, the FERC and the Nuclear
Regulatory Commission. Further details about the proposed merger are provided in
DQE's report on Form 8-K, filed with the SEC on April 10, 1997. 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 APS.
___________________________
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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 13 in Part I, Item 1 of this Report.
General
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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 April 7, 1997, DQE and Allegheny Power System, Inc. (APS), announced a
proposed tax-free, stock-for-stock merger. Upon consummation of the merger, DQE
will be a wholly owned subsidiary of APS, and the combined company's name will
be changed to Allegheny Energy, Inc. Following the merger, Duquesne will remain
a wholly owned subsidiary of DQE. The transaction is expected to close within
12 to 18 months, subject to approval of the shareholders of both companies and
applicable regulatory agencies. (See "Proposed Merger" discussion on page 18.)
Service Territory
Duquesne provides electric service to customers in Allegheny County,
including the City of Pittsburgh, Beaver County and Westmoreland County. 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. (See "Competition" discussion
on page 18.)
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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 18.) Duquesne believes its
electricity generating assets and related regulatory assets continue to satisfy
these criteria in light of the transition to competitive generation under the
Customer Choice Act. Should any portion of Duquesne's operations be deemed to no
longer meet the SFAS No. 71 criteria, Duquesne may 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.
Effective January 1, 1997, Duquesne adopted the provisions of Statement of
Position 96-1, Environmental Remediation Liabilities (SOP 96-1), which provides
authoritative guidance for recognition, measurement, display and disclosure of
environmental remediation liabilities in financial statements. Duquesne has
recorded a regulatory asset and liability of $6.8 million at March 31, 1997.
Adoption of SOP 96-1 is not expected to have a materially adverse effect on
Duquesne's financial position, results of operations or cash flows.
Results of Operations
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Sales of Electricity to Customers
The decrease in the first quarter of 1997 for total operating revenues was
$7.8 million, as compared to the first quarter of 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 expenses and investment in electric utility assets and to
provide a return on the investment. (See "Regulation" and "Competition"
discussions on pages 14 and 18.)
Sales to residential and commercial customers are strongly 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 economic development. Sales to industrial customers are
influenced by national and global economic conditions. Customer revenues
fluctuate as a result of changes in sales volume and changes in fuel and other
energy costs.
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Net Customer Revenues
Net customer revenues, reflected on the statement of consolidated income,
decreased $1.2 million or 0.5 percent in the first quarter of 1997, as compared
to the same period in 1996. The variance can be attributed primarily to
decreased residential customer kilowatt-hour (KWH) sales of 2.4 percent due to
mild 1997 winter temperatures, as compared to 1996, resulting in decreased
revenues of $1.0 million. Higher sales to several of Duquesne's largest
industrial customers resulted in a 1.7 percent increase in industrial sales.
Each of these customers reported an increase in orders as the reason for the
increase in electric demand.
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 first quarter of 1997 were $7.2
million less than the first quarter of 1996 due to a decline in demand from
other utilities and reduced availability as a result of the sale of Duquesne's
50 percent interest in the Ft. Martin Power Station (Ft. Martin). Future levels
of short-term sales to other utilities will be affected by the possible sale of
other generating stations, market rates, and by the outcome of Duquesne's FERC
filings requesting firm transmission access. (See "Outlook" discussion on page
18.)
Other Operating Revenues
Other operating revenues include Duquesne's non-KWH utility revenues in
Duquesne's statement of consolidated income. Other operating revenues are
primarily comprised of revenues from joint owners of Beaver Valley Unit 1 (BV
Unit 1) and Beaver Valley Unit 2 (BV Unit 2) for their shares of the
administrative and general costs of operating these units. Other operating
revenues therefore fluctuate depending on the timing of scheduled refueling and
maintenance outages at the Beaver Valley Power Station (BVPS) when significant
costs are incurred.
