<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 June 30, 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 June 30, 1997 and July 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 Six Months Ended
June 30, June 30,
------- -------
1997 1996 1997 1996
------------- ------------- ------------- ------------
<S> <C> <C> <C> <C>
Operating Revenues
Sales of Electricity:
Customers - net $251,786 $260,186 $517,135 $526,769
Utilities 6,289 15,077 15,020 31,042
-------------- -------------- -------------- --------------
Total Sales of Electricity 258,075 275,263 532,155 557,811
Other 14,201 9,259 23,130 17,568
-------------- -------------- -------------- --------------
Total Operating Revenues 272,276 284,522 555,285 575,379
-------------- -------------- -------------- --------------
Operating Expenses
Fuel and purchased power 50,516 58,695 102,170 117,860
Other operating 64,425 63,791 127,442 124,721
Maintenance 22,551 18,864 40,300 39,368
Depreciation and amortization 57,836 54,388 111,098 109,958
Taxes other than income taxes 19,521 20,552 39,765 42,258
Income taxes 12,136 17,810 34,177 35,949
-------------- -------------- -------------- --------------
Total Operating Expenses 226,985 234,100 454,952 470,114
-------------- -------------- -------------- --------------
OPERATING INCOME 45,291 50,422 100,333 105,265
-------------- -------------- -------------- --------------
Other Income and (Deductions)
Interest and dividend income 3,714 2,427 7,652 4,149
Income taxes (795) 1,263 (1,145) 2,363
Other - net 3,605 2,292 5,925 4,329
-------------- -------------- -------------- --------------
Total Other Income 6,524 5,982 12,432 10,841
-------------- -------------- -------------- --------------
INCOME BEFORE INTEREST AND
OTHER CHARGES 51,815 56,404 112,765 116,106
INTEREST CHARGES 21,455 22,193 42,849 45,146
MONTHLY INCOME PREFERRED
SECURITIES DIVIDEND
REQUIREMENTS 3,204 1,640 6,345 1,640
-------------- -------------- -------------- --------------
NET INCOME 27,156 32,571 63,571 69,320
DIVIDENDS ON PREFERRED AND
PREFERENCE STOCK 1,005 1,014 2,014 2,032
-------------- -------------- -------------- --------------
EARNINGS FOR COMMON STOCK $ 26,151 $ 31,557 $ 61,557 $ 67,288
============== ============== ============== ==============
</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>
June 30, December 31,
1997 1996
---- ----
<S> <C> <C>
ASSETS
Property, plant and equipment $ 4,647,271 $ 4,608,773
Less: Accumulated depreciation and amortization (1,991,408) (1,891,300)
----------------- ----------------
Property, plant and equipment - net 2,655,863 2,717,473
----------------- ----------------
Long-term investments:
Investment in DQE Common Stock 54,158 59,319
Other investments 104,501 102,948
----------------- ----------------
Total long-term investments 158,659 162,267
----------------- ----------------
Current assets:
Cash and temporary cash investments 191,851 154,414
Receivables 95,896 105,645
Other current assets, principally material and supplies 99,829 80,594
----------------- ----------------
Total current assets 387,576 340,653
----------------- ----------------
Other non-current assets:
Regulatory assets 605,334 636,816
Other 43,585 39,877
----------------- ----------------
Total other non-current assets 648,919 676,693
----------------- ----------------
TOTAL ASSETS $ 3,851,017 $ 3,897,086
================= ================
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock - $1 par value (shares - 90,000,000
authorized; 10 issued) $ - $ -
Capital surplus 822,841 825,540
Retained earnings 165,067 163,884
----------------- ----------------
Total common stockholder's equity 987,908 989,424
----------------- ----------------
Non-redeemable preferred stock 63,608 63,608
Non-redeemable Monthly Income Preferred Securities 150,000 150,000
Non-redeemable preference stock 29,195 28,997
----------------- ----------------
Total preferred and preference stock before deferred employee stock
ownership plan (ESOP) benefit 242,803 242,605
Deferred ESOP benefit (18,565) (19,533)
----------------- ----------------
Total preferred and preference stock 224,238 223,072
----------------- ----------------
Long-term debt 1,199,983 1,271,961
----------------- ----------------
Total capitalization 2,412,129 2,484,457
----------------- ----------------
Obligations under capital leases 22,768 28,407
----------------- ----------------
Current liabilities:
Current maturities and sinking fund requirements 138,334 70,912
Accounts payable 62,210 84,272
Accrued liabilities 38,766 59,020
Dividends declared 24,495 2,371
Other 1,403 4,613
----------------- ----------------
Total current liabilities 265,208 221,188
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Deferred income taxes - net 709,917 726,517
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Deferred investment tax credits 101,991 106,201
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Deferred income 129,398 139,075
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Other 209,606 191,241
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Commitments and contingencies (Note 4)
----------------- ----------------
TOTAL CAPITALIZATION AND LIABILITIES $ 3,851,017 $ 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>
Six Months Ended
June 30,
--------
1997 1996
