<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 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, 2000
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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 and (2) has been subject to such filing requirements for
the past 90 days. Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
DQE, Inc., is the holder of all shares of Duquesne Light Company common stock,
$1 par value, consisting of 10 shares as of July 31, 2000.
<PAGE>
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements.
<TABLE>
<CAPTION>
Duquesne Light Condensed Statement of Consolidated Income (Unaudited)
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(Thousands of Dollars)
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Three Months Ended June 30, Six Months Ended June 30,
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2000 1999 2000 1999
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<S> <C> <C> <C> <C>
Operating Revenues:
Sales of Electricity:
Customer revenues $257,452 $239,948 $497,950 $494,367
Utilities 10,110 15,478 21,900 29,131
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Total Sales of Electricity 267,562 255,426 519,850 523,498
Other 11,194 17,908 21,889 31,899
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Total Operating Revenues 278,756 273,334 541,739 555,397
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Operating Expenses:
Fuel and purchased power 92,709 49,669 143,336 96,580
Other operating 37,489 59,894 82,552 121,990
Maintenance 18,685 23,434 36,374 43,771
Depreciation and amortization 76,269 47,058 137,803 99,898
Taxes other than income taxes 19,212 22,148 41,168 44,238
Income taxes 10,536 16,558 17,210 35,251
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Total Operating Expenses 254,900 218,761 458,443 441,728
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Operating Income 23,856 54,573 83,296 113,669
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Other Income and Deductions 7,084 6,062 11,590 14,210
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Income Before Interest and Other Charges 30,940 60,635 94,886 127,879
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Interest Charges 19,669 28,918 40,637 57,154
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Monthly Income Preferred Securities Dividend Requirements 3,140 3,140 6,281 6,281
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Net Income 8,131 28,577 47,968 64,444
====================================================================================================================================
Dividends on Preferred and Preference Stock 869 987 1,726 1,980
Earnings for Common Stock $ 7,262 $ 27,590 $ 46,242 $ 62,464
====================================================================================================================================
</TABLE>
See notes to condensed consolidated financial statements.
2
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<TABLE>
<CAPTION>
Duquesne Light Condensed Consolidated Balance Sheet (Unaudited)
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(Thousands of Dollars)
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June 30, December 31,
ASSETS 2000 1999
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<S> <C> <C>
Property, Plant and Equipment:
Gross property, plant and equipment $ 1,938,642 $ 3,959,236
Less: Accumulated depreciation and amortization (620,352) (2,500,719)
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Total Property, Plant and Equipment--Net 1,318,290 1,458,517
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Long-Term Investments 59,346 80,891
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Current Assets:
Cash and temporary cash investments 62,502 16,068
Receivables 382,615 131,647
Prepaid taxes 300,000 --
Other current assets 21,934 111,134
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Total Current Assets 767,051 258,849
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Other Non-Current Assets:
Transition costs 554,431 2,008,171
Regulatory assets 224,411 224,002
Divestiture costs -- 218,653
Other 20,815 32,329
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Total Other Non-Current Assets 799,657 2,483,155
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Total Assets $ 2,944,344 $ 4,281,412
====================================================================================================================================
CAPITALIZATION AND LIABILITIES
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Capitalization:
Common stock (authorized--90,000,000 shares, issued and outstanding--10 shares) $ -- $ --
Capital surplus 483,345 746,051
Retained earnings 30,171 39,931
Accumulated other comprehensive income 14,417 12,692
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Total Common Stockholder's Equity 527,933 798,674
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Preferred and Preference Stock 222,028 229,512
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Long-term debt 1,060,713 1,410,754
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Total Capitalization 1,810,674 2,438,940
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Obligations Under Capital Leases 10,726 16,534
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Current Liabilities:
Notes payable and current debt maturities 755 536,353
Other current liabilities 292,709 225,333
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Total Current Liabilities 293,464 761,686
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Non-Current Liabilities:
Deferred income taxes - net 550,015 760,677
Deferred investment tax credits 21,125 22,208
Deferred income 158 93,246
Other non-current liabilities 258,182 188,121
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Total Non-Current Liabilities 829,480 1,064,252
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Commitments and Contingencies (Note D)
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Total Capitalization and Liabilities $ 2,944,344 $ 4,281,412
====================================================================================================================================
</TABLE>
See notes to condensed consolidated financial statements.
3
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<TABLE>
<CAPTION>
Duquesne Light Condensed Statement of Consolidated Cash Flows (Unaudited)
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(Thousands of Dollars)
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Six Months Ended June 30,
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2000 1999
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<S> <C> <C>
Cash Flows From Operating Activities:
Operations $ 160,665 $ 156,717
Changes in working capital other than cash 44,744 (4,471)
Prepaid taxes (300,000) --
Other (21,378) (15,389)
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Net Cash Provided By (Used In) Operating Activities (115,969) 136,857
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Cash Flows From Investing Activities:
Sale of generation assets 1,705,000 --
Proceeds from sale of inventory 21,144 --
Acquisitions (32,000) --
Construction expenditures (38,239) (40,760)
Divestiture costs (89,649) --
Long-term investments -- (1,431)
Other (7,582) (4,931)
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Net Cash Provided By (Used In) Investing Activities 1,558,674 (47,122)
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Cash Flows From Financing Activities:
Redemption of commercial paper (136,594) --
Issuance of debt -- 19,500
Loan to affiliate (250,000) --
Dividends on capital stock (257,728) (145,431)
Reductions of long-term obligations (749,197) (9,097)
Other (2,752) 340
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Net Cash (Used In) Financing Activities (1,396,271) (134,688)
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Net increase (decrease) in cash and temporary cash investments 46,434 (44,953)
Cash and temporary cash investments at beginning of period 16,068 53,151
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Cash and Temporary Cash Investments at End of Period $ 62,502 $ 8,198
====================================================================================================================================
Non-Cash Investing and Financing Activities:
Capital lease obligations recorded $ -- $ 5,988
Dividend of subsidiary companies' assets $ (67,502) $ --
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</TABLE>
See notes to condensed consolidated financial statements.