Operating Expenses
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 Energy Cost Rate
Adjustment Clause (ECR), changes in fuel and purchased power costs did not
impact earnings in the first quarter of 1997 and 1996.
Fuel and purchased power expense decreased $7.5 million in the first quarter
of 1997, as compared to the first quarter of 1996, as a result of decreases in
purchased power and fossil fuel volume. These decreases were partially offset
by increased fuel prices and purchased power prices.
Other operating expense increased $2.1 million when comparing the first
quarter of 1997 and 1996. The increase was primarily the result of increased
costs due to forced outages at both BV Unit 1 and BV Unit 2 during the first
quarter of 1997.
During the first quarter of 1997 maintenance expense decreased $2.8 million,
as compared to the first quarter of 1996, due to costs savings attributable
Duquesne's electric utility operations and the sale of Ft. Martin.
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Income taxes increased by $4.1 million in the first quarter of 1997, as
compared to the first quarter of 1996, primarily due to increased taxable
income.
Other Income
Comparing the first quarter of 1997 and the first quarter of 1996, an increase
of $1.7 million in other income was the result of additional interest and
dividend income recognized from a higher level of short-term investments.
Interest Charges
Duquesne achieved reductions of $1.6 million in interest charges in the first
quarter of 1997, as compared to the first quarter of 1996. The decrease is
primarily the result of $50.0 million in debt that matured in May 1996.
Interest expense in 1997 will be influenced by fluctuations in short-term rates
and any new financing.
Monthly Income Preferred Securities Dividend Requirements
The Monthly Income Preferred Securities Dividend Requirements reflect the
payment of $3.1 million in dividends in the first quarter of 1997 related to
preferred securities issued in 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 March 31, 1997, Duquesne was in compliance with all of its debt
covenants.
$50 million and $35 million of mortgage bonds will mature in November 1997
and February 1998, respectively. Duquesne expects to retire these bonds with
available cash or to refinance the bonds.
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 $4.2
million and $2.4 million in various investments in the first quarter of 1997 and
1996. In the first quarter of 1996, Duquesne also sold investments for $1.8
million.
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Outlook
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Proposed Merger
On April 7, 1997, DQE and APS announced a proposed tax-free, stock-for-stock
merger. Upon consummation of the merger, DQE will be a wholly owned subsidiary
of APS, and the combined company's name will be changed to Allegheny Energy,
Inc. 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 APS common stock for each share of DQE's common stock, and APS's dividend in
effect at the time of the closing of the merger. The transaction is expected to
close within 12 to 18 months, subject to approval of the shareholders of both
companies and applicable regulatory agencies, including the public utility
commissions in Pennsylvania and Maryland, the SEC, the FERC and the NRC. Further
details about the proposed merger are provided in DQE's report on Form 8-K,
filed with the SEC on April 10, 1997. 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 APS.
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 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 proposes unbundling transmission, distribution, electricity and
competitive transition charges and offers participating customers the same
options that will be available in a competitive generation market. The pilot
program is designed to comprise approximately 5 percent of Duquesne's
residential, commercial and industrial demand. Customers participating in the
pilot will have two basic options. First, customers can choose to continue
taking bundled service from Duquesne under approved tariffs. Second, customers
can choose unbundled service with their electricity provided by an alternative
electric generation supplier. All customers that choose unbundled electric
service will be subject to unbundled distribution charges approved by the PUC
and unbundled transmission charges pursuant to Duquesne's FERC-approved tariff.
Each customer that elects unbundled service
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also will be required to pay a non-bypassable access fee (competitive transition
charge or CTC) that provides Duquesne with a reasonable opportunity to recover
transition costs. On May 9, 1997, the PUC issued a Preliminary Opinion and
Order approving Duquesne's filing in part, and requiring certain revisions.
Duquesne has until May 22, 1997, to submit comments on the PUC's preliminary
order. The PUC anticipates issuing a final order in July 1997, and a revised
pilot program must be filed within 30 days of such order. The PUC further
anticipates the revised pilot program could begin in October 1997.