---------------- ----------------
<S> <C> <C>
Cash Flows From Operating Activities
Operations $191,838 $160,830
Changes in working capital other than cash (32,888) (37,972)
Other (6,260) 15,590
--------------- ---------------
Net Cash Provided By Operating Activities 152,690 138,448
--------------- ---------------
Cash Flows From Investing Activities
Construction expenditures (40,234) (32,256)
Long-term investments (6,826) (1,589)
Other 8,948 (1,728)
--------------- ---------------
Net Cash Used in Investing Activities (38,112) (35,573)
--------------- ---------------
Cash Flows From Financing Activities
Issuance of preferred stock - 150,000
Dividends on capital stock (63,490) (73,032)
Reductions of long-term obligations - net (12,849) (58,668)
Other (802) (7,390)
--------------- ---------------
Net Cash (Used in) Provided by Financing Activities (77,141) 10,910
--------------- ---------------
Net increase in cash and temporary cash investments 37,437 113,785
Cash and temporary cash investments at beginning of period 154,414 2,490
--------------- ---------------
Cash and temporary cash investments at end of period $191,851 $116,275
=============== ===============
</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 Power System, Inc.
(APS), approved a proposed tax-free, stock-for-stock merger. Upon consummation
of the merger, DQE will be a wholly owned subsidiary of Allegheny Energy, Inc.,
which will be the combined company's name. 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. The results of operations for the three and six months ended
June 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). 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.)
5
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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 June 30, 1997, and December 31, 1996, were $17.6 million and
$19.0 million ($10.3 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 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 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" discussion,
Note 3, on page 7.)
Statement of Financial Accounting Standards No. 130, Reporting
Comprehensive Income (SFAS No. 130) was issued in June 1997. SFAS No. 130
establishes standards for the reporting and display of comprehensive income and
its components (revenues, expenses, gains, and losses) in a full set of general-
purpose financial statements. SFAS No. 130 also requires that Duquesne (a)
classify items of other comprehensive income by their nature in a financial
statement and (b) display the accumulated balance of other comprehensive income
separately from retained earnings and additional paid-in-capital in the equity
section of a statement of financial position. SFAS No. 130 will be effective
for fiscal years beginning after December 15, 1997.
Statement of Financial Accounting Standards No. 131, Disclosures About
Segments of an Enterprise and Related Information (SFAS No. 131) was also
issued in June 1997. SFAS No. 131 establishes standards for public business
enterprises to report information about operating segments in annual financial
statements, and requires that those enterprises report selected information
about operating segments in interim financial reports issued to shareholders.
It also establishes standards for related disclosures about such enterprises'
products and services, geographic areas of operation and major customers. SFAS
No. 131 requires that Duquesne report a measure of segment profit or loss,
certain specific revenue and expense items, and segment assets. It also
requires that Duquesne report descriptive information about how the operating
segments were determined, the products and services provided by the operating
segments, differences between the measurements used in reporting segment
information and those used in its general-purpose financial statements, and
changes in the measurement of segment amounts from period to period. SFAS No.
131 will be effective for financial statements for periods beginning after
December 15, 1997.
2. RECEIVABLES
Components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
June 30, June 30, December 31,
1997 1996 1996
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 88,314 $105,199 $ 92,475
Other utility receivables 15,738 14,611 22,402
Other receivables 11,946 15,884 9,062
Less: Allowance for uncollectible accounts (20,102) (20,687) (18,294)
- --------------------------------------------------------------------------------------------------------------
Total Receivables $ 95,896 $115,007 $105,645
==============================================================================================================
</TABLE>
6
<PAGE>
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 June 30, 1997, 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.
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 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 standard costs will be written off. 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 (Restructuring
Plan).
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 (the
"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 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.
7
<PAGE>
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 material to the
financial position of Duquesne.