4
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<TABLE>
<CAPTION>
Duquesne Light Condensed Statement of Consolidated Comprehensive Income (Unaudited)
(Thousands of Dollars)
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Three Months Ended June 30, Six Months Ended June 30,
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2000 1999 2000 1999
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<S> <C> <C> <C> <C>
Net income $ 8,131 $ 28,577 $ 47,968 $ 64,444
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Other comprehensive income:
Unrealized holding gains (losses) arising during the period,
net of tax of $(3,286), $1,074, $1,224 and $(2,719) (4,633) 1,514 1,726 (3,834)
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Comprehensive Income $ 3,498 $ 30,091 $ 49,694 $ 60,610
====================================================================================================================================
</TABLE>
See notes to condensed consolidated financial statements.
Notes to Consolidated Financial Statements
A. SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
Consolidation
Duquesne Light Company is a wholly owned subsidiary of DQE, Inc., a multi-
utility delivery and services company. Our two wholly owned subsidiaries,
Monongahela Light and Power Company and Duquesne Financial LLC, are involved in
making long-term investments and providing financing to certain affiliates,
respectively.
We are engaged in the transmission and distribution of electric energy.
On April 28, 2000, we completed the Pennsylvania Public Utility Commission
(PUC)-approved sale of our generation assets to Orion Power MidWest, L.P. (See
"Generation Asset Sale" discussion, Note B, on page 6.)
All material intercompany balances and transactions have been eliminated in
the preparation of the consolidated financial statements.
In the opinion of management, the unaudited condensed consolidated
financial statements included in this report reflect all adjustments that are
necessary for a fair presentation of the results of interim periods and are
normal, recurring adjustments. Prior periods have been reclassified to conform
with current accounting presentations.
These statements should be read with the financial statements and notes
included in our Annual Report on Form 10-K for the year ended December 31, 1999
filed with the Securities and Exchange Commission (SEC). The results of
operations for the three and six months ended June 30, 2000, 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.
Basis of Accounting
We are subject to the accounting and reporting requirements of the SEC. In
addition, our electric utility operations are subject to regulation by the PUC
and the Federal Energy Regulatory Commission (FERC) with respect to rates for
interstate sales, transmission of electric power, accounting and other matters.
As a result of our PUC-approved restructuring plan (see "Rate Matters," Note
B, below), the electricity supply segment does not meet the criteria of
Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the
Effects of Certain Types of Regulation (SFAS No. 71). Pursuant to the PUC's
final restructuring order, generation-related regulatory assets are being
recovered through a competitive transition charge (CTC) collected in connection
with providing transmission and distribution services, and these assets have
been reclassified accordingly. The balance of transition costs was adjusted by
receipt of the generation asset sale proceeds. The electricity delivery business
segment continues to meet SFAS No. 71 criteria, and accordingly reflects
regulatory assets and liabilities consistent with cost-based ratemaking
regulations. The regulatory assets represent probable future revenue, because
provisions for these costs are currently included, or are expected to be
included, in charges to electric utility customers through the ratemaking
process. (See "Rate Matters," Note B, below.) These regulatory assets consist of
a regulatory tax receivable, unamortized debt costs and deferred employee costs.
B. RATE MATTERS
Competition and the Customer Choice Act
Under Pennsylvania ratemaking practice, regulated electric utilities were
granted exclusive geographic franchises to sell electricity, in exchange for
making investments and incurring obligations to serve customers under the then-
existing regulatory framework. Through the ratemaking process, those prudently
incurred costs were recovered from customers, along with a return on the
investment. Additionally, certain operating costs were approved for deferral
for future recovery from customers (regulatory assets). As a result of this
process, utilities
5
<PAGE>
had assets recorded on their balance sheets at above-market costs, thus creating
transition costs.
The Pennsylvania Electricity Generation Customer Choice and Competition Act
(Customer Choice Act) enables Pennsylvania's electric utility customers to
purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). All customers now have customer choice. As of
July 31, 2000, approximately 26.9 percent of our customers had chosen
alternative generation suppliers, representing approximately 12.5 percent of our
non-coincident peak load. The remaining customers are provided with electricity
through our provider of last resort services agreement with Orion (discussed
below). Customers pay their electricity generation supplier for generation
charges, and pay us the CTC and charges for transmission and distribution.
Electricity delivery (including transmission, distribution and customer service)
remains regulated in substantially the same manner as under historical
regulation.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, was
originally imposed on the transmission and distribution charges of Pennsylvania
electric utility companies under the Customer Choice Act. As part of a
settlement regarding recovery of deferred fuel costs, we previously agreed to
extend this rate cap for an additional six months through the end of 2001.
However, if our amended provider of last resort arrangement is approved, the
rate cap will be extended through 2003, with a possible further extension
through 2004. (See "Provider of Last Resort" discussion below.)
Provider of Last Resort
We are required not only to deliver electricity, but also to serve as the
provider of last resort for all customers in our service territory. Although no
longer a generation supplier, as the provider of last resort, we must provide
electricity for any customer who cannot or does not choose an alternative
electric generation supplier, or whose supplier fails to deliver. While
collecting the CTC, we may charge only PUC-approved rates for the supply of
electricity as the provider of last resort. As part of the generation asset
sale, Orion agreed to supply us, under a provider of last resort service
agreement, with all of the electric energy necessary to satisfy our provider of
last resort obligations during the CTC collection period. This agreement, which
expires upon our final collection of the CTC, in general effectively transfers
to Orion the financial risks and rewards associated with our provider of last
resort obligations. While we retain the collection risk for the electricity
sales, a component of our regulated delivery rates is designed to cover the cost
of a normal level of uncollectible accounts. In April 2000, we entered into an
agreement with Orion that, as amended in June 2000 and subject to PUC and other
approvals, would extend this provider of last resort arrangement beyond the
final CTC collection through 2004. We anticipate a determination by the PUC
later this year.
