<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 September 30, 2000
------------------
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From ____________ to ____________
Commission File Number
----------------------
1-956
Duquesne Light Company
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-0451600
------------ ----------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
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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 October 31, 2000.
<PAGE>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
Duquesne Light Condensed Statement of Consolidated Income (Unaudited)
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<TABLE>
<CAPTION>
(Thousands of Dollars)
----------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------------------------
2000 1999 2000 1999
-----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Revenues:
Sales of Electricity:
Customer revenues $ 290,361 $ 296,043 $ 788,311 $ 790,410
Utilities 4,503 27,283 26,403 56,414
-----------------------------------------------------------------------------------------------------------------------------
Total Sales of Electricity 294,864 323,326 814,714 846,824
Other 9,932 12,839 31,821 45,328
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Total Operating Revenues 304,796 336,165 846,535 892,152
-----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel and purchased power 120,983 84,341 264,319 180,921
Other operating 34,726 65,373 117,278 187,363
Maintenance 8,204 18,425 44,578 62,196
Depreciation and amortization 90,151 60,779 227,954 160,677
Taxes other than income taxes 16,554 23,830 57,722 68,068
Income taxes 4,631 18,181 21,841 53,432
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Total Operating Expenses 275,249 270,929 733,692 712,657
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Operating Income 29,547 65,236 112,843 179,495
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Other Income and Deductions 2,308 4,465 13,898 18,085
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Income Before Interest and Other Charges 31,855 69,701 126,741 197,580
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Interest Charges 16,934 29,520 57,571 86,674
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Monthly Income Preferred Securities Dividend
Requirements 3,141 3,141 9,422 9,422
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Net Income 11,780 37,040 59,748 101,484
=============================================================================================================================
Dividends on Preferred and Preference Stock 844 1,036 2,570 3,016
Earnings for Common Stock $ 10,936 $ 36,004 $ 57,178 $ 98,468
=============================================================================================================================
</TABLE>
See notes to condensed consolidated financial statements.
2
<PAGE>
Duquesne Light Condensed Consolidated Balance Sheet (Unaudited)
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<TABLE>
<CAPTION>
(Thousands of Dollars)
-------------------------------
September 30, December 31,
ASSETS 2000 1999
------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Property, Plant and Equipment:
Gross property, plant and equipment $ 1,936,764 $ 3,959,236
Less: Accumulated depreciation and amortization (610,878) (2,500,719)
------------------------------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment - Net 1,325,886 1,458,517
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Long-Term Investments 59,384 80,891
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Current Assets:
Cash and temporary cash investments 96,981 16,068
Receivables 396,378 131,647
Other current assets 105,222 111,134
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Total Current Assets 598,581 258,849
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Other Non-Current Assets:
Transition costs 478,301 2,008,171
Regulatory assets 243,843 224,002
Divestiture costs -- 218,653
Other 15,059 32,329
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Total Other Non-Current Assets 737,203 2,483,155
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Total Assets $ 2,721,054 $ 4,281,412
==============================================================================================================================
CAPITALIZATION AND LIABILITIES
------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Common stock (authorized - 90,000,000 shares, issued and outstanding - 10 shares) $ -- $ --
Capital surplus 483,327 746,051
Retained earnings 31,109 39,931
Accumulated other comprehensive income 14,713 12,692
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Total Common Stockholder's Equity 529,149 798,674
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Preferred and Preference Stock 222,627 229,512
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Long-term debt 1,060,773 1,410,754
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Total Capitalization 1,812,549 2,438,940
Obligations Under Capital Leases 10,524 16,534
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Current Liabilities:
Notes payable and current debt maturities 796 536,353
Other current liabilities 209,847 225,333
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Total Current Liabilities 210,643 761,686
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Non-Current Liabilities:
Deferred income taxes - net 497,035 782,885
Deferred income -- 93,246
Other non-current liabilities 190,303 188,121
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Total Non-Current Liabilities 687,338 1,064,252
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Commitments and Contingencies (Note D)
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Total Capitalization and Liabilities $ 2,721,054 $ 4,281,412
==============================================================================================================================
</TABLE>
See notes to condensed consolidated financial statements.