Duquesne's regulatory assets related to generation, transmission and
distribution as of June 30, 1997, were $468.3 million, $39.2 million and $97.8
million, respectively. The components of all regulatory assets for the periods
presented are as follows:
<TABLE>
<CAPTION>
June 30, December 31,
1997 1996
(Amounts in Thousands of Dollars)
- ------------------------------------------------------------------------------------
<S> <C> <C>
Regulatory tax receivable $370,420 $394,131
Unamortized debt costs (a) 90,586 93,299
Deferred rate synchronization costs 39,339 41,446
Beaver Valley Unit 2 sale/leaseback premium (b) 29,306 30,059
Deferred employee costs (c) 27,970 29,589
Deferred nuclear maintenance outage costs 4,988 13,462
Deferred coal costs (see below) 13,860 12,191
DOE decontamination and decommissioning receivable 9,315 9,779
Other 19,550 12,860
- ------------------------------------------------------------------------------------
Total Regulatory Assets $605,334 $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
<PAGE>
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 $11.3 million and $9.6 million at June 30, 1997
and December 31, 1996. The unrecovered cost of the remainder of the system-wide
coal was $2.6 million at June 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. 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. Reliability enhancements at BI are contingent upon the
projects meeting a least-cost test versus other potential sources of peaking
capacity. Duquesne is analyzing the effects of customer choice on its future
generating requirements. Duquesne is seeking 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 June 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.
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.
Based on site-specific studies finalized in 1997 for BV Unit 1, BV Unit 2
and 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.
9
<PAGE>
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.
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. The annual
contributions to the decommissioning funds 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 June 30, 1997, totaled approximately $40.3 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.
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 $3.5 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).
10
<PAGE>
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.
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 to 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. 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.
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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 June 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.
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. This amount for fossil decommissioning
is currently estimated to be $130 million for 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 its Restructuring Plan.
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 June 30, 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 $18.4 million at June 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, 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.
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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. The contract extension provides, among other things, for a three-
year 3% annual wage increase, employment security and income protection, and an
early retirement program for certain 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.
___________________________
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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 August 7, 1997, the shareholders of DQE and Allegheny Power System, Inc.
(APS), approved a proposed tax-free, stock-for-stock merger. Upon consummation
of the merger, DQE will be a wholly owned subsidiary of Allegheny Energy, Inc.
(Allegheny Energy), which will be the combined company's name. 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 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. 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 19.)
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
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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 19.) Members of the Emerging
Issues Task Force of the Financial Accounting Standards Board (the "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 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.
RESULTS OF OPERATIONS
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Sales of Electricity to Customers
The decrease in the second quarter of 1997 total operating revenues was
$12.2 million or 4.3 percent, as compared to the second quarter of 1996. Total
operating revenues decreased $20.1 million or 3.5 percent, when comparing the
six months ended June 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 14 and 19.)
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Sales to residential and commercial customers are strongly 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.
Net Customer Revenues
Net customer revenues, reflected on the statement of consolidated income,
decreased $8.4 million or 3.2 percent in the second quarter of 1997, as compared
to the same period in 1996. The variance can be attributed primarily to
decreased residential and commercial customer kilowatt-hour (KWH) sales of 6.2
percent and 3.9 percent, respectively, due to mild second quarter 1997
temperatures, as compared to 1996, resulting in decreased revenues of $5.1
million and $4.9 million, respectively. Due to the mild temperatures, fuel
volume was down from the second quarter of 1996 by 12.1 percent. Industrial
sales increased 10.4 percent as compared to the second quarter of 1996,
resulting in increased industrial revenues of $1.7 million, primarily due
to a major customer's expansion, outages experienced by that customer in the
second quarter of 1996, and significant electricity consumed by a new customer.
The remainder of the increase in electric demand is the result of improved
business for other industrial customers.
In the six months ended June 30, 1997, as compared to the six months ended
June 30, 1996, net customer revenues decreased $9.6 million or 1.8 percent.
Reduced residential customer KWH sales of 4.1 percent due to mild temperatures,
as compared to 1996, resulted in a $6.2 million decrease in residential customer
revenues. Due to the mild temperatures, fuel volume was down from the first six
months of 1996 by 10.3 percent. Industrial sales for the six months ended June
30, 1997, increased 5.9 percent, as compared to the six months ended June 30,
1996 resulting in a $2.1 million increase in industrial revenues. The increase
is the result of improved business for several of Duquesne's largest industrial
customers.
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 second quarter of 1997 were $8.8
million less than in the second quarter of 1996. In a comparison of the six
months ended June 30, 1997, to the six months ended June 30, 1996, sales to
other utilities decreased $16.0 million. The fluctuations were 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. The increases in the second quarter of 1997 as compared to
the second quarter of 1996 and in the six months ended
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June 30, 1997, as compared to the six months ended June 30, 1996 of $4.9 million
and $5.6 million are due in part to a pole attachment settlement in the second
quarter of 1997 for $2.8 million.