Generation Asset Sale
On April 28, 2000, we completed the sale of our generation assets to Orion.
Orion purchased the wholly owned Cheswick, Elrama, Phillips and Brunot Island
power stations, as well as the stations received from FirstEnergy Corp. in the
December 3, 1999 power station exchange, for approximately $1.7 billion.
In its May 29, 1998, final restructuring order, the PUC determined that
we should recover most of the above-market costs of our generation assets,
including plant and regulatory assets, through the collection of the CTC from
electric utility customers. Originally, transition costs were to be recovered
over a seven-year period ending in 2005. As we have regularly stated in our
reports, however, by applying the net proceeds of the generation asset sale to
reduce transition costs, we anticipated early termination of the CTC collection
period in 2001. However, on August 4, 2000, we submitted our final sale-related
filing to the PUC, seeking approval for the accounting treatment of the asset
sale proceeds. Pursuant to this filing, we now anticipate early termination of
the CTC collection period in the first quarter of 2002 for most major rate
classes. In addition, the transition costs, as reflected on the consolidated
balance sheet, are being amortized over the same period that the CTC revenues
are being recognized. The unrecovered balance of transition costs that remain
following the generation asset sale, previously anticipated to be approximately
$2.1 billion ($1.5 billion net of tax), was approximately $550 million ($330
million net of tax) at June 30, 2000. We are allowed to earn an 11 percent pre-
tax return on this net amount, which remains subject to PUC review. We cannot
predict the ultimate outcome of the PUC's determinations regarding our filing,
the accounting treatment sought, or the balance of transition costs.
Termination of the AYE Merger
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement with Allegheny Energy, Inc. (AYE). AYE filed suit in the United
States District Court for the Western District of Pennsylvania, seeking to
compel DQE to proceed with the merger, or in the alternative seeking an
unspecified amount of money damages. After holding a trial from October 20
through 28, 1999, the District Court ruled on December 3, 1999, that DQE had
properly terminated the merger agreement without breach, and granted judgment in
DQE's favor on all claims and all requests for injunctive relief. On December
14, 1999, AYE appealed this ruling to the Third Circuit. On May 17, 2000, the
Third Circuit unanimously affirmed the District Court's ruling. In early June
2000, AYE announced it would not pursue further appeals in this matter.
6
<PAGE>
C. RECEIVABLES
The components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
(Thousands of Dollars)
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June 30, June 30, December 31,
2000 1999 1999
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<S> <C> <C> <C>
Electric customers $ 101,829 $ 86,136 $ 82,314
Other utility 11,551 22,154 32,582
Loan to DQE 250,000 -- --
Other 30,071 32,951 25,481
(Allowance for uncollectible accounts) (10,836) (10,308) (8,730)
------------------------------------------------------------------------------------------------
Receivables - net 382,615 130,933 131,647
Less: Receivables sold -- (50,000) --
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Total $ 382,615 $ 80,933 $ 131,647
================================================================================================
</TABLE>
We have an agreement with an unaffiliated corporation that entitles us to
sell and the corporation to purchase, on an ongoing basis, up to $40 million of
accounts receivable. The accounts receivable sales agreement expires in
February 2001, and was recently amended to reduce the sale and purchase
entitlement from $50 million. The agreement is one of many sources of funds
available to us. We may elect to extend the agreement upon expiration, replace
it with a similar facility, or terminate it.
D. COMMITMENTS AND CONTINGENCIES
We estimate that in 2000 we will spend, excluding the allowance for funds
used during construction, approximately $85 million (including $5 million
relating to generation) for electric utility construction.
E. BUSINESS SEGMENTS AND
RELATED INFORMATION
We report our results by the following three principal business segments,
determined by products, services and regulatory environment: (1) the
transmission and distribution of electricity (electricity delivery business
segment), (2) the supply of electricity (electricity supply business segment)
and (3) the collection of transition costs (CTC business segment). We also
report an "all other" category, which includes investments below the
quantitative threshold for separate disclosure.
7
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<TABLE>
<CAPTION>
Business Segments for the Three Months Ended,
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(Millions of Dollars)
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Electricity Electricity All Consoli-
Delivery Supply CTC Other dated
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June 30, 2000
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<S> <C> <C> <C> <C> <C>
Operating revenues $ 85.4 $ 101.6 $ 91.8 $ -- $ 278.8
Operating expenses 53.2 112.1 13.9 (0.6) 178.6
Depreciation and amortization expense 14.1 -- 61.6 0.6 76.3
--------------------------------------------------------------------------------------------------------------
Operating income (loss) 18.1 (10.5) 16.3 -- 23.9
Other income 7.4 (0.9) -- 0.6 7.1
Interest and other charges 18.4 3.3 2.0 -- 23.7
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Earnings (loss) for common stock $ 7.1 $ (14.7) $ 14.3 $ 0.6 $ 7.3
==============================================================================================================
Assets $2,328.1 $ -- $ 554.4 $ 61.8 $2,944.3
==============================================================================================================
Capital expenditures $ 22.1 $ 4.7 $ -- $ -- $ 26.8
==============================================================================================================
</TABLE>
<TABLE>
<CAPTION>
(Millions of Dollars)
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Electricity Electricity All Consoli-
Delivery Supply CTC Other dated
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June 30, 1999
--------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 81.1 $ 102.8 $ 89.4 $ -- $ 273.3
Operating expenses 48.7 98.2 23.9 0.9 171.7
Depreciation and amortization expense 12.8 8.8 25.4 -- 47.0
--------------------------------------------------------------------------------------------------------------
Operating income (loss) 19.6 (4.2) 40.1 (0.9) 54.6
Other income 0.6 2.0 -- 3.4 6.0
Interest and other charges 9.1 11.8 12.0 0.1 33.0
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Earnings (loss) for common stock $ 11.1 $ (14.0) $ 28.1 $ 2.4 $ 27.6
==============================================================================================================
Assets (1) $1,535.4 $ 425.7 $2,226.8 $ 93.5 $4,281.4
==============================================================================================================
Capital expenditures $ 15.2 $ 9.1 $ -- $ -- $ 24.3
==============================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1999.
