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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, 2002
-------------
[_] 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
----------------------
l-10290
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:
All 10 shares of Duquesne Light Company Common Stock outstanding as of July 31,
2002 are owned by DQE, Inc.
PART I. FINANCIAL INFORMATION
Item I. Financial Statements.
Duquesne Light Condensed Consolidated Statements of Income (Unaudited)
- --------------------------------------------------------------------------------
(Millions of Dollars)
---------------------------------------------
Three Months Six Months
Ended June 30, Ended June 30,
---------------------------------------------
2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------
Operating Revenues:
Sales of Electricity:
Customer revenues $ 226.7 $ 255.9 $ 470.9 $ 492.4
Utilities l.9 3.0 3.3 7.1
- -------------------------------------------------------------------------------------------------------
Total Sales of Electricity 228.6 258.9 474.2 499.5
Other 4.4 4.5 8.2 9.3
- -------------------------------------------------------------------------------------------------------
Total Operating Revenues 233.0 263.4 482.4 508.8
- -------------------------------------------------------------------------------------------------------
Operating Expenses:
Purchased power 104.0 104.1 202.9 197.6
Other operating 23.0 26.1 43.l 54.5
Maintenance 8.3 6.2 13.7 11.7
Depreciation and amortization 44.9 80.0 119.2 159.1
Taxes other than income taxes 16.8 13.8 32.7 27.2
Income taxes 6.0 5.6 12.6 7.9
- -------------------------------------------------------------------------------------------------------
Total Operating Expenses 203.0 235.8 424.2 458.0
- -------------------------------------------------------------------------------------------------------
Operating Income 30.0 27.6 58.2 50.8
- -------------------------------------------------------------------------------------------------------
Other Income and Deductions - net 4.3 7.1 11.9 13.2
- -------------------------------------------------------------------------------------------------------
Income Before Interest and Other Charges 34.3 34.7 70.1 64.0
- -------------------------------------------------------------------------------------------------------
Interest Charges 16.1 16.1 31.0 32.4
Monthly Income Preferred Securities Dividend Requirements 3.2 3.2 6.3 6.3
- -------------------------------------------------------------------------------------------------------
Net Income 15.0 15.4 32.8 25.3
- -------------------------------------------------------------------------------------------------------
Dividends on Preferred and Preference Stock 0.8 0.8 1.6 1.7
- -------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 14.2 $ 14.6 $ 31.2 $ 23.6
=======================================================================================================
See notes to condensed consolidated financial statements.
2
Duquesne Light Condensed Consolidated Balance Sheets (Unaudited)
- --------------------------------------------------------------------------------
(Millions of Dollars)
-------------------------
June 30, December 31,
ASSETS 2002 2001
- --------------------------------------------------------------------------------
Property, Plant and Equipment:
Gross property, plant equipment $2,004.0 $1,972.3
Less: Accumulated depreciation and amortization (651.1) (627.4)
- --------------------------------------------------------------------------------
Total Property, Plant and Equipment-Net 1,352.9 1,344.9
- --------------------------------------------------------------------------------
Long-Term Investments 22.4 28.9
- --------------------------------------------------------------------------------
Current Assets:
Investment in DQE Capital Cash Pool 413.7 314.8
Receivables 437.4 417.5
Other current assets 47.2 41.4
- --------------------------------------------------------------------------------
Total Current Assets 898.3 773.7
- --------------------------------------------------------------------------------
Other Non-Current Assets:
Transition costs 45.7 134.3
Regulatory assets 272.4 267.2
Other 14.8 11.2
- --------------------------------------------------------------------------------
Total Other Non-Current Assets 332.9 412.7
- --------------------------------------------------------------------------------
Total Assets $2,606.5 $2,560.2
- --------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- --------------------------------------------------------------------------------
Capitalization:
Common stock (authorized - 90,000,000 shares,
issued and outstanding - 10 shares) $ - $ -
Capital surplus 483.3 483.3
Retained earnings 46.6 44.3
Accumulated other comprehensive income (4.6) (1.0)
- --------------------------------------------------------------------------------
Total Common stockholders's Equity 525.3 526.6
- --------------------------------------------------------------------------------
Company Obligated Mandatorily Redeemable Preferred
Trust Securities 150.0 150.0
- --------------------------------------------------------------------------------
Preferred and Preference Stock 75.1 74.5
- --------------------------------------------------------------------------------
Long-term debt 1,066.9 1,061.l
- --------------------------------------------------------------------------------
Total Capitalization 1,817.3 1,812.2
- --------------------------------------------------------------------------------
Current Liabilities:
Notes payable and current debt maturities 35.0 -
Other current liabilities 208.3 186.3
- --------------------------------------------------------------------------------
Total Current Liabilities 243.3 186.3
- --------------------------------------------------------------------------------
Non-Current Liabilities:
Deferred income taxes - net 416.1 418.3
Warwick mine liability 31.6 35.0
Other 98.2 108.4
- --------------------------------------------------------------------------------
Total Non-Current Liabilities 545.9 561.7
- --------------------------------------------------------------------------------
Commitments and contingencies (Note F)
- --------------------------------------------------------------------------------
Total Capitalization and Liabilities $2,606.5 $2,560.2
================================================================================
See notes to condensed consolidated financial statements.