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 second quarter of 1997 and 1996 or in the six months
ended June 30, 1997 and 1996.
Fuel and purchased power expense decreased $8.2 million or 13.9 percent in the
second quarter of 1997, as compared to the second quarter of 1996, and decreased
$15.7 million or 13.3 percent for the six months ended June 30, 1997, as
compared to the same period in 1996. These decreases in purchased power and
fossil fuel volume were the result of reduced residential and commercial
consumption due to mild 1997 temperatures. These decreases were partially offset
by increased fuel prices and purchased power prices.
Maintenance expense increased $3.7 million or 19.5 percent when comparing the
second quarter of 1997 to the same period in 1996. During the second quarter of
1997 there were approximately 75 percent more generating station outage-days
than in the second quarter of 1996. In the first six months of 1997, as compared
to the same period in 1996, maintenance expense increased $0.9 million or 2.4
percent. There were approximately 12 percent more generating station outage-days
in the first six months of 1997 than in the same period in 1996.
In the second quarter of 1997, depreciation and amortization expense increased
$3.4 million or 6.3 percent as compared to the second quarter of 1996. There
was a $1.1 million or 1.0 percent increase in the six months ended June 30,
1997, when compared to the same period in 1996. The increases are the result of
increased nuclear fixed cost recovery in the second quarter of 1997, as well as
increased funding of the nuclear decommissioning trust, in accordance with the
PUC-approved Ft. Martin sale. The increase is partially offset due to the full
recovery of Perry Unit 2 abandonment costs during the third quarter of 1996.
Decreases in taxes other than income taxes of $1.0 million and $2.5 million
for the second quarter of 1997 and the first six months of 1997 as compared to
the same periods in 1996 is due to reduced taxes as a result of the sale of Ft.
Martin.
Income taxes decreased in the second quarter of 1997 and the first six months
of 1997 as compared to the same periods in 1996 by $5.7 million and $1.8
million. The decreases in income taxes can be attributed to decreased taxable
income.
Other Income
Comparing the second quarter of 1997 to the second quarter of 1996 and the six
months ended June 30, 1997, to the six months ended June 30, 1996, increases of
$0.5 million and $1.6 million in other income were primarily the result of
additional interest income recognized from a higher level of short-term
investments.
Interest Charges
There was a decrease of $0.7 million or 3.3 percent in interest charges during
the second quarter of 1997 as compared to the second quarter of 1996. In
comparing the six months ended June 30, 1997, with the six months ended June 30,
1996, there was a $2.3 million or 5.1 percent decrease
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in interest and other 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 of $3.2 million in the second quarter of 1997 and
$6.3 million in the six months ended June 30, 1997, as compared to $1.6 million
in the six months ended June 30, 1996 (the entire amount having been paid in the
second quarter of 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 June 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
$50.0 million of accounts receivable. During the second quarter, the $50.0
million accounts receivable sale arrangement was extended through June 1998.
Duquesne may attempt to extend the agreement, replace it with a similar
facility, or eliminate the agreement, upon expiration.
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 $6.8
million and $1.6 million in various investments in the six months ended June 30,
1997 and 1996, respectively.
Outlook
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Proposed Merger
On August 1, 1997, Duquesne, DQE and APS filed applications outlining their
restructuring and merger plans with the FERC, the PUC and the Maryland Public
Service Commission, asking for the necessary approvals to form Allegheny Energy.
Also on August 1, 1997, Duquesne filed an application with the NRC for approval
of the indirect transfer of licenses from Duquesne to Allegheny Energy.
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. Affiliated interest filings related to restructuring will be made
by APS with the Virginia State Corporation Commission and the Public Service
Commission of West Virginia. Duquesne cannot predict the outcome of any of
these filings.
On August 7, 1997, the shareholders of DQE and APS approved a proposed tax-
free, stock-for-stock merger. Upon consummation of the merger, DQE will be a
wholly owned subsidiary of
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Allegheny Energy. 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 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 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 APS, 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 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 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. Customers participating in the
pilot were to have two basic options. First, customers could choose to continue
taking bundled service from Duquesne under approved tariffs. Second, customers
could choose unbundled service with their electricity provided by an alternative
electric generation supplier. All customers choosing 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 electing unbundled service also were to 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 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. On May 22, 1997, Duquesne submitted comments on the
PUC's preliminary order. Duquesne and other utilities have objected to several
features of the PUC's preliminary order. The PUC anticipates issuing a final
order on August 28, 1997, and a revised pilot program must be filed within 30
days of such order. The revised pilot program is now expected to begin in
December 1997.