8
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<TABLE>
<CAPTION>
Business Segments for the Six Months Ended,
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(Millions of Dollars)
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Electricity Electricity All Consoli-
Delivery Supply CTC Other dated
------------------------------------------------------------------
June 30, 2000
--------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 172.8 $ 180.4 $ 188.2 $ 0.3 $ 541.7
Operating expenses 97.8 191.7 32.5 (1.4) 320.6
Depreciation and amortization expense 23.2 5.2 107.6 1.8 137.8
--------------------------------------------------------------------------------------------------------------
Operating income (loss) 51.8 (16.5) 48.1 (0.1) 83.3
Other income 8.3 1.6 -- 1.7 11.6
Interest and other charges 29.6 5.5 13.4 0.2 48.7
--------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ 30.5 $ (20.4) $ 34.7 $ 1.4 $ 46.2
==============================================================================================================
Assets $2,328.1 $ -- $ 554.4 $ 61.8 $2,944.3
==============================================================================================================
Capital expenditures $ 33.5 $ 4.7 $ -- $ -- $ 38.2
==============================================================================================================
</TABLE>
<TABLE>
<CAPTION>
(Millions of Dollars)
------------------------------------------------------------------
Electricity Electricity All Consoli-
Delivery Supply CTC Other dated
------------------------------------------------------------------
June 30, 1999
--------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 163.4 $ 209.4 $ 182.4 $ 0.2 $ 555.4
Operating expenses 95.3 197.4 47.8 1.3 341.8
Depreciation and amortization expense 27.2 17.7 55.0 -- 99.9
--------------------------------------------------------------------------------------------------------------
Operating income (loss) 40.9 (5.7) 79.6 (1.1) 113.7
Other income 1.7 4.0 -- 8.5 14.2
Interest and other charges 18.1 23.5 23.7 0.1 65.4
--------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ 24.5 $ (25.2) $ 55.9 $ 7.3 $ 62.5
==============================================================================================================
Assets (1) $1,535.4 $ 425.7 $2,226.8 $ 93.5 $4,281.4
==============================================================================================================
Capital expenditures $ 28.6 $ 12.1 $ -- $ -- $ 40.7
==============================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1999.
9
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in
conjunction with our Annual Report on Form 10-K for the year ended December 31,
1999 filed with the Securities and Exchange Commission (SEC) and our condensed
consolidated financial statements, which are set forth on pages 2 through 9 of
this Report.
Duquesne Light Company is a wholly owned subsidiary of DQE, Inc., a multi-
utility delivery and services company. Our two wholly owned subsidiaries,
Monongahela Light and Power Company and Duquesne Financial LLC, are involved in
making long-term investments and providing financing to certain affiliates,
respectively.
We are engaged in the transmission and distribution of electric energy. On
April 28, 2000, we completed the Pennsylvania Public Utility Commission (PUC)-
approved sale of our generation assets to Orion Power MidWest, L.P. (See
"Generation Asset Sale" discussion on page 14.)
Service Area
We provide service to approximately 580,000 direct customers in southwestern
Pennsylvania (including in the City of Pittsburgh), a territory of approximately
800 square miles. Before completing the generation asset sale, we also
historically sold electricity to other utilities. (See "Generation Asset Sale"
discussion on page 14.)
Regulation
We are subject to the accounting and reporting requirements of the SEC. In
addition, our electric utility operations are subject to regulation by the PUC
and the Federal Energy Regulatory Commission (FERC) with respect to rates for
interstate sales, transmission of electric power, accounting and other matters.
As a result of our PUC-approved restructuring plan (see "Rate Matters" on
page 14), the electricity supply segment of our business does not meet the
criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Pursuant to the PUC's final restructuring order, generation-related regulatory
assets are being recovered through a competitive transition charge (CTC)
collected in connection with providing transmission and distribution services,
and these assets have been reclassified accordingly. The balance of transition
costs was adjusted by receipt of the proceeds from the generation asset sale.
The electricity delivery business segment continues to meet SFAS No. 71
criteria, and accordingly reflects regulatory assets and liabilities consistent
with cost-based ratemaking regulations. The regulatory assets represent probable
future revenue, because provisions for these costs are currently included, or
are expected to be included, in charges to electric utility customers through
the ratemaking process. (See "Rate Matters" on page 14.)
On December 15, 1999, the FERC issued its Order No. 2000, which calls on
transmission-owning utilities such as Duquesne Light to voluntarily join
regional transmission organizations. The goal of the order is to put
transmission facilities in a region under common control in an effort to reduce
costs. The order requires utilities to file a proposal for a regional
transmission organization, a description of efforts to join one, or reasons for
not joining one, by October 15, 2000. We are currently studying Order No. 2000,
and have not yet determined our response.
Business Segments
For the purposes of complying with SFAS No. 131, Disclosures about Segments
of an Enterprise and Related Information (SFAS No. 131), we are required to
disclose information about our business segments separately. This information is
set forth in "Results of Operations" below and in "Business Segments and Related
Information," Note E to our condensed consolidated financial statements on
page 7.