3
<PAGE>
Duquesne Light Condensed Statement of Consolidated Cash Flows (Unaudited)
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<TABLE>
<CAPTION>
(Thousands of Dollars)
---------------------------------
Nine Months Ended September 30,
---------------------------------
2000 1999
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Cash Flows From Operating Activities:
Operations $ 189,067 $ 217,219
Changes in working capital other than cash (36,145) 17,073
Other (37,982) (1,115)
----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided By (Used In) Operating Activities 114,940 233,177
----------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Proceeds from sale of generation assets, net of federal income tax payment of $157,424 1,547,576 --
Proceeds from sale of inventory 21,144 --
Divestiture costs (78,752) --
Capital expenditures (63,936) (57,954)
Acquisitions (32,000) --
Long-term investments -- (4,022)
Other (17,504) (20,873)
----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided By (Used In) Investing Activities 1,376,528 (82,849)
----------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Reductions of long-term obligations-net (749,326) (70,946)
Dividends on capital stock (268,571) (179,633)
Loan to affiliate (250,000) --
Redemption of commercial paper (136,594) --
Increase in notes payable -- 66,000
Other (6,064) 608
----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided By (Used In) Financing Activities (1,410,555) (183,971)
----------------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash 80,913 (33,643)
Cash, beginning of period 16,068 53,151
----------------------------------------------------------------------------------------------------------------------------------
Cash, End of Period $ 96,981 $ 19,508
==================================================================================================================================
Non-Cash Investing and Financing Activities:
Capital lease obligations recorded $ -- $ 6,470
Dividend of subsidiary companies' assets $ (61,578) $ --
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
See notes to condensed consolidated financial statements.
4
<PAGE>
Duquesne Light Condensed Statement of Consolidated Comprehensive Income
(Unaudited)
<TABLE>
<CAPTION>
(Thousands of Dollars)
-------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------
2000 1999 2000 1999
-----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Net income $ 11,780 $ 37,040 $ 59,748 $ 101,484
-------------------------------------------------------------------------------------------------------------------------
Other comprehensive income:
Unrealized holding gains (losses) arising during
the period, net of tax of $210, $(725), $1,434 and $(3,445) 296 (1,023) 2,021 (4,857)
-------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 12,076 $ 36,017 $ 61,769 $ 96,627
=========================================================================================================================
</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. We are engaged in the transmission and
distribution of electric energy. 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.
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 nine months ended September 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
Pennsylvania Public Utility Commission (PUC) and the Federal Energy Regulatory
Commission (FERC) with respect to rates for interstate sales, transmission of
electric power, accounting and other matters.
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
5
<PAGE>
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
October 31, 2000, approximately 31.4 percent of our customers had chosen
alternative generation suppliers, representing approximately 35.5 percent of our
non-coincident peak load. The remaining customers are provided with electricity
through our provider of last resort services agreement with Orion Power MidWest,
L.P. (discussed below). Customers pay for generation charges as provided by
their electricity generation supplier, 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.
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 (and the rates for the supply of electricity) beyond the
final CTC collection through 2004. We filed our extension plan on June 30, 2000.
Since October 2000, we have participated in collaborative meetings with the PUC
and various stakeholders concerning provider of last resort issues. We
anticipate the PUC's determination in November.
Transmission and Distribution 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. If
the amended provider of last resort arrangement described above is approved,
this rate cap will be extended through at least 2003. In addition, we will have
the option to further extend this cap through 2004.
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 originally anticipated early termination of the CTC
collection period in 2001.
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 $480 million ($290 million
net of tax) at September 30, 2000. We are allowed to earn an 11 percent pre-tax
return on this net amount, which remains subject to PUC review. We have received
and responded to comments on this filing, and anticipate a final determination
regarding our filing, the accounting treatment sought and the balance of
transition costs by the end of 2000.
6
<PAGE>
C. RECEIVABLES
The components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
(Thousands of Dollars)
---------------------------------------
Sept. 30, Sept. 30, December 31,
2000 1999 1999
--------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customers $ 116,581 $ 97,005 $ 82,314
Other utility 8,741 27,733 32,582
Loan to DQE 250,000 -- --
Other 31,772 21,764 25,481
(Allowance for uncollectible accounts) (10,716) (9,520) (8,730)
--------------------------------------------------------------------------------
Receivables - net 396,378 136,982 131,647
Less: Receivables sold -- (50,000) --
--------------------------------------------------------------------------------
Total $ 396,378 $ 86,982 $ 131,647
--------------------------------------------------------------------------------
</TABLE>
We have an agreement with an unaffiliated corporation that entitles us to
sell, and the corporation to purchase, accounts receivable on an ongoing basis.
We expect to terminate the agreement in the fourth quarter of 2000.