Duquesne must file a restructuring plan with the PUC by August 1, 1997,
setting forth its proposals for the transition to customer choice and the
recovery of transition costs. 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. 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 this pricing structure and timeframe, the costs will be written
off.
Duquesne has already been effective in mitigating its exposure to
transition costs. Generating plant, decommissioning and related regulatory asset
costs have been reduced by approximately $400 million during the past two years.
These reductions have resulted from a variety of strategies, such as selling
generating assets, accelerating recovery of fixed costs, increasing nuclear
decommissioning charges and reducing capitalized costs. Effective January 1,
1995, Duquesne accelerated its rate of depreciation on its fixed nuclear assets
without seeking a rate increase to recover the additional costs. On October 31,
1996, Duquesne sold its ownership interest in Ft. Martin. Under the PUC-approved
plan, Duquesne will not increase its base rates for a period of five years
through May 2001. In addition, Duquesne recorded in October 1996 a one-time
reduction of approximately $130 million in the book value of Duquesne's nuclear
plant investment. The proceeds from the sale are expected to be used to fund
reliability enhancements to the BI Unit 3 combustion turbine and to reduce
Duquesne's capitalization. The approved plan also provides for incremental
increases of $25 million in depreciation and amortization expense in 1997 and
1998 related to Duquesne's nuclear investment, as well as additional annual
contributions to its nuclear plant decommissioning funds of $5 million, without
any increase in existing electric rates. Also, Duquesne will record an annual $5
million credit to the ECR during the plan period to compensate Duquesne's
customers for lost profits from any short-term power sales foregone by the sale
of its ownership interest in Ft. Martin. In addition, Duquesne has capped energy
costs through the remainder of the plan period at a historical five-year average
of 1.47 cents per KWH. Duquesne's approved plan provides for the amortization
of the remaining deferred rate synchronization costs over a 10-year period. At
March 31, 1997, the unamortized portion of these costs totaled $40.4 million,
net of deferred fuel savings related to the two units. Finally, Duquesne's
approved plan also provides for annual assistance of $0.5 million to low-income
customers. Duquesne expects to continue these steps to address its remaining
transition costs. The Customer Choice Act provides another option to mitigate
transition costs. With PUC approval, utilities are permitted to issue
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transition bonds with a maturity of 10 years or less. Proceeds can be used to
reduce transition costs. Duquesne is currently reviewing this alternative as
well as others to further mitigate its transition costs.
As part of its transition filing, Duquesne is proposing to make a long-term
sale of electricity during the transition period to determine the market rate
for power. In addition to market-related impacts, any estimate of the ultimate
level of transition costs also 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 anticipates making its transition filing,
including the identification of potential transition costs, as required by the
PUC on August 1, 1997. The PUC is expected to rule on Duquesne's ability to
recover these costs through a CTC by May 1, 1998. 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 that 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 costs will be written off. As Duquesne has
substantial exposure to transition costs relative to its size, significant
transition cost write-offs could have a materially adverse effect on Duquesne's
financial position, results of 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 mitigation of transition costs, Duquesne has been
preparing for competition in a variety of ways. Duquesne has been building its
financial strength through the retirement and refinancing of long-term debt. In
1995, Duquesne's restrictive first mortgage bond indenture was replaced with a
new indenture with more flexible provisions. In 1996, Duquesne issued MIPS to
further add to its financial flexibility and creditworthiness.