RESULTS OF OPERATIONS
Overall Performance
Comparison of Three Months Ended June 30, 2000 and June 30, 1999. Our
earnings available for common stock were $7.3 million in the second quarter of
2000 compared to $27.6 million in the second quarter of 1999, a decrease of 73.6
percent.
The lower earnings level for the second quarter can be attributed to an
adjustment of our transition costs based upon the net generation asset sale
proceeds. The adjustment resulted in approximately $11 million less of recorded
earnings in the second quarter of 2000 compared to the second quarter of 1999.
Comparison of Six Months Ended June 30, 2000 and June 30, 1999. Our
earnings available for common stock were $46.2 million in the first six months
of 2000 compared to $62.5 million in the first six months of 1999, a decrease of
26.1 percent.
Results of Operations by Business Segment
Historically, Duquesne Light was treated as a single integrated business
segment, due to its regulated operating environment. The PUC authorized a
combined rate for supplying and delivering electricity to customers, that was
(1) cost-based, (2) designed to recover operating expenses and investment in
electric utility assets, and (3) designed to provide a return on the investment.
As a result of the Pennsylvania Electricity Generation Customer Choice and
10
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Competition Act (Customer Choice Act), supply of electricity is deregulated and
charged at a separate rate from the delivery of electricity. For the purposes of
complying with SFAS No. 131, Disclosures about Segments of an Enterprise and
Related Information, we are required to disclose information about our business
segments separately.
We report our results by the following three principal business segments,
determined by products, services and regulatory environment: (1) the
transmission and distribution of electricity (electricity delivery business
segment), (2) the supply of electricity (electricity supply business segment),
and (3) the collection of transition costs (CTC business segment). With the
completion of our generation asset sale on April 28, 2000, the electricity
supply business segment is now comprised solely of provider of last resort
service. We also report an "all other" category, comprised of our investments,
which in 2000 include our automated meter reading assets, and in 1999 included
leasing and landfill gas reserve investments.
Additional information on our business segments is set forth in Note E,
"Business Segments and Related Information," in the Notes to the Consolidated
Financial Statements on page 7.
Electricity Delivery Business Segment.
Comparison of Three Months Ended June 30, 2000 and June 30, 1999. The
electricity delivery business segment contributed $7.1 million to earnings
available for common stock in the second quarter of 2000 compared to $11.1
million in the second quarter of 1999, a decrease of $4.0 million.
Operating revenues for this business segment are primarily derived from the
delivery of electricity. Sales to residential and commercial customers are
influenced by weather conditions. Warmer summer and colder winter seasons lead
to increased customer use of electricity for cooling and heating. Commercial
sales also are affected by regional development. Sales to industrial customers
are influenced primarily by national and global economic conditions.
Operating revenues increased by $4.3 million or 5.3 percent compared to the
second quarter of 1999. The higher sales can be attributed to warmer weather in
2000 as well as increased consumption by steel manufacturers. The following
table sets forth kilowatt-hours (KWH) delivered to electric utility customers.
<TABLE>
<CAPTION>
------------------------------------------------
KWH Delivered
----------------------
(In Millions)
----------------------
Second Quarter 2000 1999 Change
------------------------------------------------
<S> <C> <C> <C>
Residential 773 752 2.8%
Commercial 1,492 1,457 2.4%
Industrial 901 873 3.2%
---------------------------------------
Sales to Electric
Utility Customers 3,166 3,082 2.7%
================================================
</TABLE>
Operating expenses for the electricity delivery business segment primarily
are made up of costs to operate and maintain the transmission and distribution
system; meter reading and billing costs; customer service; collection;
administrative expenses; income taxes; and non-income taxes, such as gross
receipts, property and payroll taxes. Operating expenses increased by $4.5
million or 9.2 percent from the second quarter of 1999. This increase is
attributable to a higher level of expenses being allocated to the delivery
business segment also due to the sale of our generation assets.
Other income was $7.4 million for the second quarter of 2000 compared to
$0.6 million in the second quarter of 1999, an increase of $6.8 million. This
increase is attributable to interest income from the DQE loan and additional
allocation to this segment due to the generation asset sale.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends. In the second quarter of 2000, there was
$9.3 million more interest and other charges allocated to the electricity
delivery business segment compared to the second quarter of 1999. Given the
generation asset sale to Orion, all remaining financing costs after
recapitalization are borne by the electricity delivery business segment.
Comparison of Six Months Ended June 30, 2000 and June 30, 1999. The
electricity delivery business segment contributed $30.5 million to earnings
available for common stock in the first six months of 2000 compared to $24.5
million in the first six months of 1999, an increase of $6.0 million or 24.5
percent.
Operating revenues increased by $9.4 million or 5.8 percent compared to the
first six months of 1999 due to an increase of 3.1 percent in sales to electric
utility customers. This increase is primarily attributable to increased
consumption by steel manufacturers. The following table sets forth KWH delivered
to electric utility customers.
<TABLE>
<CAPTION>
------------------------------------------------
KWH Delivered
----------------------
(In Millions)
----------------------
First Six Months 2000 1999 Change
------------------------------------------------
<S> <C> <C> <C>
Residential 1,677 1,668 0.5%
Commercial 2,977 2,898 2.7%
Industrial 1,834 1,724 6.4%
---------------------------------------
Sales to Electric
Utility Customers 6,488 6,290 3.1%
================================================
</TABLE>
Operating expenses were $2.5 million or 2.6 percent higher than 1999. This
increase is attributed to a higher level of expenses being allocated to the
delivery business segment due to the sale of our generation assets.
11
<PAGE>
Other income was $6.6 million higher than the first six months of 1999. This
increase is attributable to interest income from the DQE loan and additional
allocation to this segment due to the generation asset sale.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends. In the first six months of 2000, there
was $11.5 million or 63.5 percent more interest and other charges allocated to
the electricity delivery business segment compared to the first six months of
1999.