3
Duquesne Light Condensed Consolidated Statements of Cash Flows (Unaudited)
- --------------------------------------------------------------------------------
(Millions of Dollars)
-------------------------------
Six Months Ended June 30,
-------------------------------
2002 2001
- ------------------------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Operations $ 139.1 $ 146.1
Changes in working capital other than cash (68.5) (82.8)
Other (5.9) (9.5)
- ------------------------------------------------------------------------------------------------
Net Cash Provided By Operating Activities 64.7 53.8
- ------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Capital expenditures (34.9) (26.5)
Proceeds from sale of investments 2.6 3.9
Other (2.0) (0.9)
- ------------------------------------------------------------------------------------------------
Net Cash Used In Investing Activities (34.3) (23.5)
- ------------------------------------------------------------------------------------------------
Cash flows From Financing Activities:
Issuance of debt (Note E) 300.0 -
Reductions of long-term obligation (Note E) (293.0) (7.6)
Commercial paper borrowings 35.0 -
Loan to DQE (35.0) -
Dividends on capital stock (26.7) (21.7)
Other (10.7) (1.0)
- ------------------------------------------------------------------------------------------------
Net Cash Used In Financing Activities (30.4) (30.3)
- ------------------------------------------------------------------------------------------------
Net increase in cash and temporary cash investments - -
Cash and temporary cash investments at beginning of period - -
- ------------------------------------------------------------------------------------------------
Cash and Temporary Cash Investments at End of Period $ - $ -
================================================================================================
See notes to condensed consolidated financial statements.
Duquesne Light Condensed Consolidated Statements of Comprehensive Income
(Unaudited)
- --------------------------------------------------------------------------------
(Millions of Dollars)
------------------------------------------------
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------------
2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------------------
Net income $ 15.0 $ 15.4 $ 32.8 $ 25.3
Other comprehensive income:
Unrealized holding losses arising during the period,
net of tax of $(3.8), $(3.5), $(2.5) and $(5.4) (5.4) (4.9) (3.6) (7.6)
- -----------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 9.6 $ 10.5 $ 29.2 $ 17.7
=================================================================================================================
See notes to condensed consolidated financial statements.
4
Notes to Condensed Consolidated Financial Statements (Unaudited)
A. CONSOLIDATION AND ACCOUNTING POLICIES
Consolidation
Duquesne Light Company, a wholly owned subsidiary of DQE, Inc., is an
electric utility engaged in the transmission and distribution of electric
energy.
Our subsidiaries are primarily involved in operating our automated meter
reading technology and providing financing to certain affiliates.
The consolidated financial statements include the accounts of Duquesne Light
and our wholly and majority owned subsidiaries. The equity method of accounting
is used when we have a 20 to 50 percent interest in other companies. Under the
equity method, original investments are recorded at cost and adjusted by our
share of undistributed earnings or losses of these companies. All material
intercompany balances and transactions have been eliminated in the
consolidation.
Basis of Accounting
Duquesne Light is subject to the accounting and reporting requirements of the
Securities and Exchange Commission (SEC). Our electricity delivery business is
also subject to regulation by the Pennsylvania Public Utility Commission (PUC)
and the Federal Energy Regulatory Commission (FERC) with respect to rates for
delivery of electric power, accounting and other matters.
As a result of our PUC-approved restructuring plan, 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." Pursuant to the PUC's final restructuring order, and as provided in
the Pennsylvania Electricity Generation Customer Choice and Competition Act
(Customer Choice Act), generation-related transition costs 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 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 Note B.)
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires us to
make estimates and assumptions with respect to values and conditions 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 also may be
affected by the estimates and assumptions we are required to make. We evaluate
these estimates on an ongoing basis, using historical experience, consultation
with experts and other methods we consider reasonable in the particular
circumstances. Nevertheless, actual results may differ significantly from our
estimates.
The interim financial information for the three and six month periods ended
June 30, 2002 is unaudited and has been prepared on the same basis as the
audited financial statements. In the opinion of management, such unaudited
information includes all adjustments (consisting only of normal recurring
adjustments) necessary for a fair presentation of the interim information. This
information does not include all footnotes which would be required for complete
annual financial statements in accordance with accounting principles generally
accepted in the United States of America.
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, 2001
filed with the SEC. The results of operations for the three and six months ended
June 30, 2002, are not necessarily indicative of the results that may be
expected for the full year.
Recent Accounting Pronouncements
On January I, 2002, we adopted SFAS No. 141, "Business Combinations," SFAS
No. 142, "Goodwill and Other Intangible Assets," and SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," the impact of which was
not significant to our financial statements.
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
143, "Accounting for Asset Retirement Obligations," which addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs.
Specifically, this standard requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred, if a reasonable estimate of fair value can be made. The entity is
required to capitalize the cost by increasing the carrying amount of the related
long-lived asset. The capitalized cost is then depreciated over the useful life
of the related asset. Upon settlement of the liability, an entity either settles
the obligation for its recorded amount or incurs a gain or loss. The standard is
effective for fiscal years beginning after June 15, 2002. We are currently
evaluating, but have yet to determine, the impact that the adoption of SFAS No.
143 will have on our financial statements.
Reclassification
The 2001 condensed consolidated financial statements have been reclassified
to conform with the 2002 presentation.
5
B. RATE MATTERS
Competition and the Customer Choice Act
The Customer Choice Act enables electric utility customers to purchase
electricity at market prices from a variety of electric generation suppliers. As
of June 30, 2002, approximately 77.6 percent of our customers measured on a
kilowatt-hour (KWH) basis and approximately 75.6 percent on a non-coincident
peak load basis received electricity through our provider of last resort service
arrangement (discussed below). The remaining customers are provided with
electricity through alternative generation suppliers. The number of customers
participating in our provider of last resort service will fluctuate depending on
market prices and the number of alternative generation suppliers in the retail
supply business.
Customers who select an alternative generation supplier pay for generation
charges set competitively by that supplier, and pay our CTC (discussed below)
and/or transmission and distribution charges. Electricity delivery (including
transmission, distribution and customer service) remains regulated in
substantially the same manner as under historical regulation.
In November 2001, the Pennsylvania Department of Revenue established an
increased revenue neutral reconciliation tax (RNR) in order to recover a current
shortfall that resulted from electricity generation deregulation. Since January
2002, our customer bills have reflected an approximately two percent increase to
recover our costs related to the RNR. (See Note F.)