D. COMMITMENTS AND CONTINGENCIES
We estimate that in 2000 we will spend, excluding the allowance for funds used
during construction, approximately $90 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
<PAGE>
Business Segments for the Three Months Ended,
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Millions of Dollars)
-----------------------------------------------------------------------
Electricity Electricity Eliminations/ Consoli-
Delivery Supply CTC All Other dated
-----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
September 30, 2000
--------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 89.3 $ 126.6 $ 88.9 $ -- $ 304.8
Operating expenses 53.1 126.6 7.4 (1.9) 185.2
Depreciation and amortization expense 13.4 -- 76.1 0.6 90.1
---------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 22.8 -- 5.4 1.3 29.5
Other income 3.8 -- -- (1.5) 2.3
Interest and other charges 19.6 -- 1.3 -- 20.9
---------------------------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ 7.0 $ -- $ 4.1 $ (0.2) $ 10.9
=================================================================================================================================
Assets $ 2,181.0 $ -- $ 478.3 $ 61.7 $ 2,721.0
=================================================================================================================================
Capital expenditures $ 25.7 $ -- $ -- $ -- $ 25.7
=================================================================================================================================
<CAPTION>
(Millions of Dollars)
-----------------------------------------------------------------------
Electricity Electricity Eliminations/ Consoli-
Delivery Supply CTC All Other dated
-----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
September 30, 1999
---------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 95.8 $ 129.7 $ 107.8 $ 2.8 $ 336.1
Operating expenses 53.4 125.6 23.4 7.7 210.1
Depreciation and amortization expense 7.7 2.2 46.1 4.8 60.8
---------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 34.7 1.9 38.3 (9.7) 65.2
Other income (1.7) (1.7) -- 7.9 4.5
Interest and other charges 9.1 11.8 11.9 0.9 33.7
---------------------------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ 23.9 $ (11.6) $ 26.4 $ (2.7) $ 36.0
=================================================================================================================================
Assets (1) $ 1,535.4 $ 425.7 $ 2,226.8 $ 93.5 $ 4,281.4
=================================================================================================================================
Capital expenditures $ 10.4 $ 6.8 $ -- $ -- $ 17.2
=================================================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1999.
8
<PAGE>
Business Segments for the Nine Months Ended,
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Millions of Dollars)
-----------------------------------------------------------------------
Electricity Electricity Eliminations/ Consoli-
Delivery Supply CTC All Other dated
-----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
September 30, 2000
---------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 262.1 $ 307.0 $ 277.1 $ 0.3 $ 846.5
Operating expenses 150.9 318.3 39.9 (3.4) 505.7
Depreciation and amortization expense 36.6 5.2 183.8 2.4 228.0
---------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 74.6 (16.5) 53.4 1.3 112.8
Other income 12.1 1.6 -- 0.2 13.9
Interest and other charges 49.2 5.5 14.7 0.1 69.5
---------------------------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ 37.5 $ (20.4) $ 38.7 $ 1.4 $ 57.2
=================================================================================================================================
Assets $ 2,181.0 $ -- $ 478.3 $ 61.7 $ 2,721.0
=================================================================================================================================
Capital expenditures $ 59.2 $ 4.7 $ -- $ -- $ 63.9
=================================================================================================================================
<CAPTION>
(Millions of Dollars)
-----------------------------------------------------------------------
Electricity Electricity Eliminations/ Consoli-
Delivery Supply CTC All Other dated
-----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
September 30, 1999
---------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 259.3 $ 339.1 $ 290.3 $ 3.5 $ 892.2
Operating expenses 145.7 326.1 71.2 9.0 552.0
Depreciation and amortization expense 42.6 12.1 101.1 4.9 160.7
---------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 71.0 0.9 118.0 (10.4) 179.5
Other income -- 2.2 -- 15.9 18.1
Interest and other charges 27.2 35.2 35.6 1.1 99.1
---------------------------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ 43.8 $ (32.1) $ 82.4 $ 4.4 $ 98.5
=================================================================================================================================
Assets (1) $ 1,535.4 $ 425.7 $ 2,226.8 $ 93.5 $ 4,281.4
=================================================================================================================================
Capital expenditures $ 39.1 $ 18.9 $ -- $ -- $ 58.0
=================================================================================================================================
</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. We are engaged in the transmission and
distribution of electric energy. 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.
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
Pennsylvania Public Utility Commission (PUC) and the Federal Energy Regulatory
Commission (FERC) with respect to rates for interstate sales, transmission of
electric power, accounting and other matters.