Duquesne has also better positioned its business for competition through
improving operations and enhancing customer relations. In recognition of
impending industry competition and in an effort to optimize its generation
resources, in 1989 Duquesne signed a contract with Delmarva Power for a bulk
power sale for a period of 20 years. This initiative would have resulted in the
refurbishment and return to service of Duquesne's cold-reserved generating
stations. Following the plan's failure to receive regulatory approval, in 1990
Duquesne announced a second long-term power sale initiative to restart these
power plants. This plan would have provided significant impetus to economic
development in Pennsylvania as well as providing Duquesne's customers with
substantial benefits in the form of lower rates. Duquesne's efforts to upgrade
and maintain the cold-reserved units have enabled Duquesne to utilize the BI
units to meet peak demand during periods of extreme weather in recent years and
have enabled the BI units to more quickly return to service as part of the Ft.
Martin sale. In 1991, Duquesne reorganized into strategic business units along
market lines and instituted cost reduction targets for capital, operation and
maintenance, and inventory expenditures. Workforce reductions were achieved
primarily through attrition. Since 1989 Duquesne has reduced its number of
employees by 25 percent. Recently, Duquesne signed a three-year contract
extension with its bargaining unit employees through September 2001. Throughout
the period, Duquesne has been aggressively reducing its fuel costs, achieving a
13 percent reduction in the unit cost of fuel since 1990. These measures have
enabled Duquesne to reduce its rates by nearly 36 percent, in real terms, since
1990. When considering the price freeze component of Duquesne's Mitigation Plan,
prices will have declined by nearly 50 percent in real terms during the decade
of the 1990s. From a customer relations standpoint, Duquesne negotiated long-
term contracts with more than 30 key industrial and commercial customers and was
recognized in 1996 for its economic development efforts in attracting major new
industrial expansions. In 1995, Duquesne became one of the first electric
utilities in the country to offer a full customer service guarantee and also
guaranteed to match any competing electricity supplier's price for new
businesses or for the expansion of existing businesses. Duquesne also is
offering to customers
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increased bill-paying options, including an advanced technology service that
enables customers to electronically receive and pay their electric bills. This
service assists major customers just as its earlier Electricheck option helped
smaller commercial and residential customers. Additionally, Duquesne will be
positioned to offer customers a wide range of new services with the Customer
Advanced Reliability System (CARS). Utility customers will be linked to CARS by
encoder receiver transmitters contained in new or retrofitted electric meters.
Data communications offered by this technology are expected to result in
improved reliability, security, and customer satisfaction.
The proposed merger of DQE and APS, the complementary nature of the two
companies' peak usage times and customer bases, and the elimination of duplicate
activities should create a more efficient and cost-effective combined entity.
In addition, the larger, combined company should be able to take advantage of
economies of scale, and will have a wide range of products and services to offer
to a larger market.
In March 1997, a suit was filed in Pennsylvania's Commonwealth Court
seeking to overturn the Customer Choice Act, contending that the process by
which the state legislature considered and approved the act violated the
Pennsylvania state constitution. While there can be no assurance as to the
ultimate outcome of this suit, similar challenges to other legislation in
Pennsylvania have been unsuccessful.
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
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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.
______________________________
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.
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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.
Currently, the parties are engaged in settlement discussions.
Item 6. Exhibits and Reports on Form 8-K.
a. Exhibits:
EXHIBIT 2.1 - Agreement and Plan of Merger dated as of April 5, 1997,
among DQE, APS and AYP Sub, Inc. (included as Exhibit 2(a) to DQE's
Current Report on Form 8-K filed with the SEC on April 10, 1997 (the
"DQE Form 8-K") and incorporated herein by reference).
EXHIBIT 2.2 - Stock Option Agreement dated as of April 5, 1997, between
DQE and APS (filed as Exhibit 2(b) to the DQE Form 8-K and incorporated
herein by reference).
EXHIBIT 2.3 - Letter Agreement dated as of April 5, 1997, between DQE
and APS (filed as Exhibit 2(c) to the DQE Form 8-K and incorporated
herein by reference).
EXHIBIT 10.1 - Severance Agreement dated April 4, 1997, between DQE and
David D. Marshall, together with a schedule describing substantially
identical agreements with Gary L. Schwass, Victor A. Roque, James E.