Regional Transmission Organization
FERC Order No. 2000 calls on transmission-owning utilities such as Duquesne
Light to join regional transmission organizations (RTOs). We are committed to
ensuring a stable, plentiful supply of electricity for our customers. Toward
that end, we planned to join the PJM West RTO. In late 2001 and early 2002, we
entered into agreements with two generation suppliers to provide the electric
capacity required to meet our anticipated capacity credit obligations in PJM
West through 2004.
Our participation in the PJM West RTO was to be conditioned upon PUC approval
of the recovery of the cost of capacity under these agreements, and we
petitioned the PUC for such approval. However, on July 31, 2002, the FERC issued
a series of proposals designed to establish a standard market design and
transmission service for interstate electricity transactions, and extend its
deadline for joining an RTO until September 2004. In light of the FERC's
proposals, the PUC dismissed our petition without prejudice. As a result,
neither of the capacity agreements will take effect. We will continue to
evaluate the FERC's proposals and their impact on the possibility of joining an
RTO.
Competitive Transition Charge
In its 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. Following our application of net generation asset sale proceeds to
reduce transition costs, the CTC was fully collected for most of our residential
customers during the first quarter of 2002 and a large number of our commercial
customers during the second quarter of 2002. As of June 30, 2002, the CTC
balance has been fully collected for approximately 95 percent of our customers,
and 46 percent of the KWH sales for the first six months of 2002. The transition
costs, as reflected on the consolidated balance sheet, are being amortized over
the same period that the CTC revenues are being recognized.
For regulatory purposes, the unrecovered balance of transition costs was
approximately $48.4 million ($29.5 million net of tax) at June 30, 2002, on
which we are allowed to earn an 11 percent pre-tax return. A lower amount is
shown on the balance sheet due to the accounting for unbilled revenues.
Provider of Last Resort
Although no longer a generation supplier, as the provider of last resort for
all customers in our service territory, we must provide electricity for any
customer who does not choose an alternative generation supplier, or whose
supplier fails to deliver. As part of the generation asset sale, a third party
agreed to supply all of the electric energy necessary to satisfy our provider of
last resort obligations during the CTC collection period. We have extended the
arrangement (and the PUC-approved rates for the supply of electricity) beyond
the final CTC collection through December 31, 2004 (POLR II). The agreement also
permits us, following CTC collection for each rate class, an average margin of
0.5 cents per KWH supplied through this arrangement. Except for this margin,
these agreements, in general, effectively transfer to the supplier the financial
risks and rewards associated with our provider of last resort obligations.
While there are certain safeguards in the provider of last resort
arrangements designed to mitigate losses in the event that the supplier defaults
on its performance under the arrangement, we may face the credit risk of such a
default. Contractually, we have various credit enhancements that would become
activated upon certain events. If the supplier were to fail to deliver, we would
have to contract with another supplier and/or make purchases in the market at
the time of default at a time when market prices could be higher. While the
Customer Choice Act provides generally for provider of last resort supply costs
to be borne by customers, recent litigation suggests that
6
it may not be clear whether we could pass any costs in excess of the existing
PUC-approved provider of last resort prices on to our customers. Additionally,
the supplier has recently been downgraded by the rating agencies. Although we
are following the situation closely, our knowledge is limited to public
disclosure, and we do not know whether the downgrade could affect the supplier's
ability to perform. We also retain the risk that customers will not pay for the
provider of last resort generation supply. However, a component of our delivery
rate is designed to cover the cost of a normal level of uncollectible accounts.
Rate Freeze
In connection with POLR II, we negotiated a rate freeze for generation,
transmission and distribution rates. The rate freeze fixes new generation rates
for retail customers who take electricity under the extended provider of last
resort arrangement through 2004, and continues the transmission and distribution
rates for all customers at current levels through at least 2003. Under certain
circumstances, affected interests may file a complaint alleging that, under
these frozen rates, we have exceeded reasonable earnings, in which case the PUC
could make adjustments to rectify such earnings.
C. RECEIVABLES
The components of receivables for the periods indicated are as follows:
- --------------------------------------------------------------------------------
(Millions of Dollars)
---------------------------------------------
June 30, December 31,
2002 2001
- --------------------------------------------------------------------------------
Electric customer
accounts receivable $ 88.9 $ 97.1
Unbilled revenue accrual 39.7 36.6
Other utility receivables 5.4 3.2
Loan to DQE 285.0 250.0
Affiliate receivables 13.5 23.9
Other receivables 12.3 13.0
Less: Allowance for
uncollectible accounts (7.4) (6.3)
- --------------------------------------------------------------------------------
Total Receivables $ 437.4 $ 417.5
================================================================================
D. RESTRUCTURING CHARGES
During the fourth quarter of 2001, we recorded a pre-tax restructuring charge
of $10.8 million. The restructuring plan included the (1) consolidation and
reduction of certain administrative and back-office functions through an
involuntary termination plan; (2) abandonment of certain office facilities to
relocate employees to one centralized location; and (3) write-off of certain
leasehold improvements related to abandoned office facilities. Of the $10.8
million, $8.3 million was for employee termination benefits for approximately
100 management, professional and administrative personnel; $1.5 million was for
future lease payments; and $1.0 million was for other lease costs associated
with the restructuring plan. To date, approximately 90 employees have been
terminated. The restructuring liability at June 30, 2002 was $4.6 million and is
included in "other current liabilities" on the condensed consolidated balance
sheet.
The following table summarizes the current year activity for the accrued
restructuring liability for the period ended June 30, 2002:
- --------------------------------------------------------------------------------
Restructuring Liability
---------------------------------------------
(Millions of Dollars)
---------------------------------------------
Employee
Termination Lease
Benefits costs Total
- --------------------------------------------------------------------------------
Balance at December 31, 2001 $ 6.6 $ 2.2 $ 8.8
2002 payments (4.0) (0.2) (4.2)
- --------------------------------------------------------------------------------
Balance at June 30, 2002 $ 2.6 $ 2.0 $ 4.6
================================================================================
We believe that the remaining provision is adequate to complete the
restructuring plan. We expect the remaining restructuring liabilities to be paid
on a monthly basis throughout 2006.