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
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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 plan (the Restructuring
Plan) with the PUC. Duquesne anticipates a decision by the PUC on or before
April 30, 1998. The Restructuring Plan uses 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 established a return on equity "spillover"
mechanism that will ensure that the related revenues are used to further
mitigate stranded costs. Finally, the Restructuring Plan redesigns rates to
encourage more efficient electricity
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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.
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
"Regulation" discussion on page 14.) 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.
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<PAGE>
In addition to the Restructuring Plan, on August 1, 1997, DQE and APS filed
their joint merger application with the FERC (the FERC Filing). Pursuant to the
FERC Filing, DQE and APS have committed to forming or joining an independent
system operator (ISO) which meets their requirements following the merger. In
addition, DQE and APS 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
BVPSOs 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.
22
<PAGE>
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.
23
<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. Since
April 1997, the parties have been engaged in settlement discussions.
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
June 30, 1997.
______________________________
24
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
DUQUESNE LIGHT COMPANY
----------------------
(Registrant)
Date August 13, 1997 /s/ Gary L. Schwass
----------------------- ---------------------------
(Signature)
Gary L. Schwass
Senior Vice President and
Chief Financial Officer
Date August 13, 1997 /s/ Morgan K. O'Brien
------------------------ ----------------------------
(Signature)
Morgan K. O'Brien
Controller and
Principal Accounting Officer
25
<PAGE>
Exhibit 12.1
Duquesne Light Company and Subsidiary
Calculation of Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
Six Months Ended -----------------------
June 30, 1997 1996 1995 1994 1993 1992
-------------- ---- --------- --------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $ 40,814 $ 82,505 $ 89,139 $ 94,646 $102,938 $119,179
Other interest 509 1,632 2,599 1,095 2,387 1,749
Monthly Income Preferred Securities dividend requirements 6,281 7,921 - - - -
Amortization of debt discount, premium and expense - net 2,940 5,973 6,252 6,381 5,541 4,223
Portion of lease payments representing an interest factor 22,179 44,357 44,386 44,839 45,925 60,721
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 72,723 $142,388 $142,376 $146,961 $156,791 $185,872
-------- -------- -------- -------- -------- --------
EARNINGS:
Income from continuing operations $ 63,571 $149,860 $151,070 $147,449 $144,787 $149,768
Income taxes 11,341* 83,008* 92,894* 84,191* 77,237* 110,993
Fixed charges as above 72,723 142,388 142,376 146,961 156,791 185,872
-------- -------- -------- -------- -------- --------
Total Earnings $147,635 $375,256 $386,340 $378,601 $378,815 $446,633
-------- -------- -------- -------- -------- --------
RATIO OF EARNINGS TO FIXED CHARGES 2.03 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 $1.4 million for the six months ended
June 30, 1997, has been excluded from the ratio.
*Earnings related to income taxes reflect a $6.0 million decrease for the six
months ended June 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 2.11 for the six months ended June 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> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,655,863
<OTHER-PROPERTY-AND-INVEST> 158,659
<TOTAL-CURRENT-ASSETS> 387,576
<TOTAL-DEFERRED-CHARGES> 648,919
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,851,017
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 822,841
<RETAINED-EARNINGS> 165,067
<TOTAL-COMMON-STOCKHOLDERS-EQ> 987,908
3,000
221,238<F1>
<LONG-TERM-DEBT-NET> 1,199,983
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 120,000
0
<CAPITAL-LEASE-OBLIGATIONS> 22,768
<LEASES-CURRENT> 18,334
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,277,786
<TOT-CAPITALIZATION-AND-LIAB> 3,851,017
<GROSS-OPERATING-REVENUE> 555,285
<INCOME-TAX-EXPENSE> 34,177
<OTHER-OPERATING-EXPENSES> 420,775
<TOTAL-OPERATING-EXPENSES> 454,952
<OPERATING-INCOME-LOSS> 100,333
<OTHER-INCOME-NET> 12,432
<INCOME-BEFORE-INTEREST-EXPEN> 112,765
<TOTAL-INTEREST-EXPENSE> 49,194<F2>
<NET-INCOME> 63,571
2,014
<EARNINGS-AVAILABLE-FOR-COMM> 61,557
<COMMON-STOCK-DIVIDENDS> 63,490
<TOTAL-INTEREST-ON-BONDS> 43,754
<CASH-FLOW-OPERATIONS> 152,690
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0.00
<FN>
<F1>Includes $10,630 of Preference Stock
<F2>Includes $6,345 of Monthly Income Preferred Securities Dividend Requirements
</FN>
</TABLE>