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. In a filing made October 16, 2000, we informed the FERC that we plan to
join a regional transmission organization at the earliest practicable date, and
are currently exploring our options. We anticipate making a final decision by
the end of 2001.
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 September 30, 2000 and September 30, 1999.
Our earnings available for common stock were $10.9 million in the third quarter
of 2000 compared to $36.0 million in the third quarter of 1999, a decrease of
69.7 percent.
The lower earnings level for the third quarter can be attributed to a decrease
in sales to electric customers caused by milder weather in 2000, lower CTC
revenues due to the collection of transition costs with the generation asset
sale, and accelerated amortization of the remaining transition costs.
Comparison of Nine Months Ended September 30, 2000 and September 30, 1999. Our
earnings available for common stock were $57.2 million in the first nine months
of 2000 compared to $98.5 million in the first nine months of 1999, a decrease
of 41.9 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
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 busi-
10
<PAGE>
ness 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 September 30, 2000 and September 30, 1999.
The electricity delivery business segment contributed $7.0 million to net
income in the third quarter of 2000 compared to $23.9 million in the third
quarter of 1999, a decrease of $16.9 million or 70.7 percent.
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 decreased by $6.5 million or 6.8 percent compared to the
third quarter of 1999. This decrease is due to lower sales to electric utility
customers of 3.6 percent in the third quarter of 2000. The lower sales can be
attributed to lower sales to residential customers due to milder weather in
2000. The following table sets forth kilowatt-hours (KWH) delivered to electric
utility customers.
<TABLE>
<CAPTION>
----------------------------------------------------
KWH Delivered
---------------------------
(In Millions)
---------------------------
Third Quarter 2000 1999 Change
----------------------------------------------------
<S> <C> <C> <C>
Residential 988.4 1,104.5 (10.5)%
Commercial 1,697.8 1,720.8 (1.3)%
Industrial 898.8 893.3 0.6 %
------------------------------------------
Sales to Electric
Utility Customers 3,585.0 3,718.6 (3.6)%
====================================================
</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 decreased by $0.3
million or 0.6 percent from the third quarter of 1999. The relative consistency
between periods can be attributed to a higher level of overhead expenses being
allocated to the electricity delivery business segment due to the generation
asset sale.
Other income was $3.8 million for the third quarter of 2000 compared to $(1.7)
million in the third quarter of 1999, an increase of $5.5 million. The increase
in other income can be attributed to interest on a loan to DQE, as well as a
higher level of other income being allocated to this segment as a result of the
generation asset sale. 1999 includes an adjustment to other income for income
taxes.
Interest and other charges include interest on debt, other interest and
preferred stock dividends of Duquesne Light. In the third quarter of 2000, there
was $10.5 million more interest and other charges allocated to the electricity
delivery business segment compared to the third quarter of 1999. Although we
utilized auction proceeds to retire debt, and thus reduced our overall level of
interest expense, all remaining financing costs after recapitalization are now
borne by the electricity delivery business segment.
Comparison of Nine Months Ended September 30, 2000 and September 30, 1999. The
electricity delivery business segment contributed $37.5 million to net income in
the first nine months of 2000 compared to $43.8 million in the first nine months
of 1999, a decrease of $6.3 million or 14.4 percent.
Operating revenues increased by $2.8 million or 1.1 percent compared to the
first nine months of 1999 due to an increase of 0.6 percent in sales to electric
utility customers. The increase is primarily attributable to increased
consumption by steel manufacturers, offset by lower residential sales due to
milder weather conditions in 2000. The following table sets forth KWH delivered
to electric utility customers.
<TABLE>
<CAPTION>
----------------------------------------------------
KWH Delivered
----------------------------
(In Millions)
----------------------------
First Nine Months 2000 1999 Change
<S> <C> <C> <C>
----------------------------------------------------
Residential 2,664.9 2,772.9 (3.9)%
Commercial 4,675.0 4,618.5 1.2 %
Industrial 2,733.1 2,617.1 4.4 %
-------------------------------------------
Sales to Electric
Utility Customers 10,073.0 10,008.5 0.6 %
====================================================
</TABLE>
Operating expenses were $5.2 million or 3.6 percent higher than in the first
nine months of 1999, primarily due to the allocation of more overhead expenses
to the electricity delivery business segment as a result of the generation asset
sale.
Other income was $12.1 million higher than in the first nine months of 1999.
The increase was due to the following items: (1) the interest income on the loan
to DQE, (2) increased interest income, a result of more cash due to the
generation asset sale, and (3) a higher level of other income being allocated to
the electricity delivery business segment in 2000 because of the generation
asset sale.