E. DEBT
On April 15, 2002, we issued $200 million of 6.7 percent first mortgage bonds
due 2012. On April 30, 2002, we issued $100 million of 6.7 percent first
mortgage bonds due 2032. In each case we used the proceeds to call and refund
existing debt, including debt scheduled to mature in 2003 and 2004.
In January 2002, we issued commercial paper and loaned the proceeds to DQE;
this loan is payable on demand. The balance of commercial paper and related loan
to DQE was $35 million as of June 30, 2002.
7
F. COMMITMENTS AND CONTINGENCIES
Construction
We estimate that in 2002 we will spend, excluding the allowance for funds
used during construction, approximately $70 million for electric utility
construction.
Employees
We are a party to a labor contract with the International Brotherhood of
Electrical Workers, which represents the majority of our employees. This
contract expires September 30, 2003.
Legal Proceedings
As discussed elsewhere in this report, we requested and received PUC approval
to recover approximately $13 million of costs we will incur in 2002 due to the
RNR. On November 19, 2001, the Pennsylvania Office of Consumer Advocate (OCA)
filed a complaint with the PUC, objecting to the recovery approval and stating
various matters, such as rate of return and offsetting savings, that should be
considered before allowing RNR recovery in excess of rate caps. An initial
hearing on the OCA's complaint was held May 2, 2002 before a PUC administrative
law judge, who denied the OCA's objections. However, on May 9, 2002, the PUC
ordered that our quarterly earnings may be considered in the RNR proceedings.
Additional hearings were held in July 2002. On August 8, 2002, the PUC voted to
uphold dismissal of the OCA's case. The OCA has until early September 2002 to
appeal.
Although we cannot predict the ultimate outcome of this matter, we believe
the final resolution will not significantly affect our results of operations or
cash flows.
G. SUBSEQUENT EVENTS
In July 2002, we retired our outstanding commercial paper balance of $35
million, using proceeds from the repayment of the loan to DQE. On August 5,
2002, we redeemed the following: (i) $10 million aggregate principal amount of
our 8.20 percent first mortgage bonds due 2022 at a redemption price of 104.51
percent of the principal amount thereof, and (ii) $100 million aggregate
principal amount of our 7 5/8 percent first mortgage bonds due 2023 at a
redemption price of 103.9458 percent of the principal amount thereof. Our
investment in the cash pool was used to retire the first mortgage bonds.
H. BUSINESS SEGMENTS AND RELATED INFORMATION
We report the results of our business segments, determined by products,
services and regulatory environment as follows: (1) transmission and
distribution of electricity (electricity delivery business segment), (2) supply
of electricity (electricity supply business segment), and (3) collection of
transition costs (CTC business segment).
8
Business Segments for the Three Months Ended:
- --------------------------------------------------------------------------------
(Millions of Dollars)
-----------------------------------------------------------------
Electricity Electricity Consoli-
Delivery Supply CTC dated
-----------------------------------------------------------------
June 30, 2002
- ---------------------------------------------------------------------------------------------------------------------
Operating revenues $ 85.5 $ 113.9 $ 33.6 $ 233.0
Operating expenses 31.3 104.0 135.3
Depreciation and amortization expense 14.0 - 30.9 44.9
Income and other tax expense 13.9 7.0 1.9 22.8
- ---------------------------------------------------------------------------------------------------------------------
Operating income 26.3 2.9 0.8 30.0
Other income 4.3 - - 4.3
Interest and other charges 20.1 - - 20.1
- ---------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 10.5 $ 2.9 $ 0.8 $ 14.2
=====================================================================================================================
Assets $ 2,560.8 $ - $ 45.7 $ 2,606.5
=====================================================================================================================
Capital expenditures $ 21.0 $ - $ - $ 21.0
=====================================================================================================================
(Millions of Dollars)
- ---------------------------------------------------------------------------------------------------------------------
Electricity Electricity Consoli-
Delivery Supply CTC dated
-----------------------------------------------------------------
June 30, 2001
- ---------------------------------------------------------------------------------------------------------------------
Operating revenues $ 80.7 $ 108.8 $ 73.9 $ 263.4
Operating expenses 32.3 104.1 - 136.4
Depreciation and amortization expense 14.8 - 65.2 80.0
Income and other tax expense 9.5 4.7 5.2 19.4
- ---------------------------------------------------------------------------------------------------------------------
Operating income 24.1 - 3.5 27.6
Other income 7.1 - - 7.1
Interest and other charges 20.1 - - 20.1
- ---------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 11.1 $ - $ 3.5 $ 14.6
=====================================================================================================================
Assets (a) $ 2,425.9 $ - $ 134.3 $ 2,560.2
=====================================================================================================================
Capital expenditures $ 15.4 $ - $ - $ 15.4
=====================================================================================================================
(a) Relates to assets as of December 31, 2001.
9
Business Segments for the Six Months Ended:
(Millions of Dollars)
--------------------------------------------------------------
Electricity Electricity Consoli-
Delivery Supply CTC dated
--------------------------------------------------------------
June 30, 2002
- ------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 165.7 $ 218.1 $ 98.6 $ 482.4
Operating expenses 56.8 202.9 - 259.7
Depreciation and amortization expense 28.2 - 91.0 119.2
Income and other tax expense 28.0 11.8 5.5 45.3
- ------------------------------------------------------------------------------------------------------------------------
Operating income 52.7 3.4 2.1 58.2
Other income 1l.9 - - 11.9
Interest and other charges 38.9 - - 38.9
- ------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 25.7 $ 3.4 $ 2.1 $ 31.2
========================================================================================================================
Capital expenditures $ 34.9 $ - $ - $ 34.9
========================================================================================================================
(Millions of Dollars)
--------------------------------------------------------------
Electricity Electricity Consoli-
Delivery Supply CTC dated
--------------------------------------------------------------
June 30, 2001
- ------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 154.4 $ 206.4 $ 148.0 $ 508.8
Operating expenses 66.2 197.6 - 263.8
Depreciation and amortization expense 29.6 - 129.5 159.1
Income and other tax expense 15.5 8.8 10.8 35.1
- ------------------------------------------------------------------------------------------------------------------------
Operating income 43.1 - 7.7 50.8
Other income 13.2 - - 13.2
Interest and other charges 40.4 - - 40.4
- ------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 15.9 $ - $ 7.7 $ 23.6
========================================================================================================================
Capital expenditures $ 26.5 $ - $ - $ 26.5
========================================================================================================================
10
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Part I, Item 2 of this Quarterly Report on Form 1O-Q should be read in
conjunction with our Annual Report on Form 1O-K for the year ended December 31,
2001 filed with the Securities and Exchange Commission (SEC), and the condensed
consolidated financial statements, which are set forth in Part 1, Item I of this
Report.