Cross and James D. Mitchell (filed as Exhibit 10.1 to DQE's Form 10-Q
Quarterly Report for the quarter ended March 31, 1997, and incorporated
herein by reference).
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
March 31, 1997.
______________________________
23
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
DUQUESNE LIGHT COMPANY
----------------------
(Registrant)
Date May 14, 1997 /s/ Gary L. Schwass
------------ -----------------------
(Signature)
Gary L. Schwass
Senior Vice President and
Chief Financial Officer
Date May 14, 1997 /s/ Morgan K. O'Brien
------------ -------------------------
(Signature)
Morgan K. O'Brien
Controller and
Principal Accounting Officer
24
<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,
Three Months Ended -----------------------
March 31, 1997 1996 1995 1994 1993 1992
------------------ -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $20,311 $ 82,505 $ 89,139 $ 94,646 $102,938 $119,179
Other interest 244 1,632 2,599 1,095 2,387 1,749
Monthly Income Preferred Securities
dividend requirements 3,141 7,921 ----- ----- ----- -----
Amortization of debt discount,
premium and expense - net 1,471 5,973 6,252 6,381 5,541 4,223
Portion of lease payments
representing an interest factor 11,208 44,357 44,386 44,839 45,925 60,721
------- -------- -------- -------- -------- --------
Total Fixed Charges $36,375 $142,388 $142,376 $146,961 $156,791 $185,872
------- -------- -------- -------- -------- --------
EARNINGS:
Income from continuing operations $36,415 $149,860 $151,070 $147,449 $144,787 $149,768
Income taxes 22,391* 83,008* 92,894* 84,191* 77,237* 110,993
Fixed charges as above 36,375 142,388 142,376 146,961 156,791 185,872
------- -------- -------- -------- -------- --------
Total Earnings $95,181 $375,256 $386,340 $378,601 $378,815 $446,633
------- -------- -------- -------- -------- --------
RATIO OF EARNINGS TO FIXED CHARGES 2.62 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 $0.7 million for the three months
ended March 31, 1997, has been excluded from the ratio.
*Earnings related to income taxes reflect a $3.0 million decrease for the three
months ended March 31, 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 2.70 for the three months ended March 31, 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> 3-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> MAR-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,680,253
<OTHER-PROPERTY-AND-INVEST> 158,496
<TOTAL-CURRENT-ASSETS> 404,050
<TOTAL-DEFERRED-CHARGES> 666,937
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,909,736
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 822,423
<RETAINED-EARNINGS> 160,859
<TOTAL-COMMON-STOCKHOLDERS-EQ> 983,282
3,000
220,674<F1>
<LONG-TERM-DEBT-NET> 1,234,921
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 85,000
0
<CAPITAL-LEASE-OBLIGATIONS> 24,150
<LEASES-CURRENT> 20,229
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,338,480
<TOT-CAPITALIZATION-AND-LIAB> 3,909,736
<GROSS-OPERATING-REVENUE> 283,009
<INCOME-TAX-EXPENSE> 22,041
<OTHER-OPERATING-EXPENSES> 205,926
<TOTAL-OPERATING-EXPENSES> 227,967
<OPERATING-INCOME-LOSS> 55,042
<OTHER-INCOME-NET> 5,908
<INCOME-BEFORE-INTEREST-EXPEN> 60,950
<TOTAL-INTEREST-EXPENSE> 24,535<F2>
<NET-INCOME> 36,415
1,009
<EARNINGS-AVAILABLE-FOR-COMM> 35,406
<COMMON-STOCK-DIVIDENDS> 40,247
<TOTAL-INTEREST-ON-BONDS> 21,782
<CASH-FLOW-OPERATIONS> 132,996
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0.00
<FN>
<F1>Includes $10,066 of Preference Stock
<F2>Includes $3,141 of Monthly Income Preferred Securities Dividend Requirements
</FN>
</TABLE>