Interest and other charges include interest on debt, other interest and
preferred stock dividends of Duquesne Light. In the first nine months of 2000,
there was $22.0 million or 80.9 percent more interest and other charges
allocated to the electricity delivery business segment compared to the first
nine months of 1999. Although we utilized auction pro-
11
<PAGE>
ceeds to retire debt and thus reduced our overall level of interest expense,
all remaining financing costs after recapitalization are now borne by the
electricity delivery business segment.
Electricity Supply and CTC Business Segments.
Comparison of Three Months Ended September 30, 2000 and September 30, 1999. In
the third quarter of 2000, the electricity supply and CTC business segments
reported net income of $4.1 million compared to $14.8 million in the third
quarter of 1999, a decrease of $10.7 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 decreased by $22.0 million or 9.3 percent from the third
quarter of 1999. The decrease is due to two factors: (1) 18.4 percent lower KWH
supplied primarily due to lower sales to other utilities following our
generation asset sale; and (2) a lower CTC revenue rate per KWH compared to
1999. In accordance with the PUC restructuring order, our annual transition cost
recovery rate decreases proportionally with the increasing customer shopping
credit. The following table sets forth KWH supplied for customers who have not
chosen an alternative generation supplier.
<TABLE>
<CAPTION>
------------------------------------------------------
KWH Supplied
--------------------------
(In Millions)
--------------------------
Third Quarter 2000 1999 Change
------------------------------------------------------
<S> <C> <C> <C>
Residential 639.2 911.9 (29.9)%
Commercial 1,604.6 1,241.7 29.2 %
Industrial 881.0 866.9 1.6 %
---------------------------------------------
Sales to Electric
Utility Customers 3,124.8 3,020.5 3.5 %
---------------------------------------------
Sales to Other Utilities 88.5 919.1 (90.4)%
---------------------------------------------
Total Sales 3,213.3 3,939.6 (18.4)%
======================================================
</TABLE>
Operating expenses for the electricity supply business segment are primarily
made up of energy costs; costs to operate and maintain the power stations; 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.
Operating expenses decreased $15.0 million or 10.1 percent from the third
quarter of 1999, as a result of the generation asset sale. The decrease was
partially offset by the higher cost of purchased power related to the provider
of last resort supply agreement with Orion Power MidWest, L.P. (See "Provider of
Last Resort" discussion on page 14.) The cost under the provider of last resort
agreement, 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 third quarter of 1999, depreciation of generation assets.
There was an increase of $27.8 million or 57.6 percent compared to the third
quarter of 1999. This increase was due to a higher level of transition cost
amortization in the third quarter of 2000.
Interest and other charges include interest on debt, other interest and
preferred stock dividends. In the third quarter of 2000 there was a $22.4
million decrease in interest and other charges compared to the third quarter of
1999. The decrease reflects the retirement of debt with auction proceeds and
less interest expense allocated to these segments due to the generation asset
sale.
Comparison of Nine Months Ended September 30, 2000 and September 30, 1999. In
the first nine months of 2000, the electricity supply and CTC business segments
reported net income of $18.3 million compared to $50.3 million in the first nine
months of 1999, a decrease of $32.0 million or 63.6 percent.
Operating revenues decreased by $45.3 million or 7.2 percent compared to the
first nine months of 1999. The decrease in revenues resulted from a 62.7 percent
decrease in energy supplied to other utilities in the first nine months of 2000
compared to the first nine months of 1999, as well as a decrease in the
transition cost recovery rate set forth by the PUC. The following table sets
forth KWH supplied for customers who have not chosen an alternative generation
supplier.
<TABLE>
<CAPTION>
-------------------------------------------------------
KWH Supplied
---------------------------
(In Millions)
---------------------------
First Nine Months 2000 1999 Change
-------------------------------------------------------
<S> <C> <C> <C>
Residential 1,861.3 2,368.6 (21.4)%
Commercial 3,485.9 3,381.1 3.1 %
Industrial 2,552.1 2,527.0 1.0 %
----------------------------------------------
Sales to Electric
Utility Customers 7,899.3 8,276.7 (4.6)%
----------------------------------------------
Sales to Other Utilities 883.9 2,369.6 (62.7)%
----------------------------------------------
Total Sales 8,783.2 10,646.3 (17.5)%
=======================================================
</TABLE>
12
<PAGE>
Operating expenses decreased $39.1 million or 9.8 percent from the first nine
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, following the generation asset sale, from the
higher rate per KWH due to the customer shopping credit.