Duquesne Light Company, a wholly owned subsidiary of DQE, Inc., is an
electric utility engaged in the transmission and distribution of electric
energy.
Our subsidiaries are primarily involved in operating our automated meter
reading technology and providing financing to certain affiliates.
Service Area
Our electric utility operations provide service to approximately 586,000
direct customers in southwestern Pennsylvania (including in the City of
Pittsburgh), a territory of approximately 800 square miles.
Regulation
We are subject to the accounting and reporting requirements of the SEC. Our
electric delivery business is also subject to regulation by the Pennsylvania
Public Utility Commission (PUC) and the Federal Energy Regulatory Commission
(FERC) with respect to rates for delivery of electric power, accounting and
other matters.
Business Segments
This information is set forth in "Results of Operations" below and in
"Business Segments and Related Information," Note H to our condensed
consolidated financial statements.
Forward-looking Statements
We use forward-looking statements in this report. Statements that are not
historical facts are forward-looking statements, and are based on beliefs and
assumptions of our management, and on information currently available to
management. Forward-looking statements include statements preceded by, followed
by or using such words as "believe," "expect," "anticipate," "plan," "estimate"
or similar expressions. Such statements speak only as of the date they are made,
and we undertake no obligation to update publicly any of them in light of new
information or future events. Actual results may materially differ from those
implied by forward-looking statements due to known and unknown risks and
uncertainties, some of which are discussed below.
. Demand for and pricing of electric utility services, changing market
conditions and weather conditions could affect earnings levels.
. Earnings will be affected by the number of customers who choose to
receive electric generation through the provider-of-last-resort
arrangement, by final PUC approval of our post-2004 provider of last
resort plan and by the continued performance of our generation
supplier.
. Overall performance could be affected by economic, competitive,
regulatory, governmental (including tax) and technological factors
affecting operations, markets, products, services and prices, as well
as the factors discussed in our SEC filings made to date.
Recent Accounting Pronouncements
In June 2001 the Financial Accounting Standards Board (FASB) issued a new
accounting standard, Statement of Financial Accounting Standards (SFAS) No. 143,
"Accounting for Asset Retirement Obligations."
SFAS No. 143 addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. Specifically, this standard requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred, if a reasonable estimate of fair value can be made. The
entity is required to capitalize the cost by increasing the carrying amount of
the related long-lived asset. The capitalized cost is then depreciated over the
useful life of the related asset. Upon settlement of the liability, an entity
either settles the obligation for its recorded amount or incurs a gain or loss.
The standard is effective for fiscal years beginning after June 15, 2002. We are
currently evaluating, but have yet to determine, the impact that the adoption of
SFAS No. 143 will have on our financial statements.
RESULTS OF OPERATIONS
Overall Performance
Three months ended June 30, 2002. Our earnings available for common stock
were $14.2 million in the second quarter of 2002 compared with $14.6 million in
the second quarter of 2001, a decrease of $0.4 million or 2.7 percent. Cost
savings during this period were offset by lower other income, as discussed
below.
11
Six months ended June 30, 2002. Our earnings available for common stock
were $31.2 million in the first six months of 2002 compared with $23.6 million
in the first six months of 2001, an increase of $7.6 million or 32.2 percent.
This increase is primarily due to lower operating expenses due to the corporate
restructuring that occurred in the fourth quarter of 2001, as well as our cost
reduction initiatives, which continue to generate incremental cost savings.
Results of Operations by Business Segment
We report the results of our business segments, determined by products,
services and regulatory environment as follows: (1) transmission and
distribution of electricity (electricity delivery business segment), (2) supply
of electricity (electricity supply business segment), and (3) collection of
transition costs (CTC business segment).
Electricity Delivery Business Segment.
Three months ended June 30, 2002. The electricity delivery business segment
reported $10.5 million of earnings for common stock in the second quarter of
2002 compared to $11.1 million in the second quarter of 2001, a decrease of $0.6
million, or 5.4 percent, as a result of lower other income in 2002. Other income
in the second quarter of 2001 included a $0.9 million after-tax gain from the
sale of property and higher interest earnings.
Operating revenues for this business segment are primarily derived from the
delivery of electricity, including related excise taxes. Sales to residential
and commercial customers are primarily 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 residential, commercial and industrial customers are
influenced by national and global economic conditions.
Operating revenues increased by $4.8 million or 5.9 percent compared to the
second quarter of 2001. The increase can be primarily attributed to the increase
in the excise taxes that are collected through revenue. The largest excise tax
increase is in the Pennsylvania revenue neutral reconciliation (RNR) tax rate,
which became effective January 1, 2002. Electric distribution companies, such as
Duquesne Light, are permitted to recover this cost from consumers on a current
basis. (See "Legal Proceedings.") In addition, sales to electric utility
customers increased approximately 3.4 percent, contributing to higher operating
revenues.
Residential sales increased 5.9 percent, primarily due to hotter than
normal weather in June 2002. Commercial sales increased 2.4 percent due to an
increase in the number of commercial customers and the hotter weather.