Electricity Supply and CTC Business Segments.
Comparison of Three Months Ended June 30, 2000 and June 30, 1999. In the
second quarter of 2000, the electricity supply and CTC business segments
reported a loss for common stock of $0.4 million compared to net income of $14.1
million in the second quarter of 1999, a decrease of $14.5 million.
For the electricity supply and CTC business segments, operating revenues
are derived primarily from the supply of electricity for delivery to retail
customers, the supply of electricity to wholesale customers and the collection
of generation-related transition costs from electricity delivery customers.
Energy requirements for residential and commercial customers are also
influenced by weather conditions. Warmer summer and colder winter seasons lead
to increased customer use of electricity for cooling and heating. Commercial
energy requirements are also affected by regional development. Energy
requirements for industrial customers are primarily influenced by national and
global economic conditions.
Short-term sales to other utilities are made at market rates. Fluctuations
in electricity sales to other utilities are related to customer energy
requirements, the energy market and transmission conditions, and the
availability of generating stations.
Operating revenues were relatively consistent in the second quarters of 2000
and 1999. The following table sets forth KWH supplied for customers who have not
chosen an alternative generation supplier, including unbilled provider of last
resort KWH supplied.
<TABLE>
<CAPTION>
------------------------------------------------
KWH Supplied
----------------------
(In Millions)
----------------------
Second Quarter 2000 1999 Change
------------------------------------------------
<S> <C> <C> <C>
Residential 643 634 1.4%
Commercial 1,251 987 26.7%
Industrial 979 838 16.8%
----------------------------------------
Sales to Electric
Utility Customers 2,873 2,459 16.8%
----------------------------------------
Sales to Other Utilities 301 788 (61.8)%
----------------------------------------
Total Sales 3,174 3,247 (2.2)%
=================================================
</TABLE>
Operating expenses for the electricity supply business segment are primarily
made up of energy costs; costs to operate and maintain the power stations;
administrative expenses; income taxes; and non-income taxes, such as gross
receipts, property and payroll taxes.
Fluctuations in energy costs generally result from changes in the cost of
fuel; total KWH supplied; and generating station availability. In the second
quarter of 1999, fluctuations also resulted from the mix between coal, nuclear
generation and purchased power.
Operating expenses increased $3.9 million or 3.2 percent from the second
quarter of 1999, as a result of the generation asset sale. During the second
quarter of 2000, operating costs consisted of purchased power costs related to
the Orion provider of last resort supply agreement. (See "Provider of Last
Resort" discussion on page 14.) The cost, approximately $0.04 per KWH, is equal
to the customer shopping credit. During 1999,the average production cost, both
fuel and non-fuel operating and maintenance costs, was approximately $0.025 per
KWH.
Depreciation and amortization expense includes the amortization of
transition costs and, in the second quarter of 1999, accrued nuclear
decommissioning costs. There was an increase of $27.4 million or 80.1 percent
compared to the second quarter of 1999. This increase was due to a higher level
of transition cost amortization in the second quarter of 2000.
Interest and other charges include interest on debt, other interest and
preferred stock dividends. In the second quarter of 2000 there was an $18.5
million decrease in interest and other charges compared to the second quarter of
1999. The decrease reflects less interest expense allocated to this segment in
the second quarter of 2000 due to the generation asset sale.
Comparison of Six Months Ended June 30, 2000 and June 30, 1999. In the first
six months of 2000, the electricity supply and CTC business segments reported
net income of $14.3 million compared to $30.7 million in the first six months of
1999, a decrease of $16.4 million or 53.4 percent.
Operating revenues decreased by $23.2 million or 5.9 percent compared to the
first six months of 1999. The decrease in revenues resulted from a 45.2 percent
decrease in energy supplied to other utilities in the first six months of 2000
compared to the first six months of 1999, due to the generation asset sale. The
following table sets forth KWH supplied for customers who have not chosen an
alternative generation supplier, including unbilled provider of last resort KWH
supplied.
12
<PAGE>
<TABLE>
<CAPTION>
-------------------------------------------------
KWH Supplied
-----------------------
(In Millions)
-----------------------
First Six Months 2000 1999 Change
-------------------------------------------------
<S> <C> <C> <C>
Residential 1,326 1,457 (9.0)%
Commercial 2,130 2,139 (0.4)%
Industrial 1,827 1,660 10.1%
----------------------------------------
Sales to Electric
Utility Customers 5,283 5,256 0.5%
----------------------------------------
Sales to Other Utilities 795 1,450 (45.2)%
----------------------------------------
Total Sales 6,078 6,706 (9.4)%
=================================================
</TABLE>
Operating expenses decreased $21.0 million or 8.6 percent from the first six
months of 1999, as a result of lower power production costs through the date of
the generation asset sale. Partially offsetting this decrease was an increase in
purchased power costs in 2000 from the higher rate per KWH due to the customer
shopping credit.
There was an increase of $40.1 million or 55.2 percent in depreciation and
amortization expense compared to the first six months of 1999. This increase was
due to a higher level of transition cost amortization in the first six months of
2000.
In the first six months of 2000 there was a $28.3 million or 60.0 percent
decrease in interest and other charges compared to the first six months of 1999.
The decrease reflects less interest expense allocated to the electricity supply
and CTC business segments in 2000 due to the generation asset sale.
All Other.
Comparison of Three Months Ended June 30, 2000 and June 30, 1999. The all
other category contributed $0.6 million to earnings available for common stock
in the second quarter of 2000 compared to $2.4 million in the second quarter of
1999, a decrease of $1.8 million or 75.0 percent. The decrease is primarily the
result of lower lease income in the second quarter of 2000.