There was an increase of $75.8 million or 67.0 percent in depreciation and
amortization expense compared to the first nine months of 1999. This increase
was due to a higher level of transition cost amortization in the first nine
months of 2000.
In the first nine months of 2000 there was a $50.6 million or 71.5 percent
decrease in interest and other charges compared to the first nine months of
1999. The decrease reflects a lower level of interest expense from the
retirement of debt with generation asset sale proceeds, and less interest
expense allocated to these segments in 2000 due to the sale.
All Other.
Comparison of Three Months Ended September 30, 2000 and September 30, 1999.
The all other category had a net loss of $0.2 million in the third quarter of
2000 compared to a net loss of $2.7 million in the third quarter of 1999. The
lower income in 2000 is primarily due to the dividend of certain investments
in April 2000 to our parent company, DQE, and the sale of affordable housing
investments during 1999.
Comparison of Nine Months Ended September 30, 2000 and September 30, 1999. The
all other category contributed $1.4 million to earnings available for common
stock in the first nine months of 2000 compared to $4.4 million in the first
nine months of 1999, a decrease of $3.0 million. The decrease can be attributed
to the dividend of certain investments in April 2000 to DQE.
LIQUIDITY AND CAPITAL RESOURCES
Capital Expenditures
We estimate that during 2000 we will spend, excluding the allowance for funds
used during construction, approximately $90 million for electric utility
construction, including $5 million for generation. During the first nine months
of 2000, we have spent approximately $63.9 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 DQE. The loan is in the form
of a demand note bearing 8 percent annual interest payable monthly.
Financing
At September 30, 2000, we had $0.8 million of current debt maturities. There
were no bank loans or commercial paper borrowings during the quarter.
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 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
2001. 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 September 30, 2000, no
borrowings were outstanding.
We have an agreement with an unaffiliated corporation that entitles us to
sell, and the corporation to purchase, accounts receivable on an ongoing basis.
At various times during the first nine months of 2000, we had sold receivables
under the facility. No amounts were outstanding at September 30, 2000. At
September 30, 1999 we had sold $50 million of receivables. We expect to
terminate the agreement in the fourth quarter of 2000.
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 to our provider of last resort service agreement),
which has affected our cash flows. Customer revenues include revenues from
provider of last resort customers. Although we collect these revenues, we pass
them on (net of gross receipts tax) to Orion. In addition, 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 bills.
13
<PAGE>
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
October 31, 2000, approximately 31.4 percent of our customers had chosen
alternative generation suppliers, representing approximately 35.5 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 for generation charges as provided by their electricity
generation supplier, 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.
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 (and the rates for the supply of electricity) beyond
the final CTC collection through 2004. We filed our extension plan on June 30,
2000. Since October 2000, we have participated in collaborative meetings with
the PUC and various stakeholders concerning provider of last resort issues. We
anticipate the PUC's determination in November.
Transmission and Distribution 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. If
the amended provider of last resort arrangement described above is approved,
this rate cap will be extended through at least 2003. In addition, we will have
the option to further extend this cap through 2004.
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 originally anticipated early termination of the CTC
collection period in 2001.
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 $480 million ($290 million
net of tax) at September 30, 2000. We are allowed to earn an 11 percent pre-tax
return on this net amount, which remains subject to PUC review. We have received
and responded to comments on this filing, and anticipate a final determination
regarding our filing, the accounting treatment sought and the balance of
transition costs by the end of 2000.
14
<PAGE>
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 $1.9 million and
$1.0 million for the nine months ended September 30, 2000 and September 30,
1999. A 10 percent reduction in interest rates would have increased the market
value of our fixed rate debt by approximately $42.9 million and $73.0 million as
of September 30, 2000 and December 31, 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: changing weather conditions; demand for electric
utility services; and economic, competitive, regulatory, governmental and
technological factors affecting operations, markets, products, services and
prices.
PART II. OTHER INFORMATION.
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. On November 9, 2000, we furnished a Report on Form 8-K to provide disclosure
under Regulation FD regarding a presentation to the investment community.
No financial statements were included.
_____________________________
15
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
Duquesne Light Company
-------------------------------------------
(Registrant)
Date November 14, 2000 /s/ Frosina C. Cordisco
----------------------- -------------------------------------------
(Signature)
Frosina C. Cordisco
Treasurer
Date November 14, 2000 /s/ James E. Wilson
----------------------- -------------------------------------------
(Signature)
James E. Wilson
Vice President and Chief Accounting Officer
16