Industrial sales increased 2.7 percent due to increased consumption by steel
manufacturers. The following table sets forth kilowatt-hours (KWH) delivered to
electric utility customers.
- -------------------------------------------------------------------
KWH Delivered
-----------------------------
(In Millions)
-----------------------------
Second Quarter 2002 2001 Change
- -------------------------------------------------------------------
Residential 866 818 5.9 %
Commercial 1,606 1,568 2.4 %
Industrial 843 821 2.7 %
- ---------------------------------------------------------
Sales to Electric
Utility Customers 3,315 3,207 3.4 %
==================================================================
Operating expenses for the electricity delivery business segment consist
primarily of costs to operate and maintain the transmission and distribution
system; meter reading, billing and collection costs; customer service; and
administrative expenses. Operating expenses decreased $1.0 million or 3.1
percent compared to the second quarter of 2001, primarily due to the corporate
restructuring that occurred in the fourth quarter of 2001, as well as our cost
reduction initiatives, which continue to generate incremental cost savings.
Income and other tax expense for the electricity delivery business segment
consists of income taxes and non-income taxes, such as gross receipts, property
and payroll taxes. There was an increase of $4.4 million or 46.3 percent
compared to the second quarter of 2001, primarily due to a $3.6 million increase
in gross receipts tax due to the increased RNR, as well as increased income
taxes due to the higher pre-tax income in the second quarter of 2002.
Other income decreased $2.8 million or 39.4 percent compared to the second
quarter of 2001, primarily due to a $0.9 million after-tax gain on the sale of
property, and higher interest earnings, in the second quarter of 2001.
Six months ended June 30, 2002. The electricity delivery business segment
reported $25.7 million of earnings for common stock in the first six months of
2002 compared to $15.9 million in the first six months of 2001, an increase of
$9.8 million, or 61.6 percent. This improvement is a result of lower operating
expenses due to the corporate restructuring that occurred in the fourth quarter
of 2001, as well as our cost reduction initiatives, which continue to generate
incremental cost savings.
Operating revenues increased by $11.3 million or 7.3 percent compared to
the first six months of 2001. The increase can be primarily attributed to the
$10.0 million increase in the excise taxes that are collected through revenue,
in particular the RNR increase. In addition, sales to electric utility customers
increased approximately 1.7 percent, contributing to higher operating revenues.
12
Residential sales increased 2.3 percent, primarily due to hotter than
normal June weather, which more than offset the adverse effects of warmer than
normal winter weather in the first quarter. Commercial sales increased 2.1
percent due to an increase in the number of commercial customers and the hotter
weather. Industrial sales increased 0.3 percent as well. The following table
sets forth KWH delivered to electric utility customers.
- ---------------------------------------------------------------------
KWH Delivered
-----------------------------------
(in Millions)
-----------------------------------
First Six Months 2002 2001 Change
- ---------------------------------------------------------------------
Residential 1,758 1,719 2.3 %
Commercial 3,119 3,054 2.1 %
Industrial 1,663 1,658 0.3 %
- --------------------------------------------------------
Sales to Electric
Utility Customers 6,540 6,431 1.7 %
=====================================================================
Operating expenses decreased by $9.4 million or 14.2 percent compared to
the first six months of 2001. This decrease is due to the corporate
restructuring that occurred in the fourth quarter of 2001 as well as our cost
reduction initiatives, which continue to generate incremental cost savings.
There was an increase in income and other tax expense of $12.5 million or
80.6 percent compared to the first six months of 2001, primarily due to a $7.5
million increase in gross receipts tax due to the increased RNR, as well as
increased income taxes due to the higher pre-tax income in the first six months
of 2002.
Other income decreased $1.3 million or 9.8 percent compared to the first
six months of 2001. During the first six months of 2002, a $0.8 million
after-tax gain was recognized on the sale of certain securities. This was offset
by a $0.9 million after-tax gain on the sale of property and higher interest
earnings in 2001.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne Light. Interest and other
charges decreased $1.5 million or 3.7 percent compared to the first six months
of 2001, due to favorable interest rates on the $418.0 million of variable rate,
tax-exempt debt.
Electricity Supply Business Segment.
Three months ended June 30,2002. The electricity supply business segment
reported earnings for common stock of $2.9 million in the second quarter of
2002, compared with earnings for common stock of zero in the second quarter of
2001. For the period April 28, 2000 through December 31, 2001, this segment's
financial results reflected our initial provider of last resort service
arrangement (POLR I), which was designed to be income neutral. During the first
quarter of 2002, we began operating under our new provider of last resort
arrangement (POLR II), which extends the provider of last resort service (and
the PUC-approved rates for the supply of electricity) beyond the final CTC
collection through December 31, 2004. POLR II also permits us, following CTC
collection for each rate class, an average margin of 0.5 cents per KWH supplied.
Operating revenues for this business segment are derived primarily from the
supply of electricity for delivery to retail customers and, to a much lesser
extent, the supply of electricity to wholesale customers. Retail energy
requirements fluctuate as the number of customers participating in customer
choice changes. Energy requirements for residential and commercial customers are
also influenced by weather conditions; temperature extremes 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
result primarily from excess daily energy deliveries to our electricity delivery
system.
Operating revenues increased $5.1 million or 4.7 percent compared to the
second quarter of 2001, due to higher average generation rates. The average
generation rate increased January 1, 2002, due to scheduled rate increases. In
addition, the average rates increase incrementally as rate classes become
subject to the POLR II arrangement. Those higher average generation rates more
than offset the decline in total KWH supplied.
The following table sets forth KWH supplied for customers who had not
chosen an alternative generation supplier, segregated by those customers
supplied under the POLR I or the POLR II contract.