Comparison of Six Months Ended June 30, 2000 and June 30, 1999. The all
other category contributed $1.4 million to earnings available for common stock
in the first six months of 2000 compared to $7.3 million in the first six months
of 1999, a decrease of $5.9 million. The decrease can be attributed to lower
lease income in 2000.
LIQUIDITY AND CAPITAL RESOURCES
Capital Expenditures
We estimate that during 2000 we will spend, excluding the allowance for
funds used during construction, approximately $85 million for electric utility
construction, including $5 million for generation. During the first six months
of 2000, we have spent approximately $38.2 million on capital expenditures
related to the electricity delivery and supply business segments.
Disposition
On April 28, 2000, we completed the sale of our generation assets to Orion
for approximately $1.7 billion. (See "Generation Asset Sale" discussion on
page 14.)
Investments
During the second quarter we lent $250 million to our parent company, DQE.
The loan is in the form of a demand note bearing 8 percent annual interest
payable quarterly.
Financing
At June 30, 2000, we had $0.8 million of current debt maturities. During the
quarter, the maximum amount of bank loans and commercial paper borrowings
outstanding was $51.5 million, the amount of average daily borrowings was $14
million, and the weighted average daily interest rate was 6.13 percent.
With the proceeds of the generation asset sale in April 2000, we retired
$350 million of long-term bonds, $399 million of current maturities and $137
million of commercial paper.
During the second quarter, we dividended certain assets in our Monongahela
Light & Power subsidiary to our parent company, DQE.
Future Capital Requirements and Availability
We are using the proceeds of our generation asset sale to recapitalize. As
previously reported, we have retired short-term debt and redeemed long-term
debt.
We maintain a $225 million revolving credit agreement expiring in September
2000. We have the option to convert the revolver into a term loan facility for
a period of two years for any amounts then outstanding upon expiration of the
revolving credit period. Interest rates can, in accordance with the option
selected at the time of the borrowing, be based on one of several indicators,
including prime, Eurodollar, or certificate of deposit rates. Facility fees are
based on the unborrowed amount of the commitment. At June 30, 2000, no
borrowings were outstanding.
We have an agreement with an unaffiliated corporation that entitles us to
sell, and the corporation to purchase, on an ongoing basis, up to $40 million of
accounts receivable. At various times during the second quarter, we had sold
receivables under the facility. No amounts were outstanding at June 30, 2000. At
June 30, 1999 we had sold $50 million of receivables. The accounts receivable
sales agreement expires in February 2001, and was recently amended to reduce the
sale and purchase entitlement from $50 million. The agreement is one of many
sources of funds available to us. We may elect to extend the agreement upon
expiration, replace it with a similar facility, or terminate it.
With customer choice fully in effect, and our generation asset divestiture
complete, all our electric utility customers are buying their generation
directly from alternative suppliers or indirectly from Orion (who supplies
generation to us pursuant
13
<PAGE>
to our provider of last resort service agreement). Customer revenues from our
operations have been reduced by an amount equal to the generation rate
previously applicable to those customers using alternative generation suppliers.
A further impact on customer revenues is expected to occur when the CTC has been
fully collected, which is currently expected to occur in 2002 for most major
rate classes; elimination of the CTC will reduce customer rates.
RATE MATTERS
Competition and the Customer Choice Act
Under Pennsylvania ratemaking practice, regulated electric utilities were
granted exclusive geographic franchises to sell electricity, in exchange for
making investments and incurring obligations to serve customers under the then-
existing regulatory framework. Through the ratemaking process, those prudently
incurred costs were recovered from customers, along with a return on the
investment. Additionally, certain operating costs were approved for deferral
for future recovery from customers (regulatory assets). As a result of this
process, utilities had assets recorded on their balance sheets at above-market
costs, thus creating transition costs.
The Pennsylvania Electricity Generation Customer Choice and Competition Act
(Customer Choice Act) enables Pennsylvania's electric utility customers to
purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). All customers now have customer choice. As of
July 31, 2000, approximately 26.9 percent of our customers had chosen
alternative generation suppliers, representing approximately 12.5 percent of our
non-coincident peak load. The remaining customers are provided with electricity
through our provider of last resort service agreement with Orion (discussed
below). Customers pay their electricity generation supplier for generation
charges, and pay us the CTC and charges for transmission and distribution.
Electricity delivery (including transmission, distribution and customer service)
remains regulated in substantially the same manner as under historical
regulation.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, was
originally imposed on the transmission and distribution charges of Pennsylvania
electric utility companies under the Customer Choice Act. As part of a
settlement regarding recovery of deferred fuel costs, we previously agreed to
extend this rate cap for an additional six months through the end of 2001.
However, if our amended provider of last resort arrangement is approved, the
rate cap will be extended through 2003, with a possible further extension
through 2004. (See "Provider of Last Resort" discussion below.)
Provider of Last Resort
We are required not only to deliver electricity, but also to serve as the
provider of last resort for all customers in our service territory. Although no
longer a generation supplier, as the provider of last resort, we must provide
electricity for any customer who cannot or does not choose an alternative
electric generation supplier, or whose supplier fails to deliver. While
collecting the CTC, we may charge only PUC-approved rates for the supply of
electricity as the provider of last resort. As part of the generation asset
sale, Orion agreed to supply us, under a provider of last resort service
agreement, with all of the electric energy necessary to satisfy our provider of
last resort obligations during the CTC collection period. This agreement, which
expires upon our final collection of the CTC, in general effectively transfers
to Orion the financial risks and rewards associated with our provider of last
resort obligations. While we retain the collection risk for the electricity
sales, a component of our regulated delivery rates is designed to cover the cost
of a normal level of uncollectible accounts. In April 2000, we entered into an
agreement with Orion that, as amended in June 2000 and subject to PUC and other
approvals, would extend this provider of last resort arrangement beyond the
final CTC collection through 2004. We anticipate a determination by the PUC
later this year.