- ---------------------------------------------------------------------
KWH Supplied
------------------------------
(In Millions)
------------------------------
Second Quarter 2002 2001
- ---------------------------------------------------------------------
POLR I POLR II Total POLR I
- ---------------------------------------------------------------------
Residential 59 530 589 522
Commercial 813 387 1,200 1,339
Industrial 727 54 781 787
- ---------------------------------------------------------------------
KWH Sales 1,599 971 2,570 2,648
Sales to Other Utilities 48 94
- ---------------------------------------------------------------------
Total Sales 2,618 2,742
=====================================================================
Income and other tax expense for the electricity supply business segment
consists of gross receipts tax, which fluctuates in direct relation to operating
revenues, and income taxes, which fluctuate in direct relation to pre-tax
income. Income and other tax expense increased
13
$2.3 million or 48.9 percent from the second quarter of 2001, due to the
increase in revenues from electric utility customers. In addition, pre-tax
income of $4.9 was generated from the electricity supply business segment in the
second quarter of 2002 since we began operating under the POLR II arrangement,
which resulted in $2.0 million of income tax expense.
Six months ended June 30, 2002. The electricity supply business segment
reported earnings for common stock of $3.4 million in the first six months of
2002, compared to earnings for common stock of zero in the first six months of
2001. During the first quarter of 2002, we began operating under the POLR II
arrangement, discussed above.
Operating revenues increased $11.7 million or 5.7 percent compared to the
first six months of 2001, due to higher average generation rates, discussed
above. These higher average generation rates more than offset the decline in
total KWH supplied.
The following table sets forth KWH supplied for customers who had not chosen
an alternative generation supplier, segregated by those customers supplied under
the POLR I or the POLR II arrangement.
- --------------------------------------------------------------------------------
KWH Supplied
-----------------------------------------------
(In Millions)
-----------------------------------------------
First Six Months 2002 2001
- --------------------------------------------------------------------------------
POLR I POLR II Total POLR I
- --------------------------------------------------------------------------------
Residential 550 682 1,232 1,143
Commercial 1,946 388 2,334 2,476
Industrial 1,475 55 1,530 1,536
- --------------------------------------------------------------------------------
KWH Sales 3,971 1,125 5,096 5,155
Sales to Other Utilities 111 249
- --------------------------------------------------------------------------------
Total Sales 5,207 5,404
================================================================================
Operating expenses for the electricity supply business segment consist of
costs to obtain energy for our provider of last resort service which fluctuate
in direct relation to operating revenues. Operating expenses increased $5.3
million or 2.7 percent compared to the first six months of 2001, a result of the
higher average generation rates charged to customers in the first six months of
2002 under our provider of last resort arrangements.
Income and other tax expense increased $3.0 million or 34.1 percent from the
first six months of 2001, due to the increase in revenues from electric utility
customers. In addition, pre-tax income of $5.7 million was generated from the
electricity supply business segment in the first six months of 2002 since we
began operating under the POLR II arrangement, which resulted in $2.3 million of
income tax expense.
CTC Business Segment.
Three months ended June 30,2002. For the CTC business segment, operating
revenues are derived by billing electric delivery customers for
generation-related transition costs. We are allowed to earn an 11 percent pretax
return on the net of tax CTC balance. As revenues are billed to customers on a
monthly basis, we amortize the CTC balance. The resulting decrease in the CTC
balance causes a decline in the return we earn.
In the second quarter of 2002, the CTC business segment reported earnings
for common stock of $0.8 million compared to $3.5 million during the same period
in 2001, a decrease of $2.7 million or 77.1 percent, due to lower earnings
resulting from the decreased CTC balance.
Operating revenues decreased $40.3 million or 54.5 percent, due to scheduled
decreases in the average CTC rate charged to customers from 2001 to 2002, as
well as the full collection of the allocated CTC balance for most of our
residential customers during the first quarter of 2002, and for a large number
of our commercial customers in the second quarter of 2002. As of June 30, 2002,
the CTC balance has been fully collected for approximately 95 percent of our
customers, and 46 percent of the KWH sales for the first six months of 2002.
Depreciation and amortization expense consists of the amortization of
transition costs. There was a decrease of $34.3 million or 52.6 percent compared
to the second quarter of 2001, primarily due to the full collection of the
allocated CTC balance for certain customers, as discussed above.
Income and other tax expense consists of gross receipts tax, which
fluctuates in direct relation to operating revenues and income taxes, which
fluctuate in direct relation to pre-tax income. Income and other expense
decreased $3.3 million or 63.5 percent compared to the second quarter of 2001,
due to a $1.8 million decrease in gross receipts tax due to the decline in
revenues and a $1.5 million decrease in income taxes due to lower pre-tax income
in the second quarter of 2002.
Six months ended June 30, 2002. In the first six months of 2002, the CTC
business segment reported earnings for common stock of $2.1 million compared to
$7.7 million during the same period in 2001, a decrease of $5.6 million or 72.7
percent. As the CTC balance is collected from customers, there is a resulting
decline in the return we earn.
Operating revenues decreased $49.4 million or 33.4 percent compared to the
first six months of 2001. This decrease is due to scheduled decreases in the
average CTC rate, as well as the full collection of the allocated CTC balance
for certain customers, as discussed above.
14
Depreciation and amortization expense decreased $38.5 million or 29.7
percent compared to the first six months of 2001, primarily due to the full
collection of the allocated CTC balance for certain customers, as discussed
above.
Income and other tax expense decreased $5.3 million or 49.1 percent
compared to the first six months of 2001, due to the $2.2 million decrease in
gross receipts tax due to the decline in operating revenues and the $3.1 million
decrease in income taxes due to lower pre-tax income during the first six months
of 2002.
LIQUIDITY AND CAPITAL RESOURCES
Capital Expenditures
We estimate that during 2002 we will spend, excluding the allowance for
funds used during construction, approximately $70 million for electric utility
construction. During the first six months of 2002, we have spent $34.9 million
on capital expenditures.
Asset Dispositions
During the first six months of 2002, we did not make any acquisitions, but
we received approximately $1.3 million of proceeds from the sale of securities
and recognized an after-tax gain of $0.8 million. We also received approximately
$1.3 million from the sale of a building and recognized an after-tax gain of
$0.3 million.