Generation Asset Sale
On April 28, 2000, we completed the sale of our generation assets to Orion.
Orion purchased our wholly owned Cheswick, Elrama, Phillips and Brunot Island
power stations, as well as the stations received from FirstEnergy Corp. in the
December 3, 1999 power station exchange, for approximately $1.7 billion.
In its May 29, 1998, final restructuring order, the PUC determined that we
should recover most of the above-market costs of our generation assets,
including plant and regulatory assets, through the collection of the CTC from
electric utility customers. Originally, transition costs were to be recovered
over a seven-year period ending in 2005. As we have regularly stated in our
reports, however, by applying the net proceeds of the generation asset sale to
reduce transition costs, we anticipated early termination of the CTC collection
period in 2001. However, on August 4, 2000, we submitted our final sale-related
filing to the PUC, seeking approval for the accounting treatment of the asset
sale proceeds. Pursuant to this filing, we now anticipate early termination of
the CTC collection period in the first quarter of 2002 for most major rate
classes. In addition, the transition costs, as reflected on the consolidated
balance sheet, are being amortized over the same period that the CTC revenues
are being recognized. The unrecovered balance of transition costs that remain
following the generation asset sale, previously anticipated to be approximately
$2.1 billion ($1.5 billion net of tax), was approximately $550 million ($330
million net of tax) at June 30, 2000. We are allowed to earn an 11 percent pre-
tax return on this net
14
<PAGE>
amount, which remains subject to PUC review. We cannot predict the ultimate
outcome of the PUC's determinations regarding our filing, the accounting
treatment sought, or the balance of transition costs.
Termination of the AYE Merger
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement with Allegheny Energy, Inc. (AYE). AYE filed suit in the United States
District Court for the Western District of Pennsylvania, seeking to compel DQE
to proceed with the merger, or in the alternative seeking an unspecified amount
of money damages. After holding a trial from October 20 through 28, 1999, the
District Court ruled on December 3, 1999, that DQE had properly terminated the
merger agreement without breach, and granted judgment in DQE's favor on all
claims and all requests for injunctive relief. On December 14, 1999, AYE
appealed this ruling to the Third Circuit. On May 17, 2000, the Third Circuit
unanimously affirmed the District Court ruling. In early June 2000, AYE
announced it would not pursue further appeals in this matter.
Item 3. Quantitative and Qualitative Disclosures
About Market Risk.
Market risk represents the risk of financial loss that may impact our
consolidated financial position, results of operations or cash flows due to
adverse changes in market prices and rates.
We manage our interest rate risk by balancing our exposure between fixed and
variable rates while attempting to minimize our interest costs. Currently, our
variable interest rate debt is approximately 40 percent of long-term borrowings.
This variable rate debt is low-cost, tax-exempt debt. We also manage our
interest rate risk by retiring and issuing debt from time to time and by
maintaining a balance of short-term, medium-term and long-term debt. A 10
percent increase in interest rates would have affected our variable rate debt
obligations by increasing interest expense by approximately $0.8 million for the
six months ended June 30, 2000 and 1999. A 10 percent reduction in interest
rates would have increased the market value of our fixed rate debt by
approximately $11.8 million and $13.3 million as of June 30, 2000 and June 30,
1999. Such changes would not have had a significant near-term effect on our
future earnings or cash flows.
---------------------
Except for historical information contained herein, the matters discussed in
this report are forward-looking statements that involve risks and uncertainties
including, but not limited to: economic, competitive, regulatory, governmental
and technological factors affecting operations, markets, products, services and
prices; and other risks discussed in our filings with the SEC.
15
<PAGE>
PART II. OTHER INFORMATION.
Item 1. Legal Proceedings.
On October 5, 1998, DQE announced the unilateral termination of the merger
agreement with Allegheny Energy, Inc. (AYE). DQE believes that AYE suffered a
material adverse effect as a result of the PUC's final restructuring order
regarding AYE's utility subsidiary, West Penn Power Company. AYE filed suit in
the United States District Court for the Western District of Pennsylvania,
seeking to compel DQE to proceed with the merger, or in the alternative seeking
an unspecified amount of money damages. On October 28, 1998, the judge ruled in
DQE's favor regarding termination of the merger agreement. AYE appealed to the
United States Court of Appeals for the Third Circuit, who on March 11, 1999,
remanded the case to the District Court for further proceedings. Trial was held
from October 20 through 28, 1999. On December 3, 1999, the District Court ruled
that DQE had properly terminated the merger agreement without breach, and
granted judgment in its favor on all claims and all requests for injunctive
relief. On December 14, 1999, AYE appealed this decision to the Third Circuit,
who, on May 17, 2000, unanimously affirmed the District Court's ruling. In early
June 2000, AYE announced it would not pursue further appeals in this matter.
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits:
EXHIBIT 12.1 - Calculation of Ratio of Earnings to Fixed Charges and
Preferred and Preference Stock Dividend Requirements.
EXHIBIT 27.1 - Financial Data Schedule
b. A report on Form 8-K was filed May 23, 2000, to report the Third Circuit's
decision on the AYE merger litigation. No financial statements were filed
with this report.
A report on Form 8-K was filed June 14, 2000, to discuss a presentation made
by DQE officers to the Wall Street Utility Group on that date. No financial
statements were filed with this report.
-----------------------------
16
<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 14, 2000 /s/ Frosina C. Cordisco
--------------------- ----------------------------
(Signature)
Frosina C. Cordisco
Treasurer
Date August 14, 2000 /s/ James E. Wilson
--------------------- ----------------------------
(Signature)
James E. Wilson
Vice President and Chief Accounting Officer
17