Financing and Capital Availability
On August 5, 2002, we redeemed the following: (i) $10 million aggregate
principal amount of our 8.20 percent first mortgage bonds due 2022 at a
redemption price of 104.51 percent of the principal amount thereof, and (ii)
$100 million aggregate principal amount of our 7 5/8 percent first mortgage
bonds due 2023 at a redemption price of 103.9458 percent of the principal amount
thereof. Our investment in the cash pool was used to retire these bonds. We have
also reduced outstanding commercial paper balances by $26 million in June 2002,
and $35 million in July 2002, using proceeds from the repayment of the loan to
DQE. With these debt reductions, we expect our debt-to-total-capitalization
ratio (discussed below) to be approximately 56 percent.
On April 15, 2002, we issued $200 million of 6.7 percent first mortgage
bonds due 2012. On April 30, 2002, we issued $100 million of 6.7 percent first
mortgage bonds due 2032. In each case we used the proceeds to call and refund
existing debt, including debt scheduled to mature in 2003 and 2004.
In the first quarter of 2002, Moody's Investor Service, Standard & Poor's,
and Fitch Ratings assessed our short and long-term credit profiles. The ratings
reflect the agencies' opinion of our overall financial strength. Ratings impact
our ability to access capital markets for investment and capital requirements,
as well as the relative costs related to such liquidity capability. In general,
the agencies reduced our long-term credit ratings, although staying within the
range considered to be investment grade. The agencies maintained the existing
credit ratings for our short-term debt. This ratings downgrade does not limit
our ability to access our revolving credit facility; it does, however, impact
the cost of maintaining the credit facility and the cost of any new debt. These
ratings are not a recommendation to buy, sell or hold any securities of Duquesne
Light, may be subject to revisions or withdrawal by the agencies at any time,
and should be evaluated independently of each other and any other rating that
may be assigned to our securities.
At June 30, 2002, we had $35 million of commercial paper borrowings
outstanding. During the quarter, the maximum amount of bank loans and commercial
paper borrowings outstanding was $98 million, the amount of average daily
borrowings was $72.3 million, and the weighted average daily interest rate was
2.3 percent.
We maintain a $150 million revolving credit agreement expiring in October
2002. We may convert the revolver into a term loan facility for a one-year
period, 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 and
Eurodollar rates. Fees are based on the unborrowed amount of the commitment. We
plan to extend the facility prior to expiration. At June 30, 2002 no borrowings
were outstanding.
Under our credit facility, we are required to maintain a maximum
debt-to-capitalization ratio of 65.0 percent. At June 30, 2002 we were in
compliance, having a debt-to-total-capitalization ratio of approximately 59.8
percent.
Contractual Obligations and Commercial Commitments
As of June 30, 2002, we have certain contractual obligations and commercial
commitments that extend beyond this year, the principal amounts of which are set
forth in the following tables:
15
Payments Due By Period
- --------------------------------------------------------------------------------------------------------
(In Millions)
----------------------------------------------------------
2002 2003 2004 2005 After Total
----------------------------------------------------------
Long-Term Debt $ - $ - $ 0.4 $ 0.4 $1,070.0 $1,070.8
Notes Payable and Current Maturities 35.0 - - - - 35.0
Capital Lease Obligations 0.2 0.4 0.4 0.5 1.4 2.9
Operating Leases 1.6 3.3 3.5 3.8 24.1 36.3
- --------------------------------------------------------------------------------------------------------
Total Contractual Cash Obligations $ 36.8 $ 3.7 $ 4.3 $ 4.7 $1,095.5 $1,145.0
========================================================================================================
Other Commercial Commitments
- --------------------------------------------------------------------------------------------------------
(In Millions)
----------------------------------------------------------
2002 2003 2004 2005 After Total
----------------------------------------------------------
Revolving Credit Agreements (a) $ - $ 150.0 $ - $ - $ - $ 150.0
Standby Letters of Credit (a) 12.2 - - - - 12.2
Surety Bonds (b)
Commercial 45.8 - - - - 45.8
Contract 0.3 - - - - 0.3
- --------------------------------------------------------------------------------------------------------
Total Commercial Commitments $ 58.3 $150.00 $ - $ - $ - $ 208.3
========================================================================================================
(a) Revolving Credit Agreements and Letters of Credit are typically for a 364-
day period and are renewed annually.
(b) Surety bonds are renewed annually. Some of the commercial bonds cover
regulatory and contractual obligations which exceed a one-year period.
RATE MATTERS
Competition and the Customer Choice Act
The Pennsylvania Electricity Generation Customer Choice and Competition Act
(Customer Choice Act) enables electric utility customers to purchase electricity
at market prices from a variety of electric generation suppliers. As of June 30,
2002, approximately 77.6 percent of our customers measured on a KWH basis, and
approximately 75.6 percent on a non-coincident peak load basis received
electricity through our provider of last resort service arrangement. The
remaining customers are provided with electricity through alternative generation
suppliers. The number of customers participating in our provider of last resort
service will fluctuate depending on market prices and the number of alternative
generation suppliers in the retail supply business.
Customers who select an alternative generation supplier pay for generation
charges set competitively by that supplier, and pay us a competitive transition
charge (discussed below) and/or transmission and distribution charges.
Electricity delivery (including transmission, distribution and customer service)
remains regulated in substantially the same manner as under historical
regulation.
In November 2001, the Pennsylvania Department of Revenue established an
increased RNR tax in order to recover a current shortfall that resulted from
electricity generation deregulation. Since January 2002, our customer bills have
reflected an approximately two percent increase to recover our costs related to
the RNR. (See "Legal Proceedings.")
Regional Transmission Organization
FERC Order No. 2000 calls on transmission-owning utilities such as Duquesne
Light to join regional transmission organizations (RTOS). We are committed to
ensuring a stable, plentiful supply of electricity for our customers. Toward
that end, we planned to join the PJM West RTO. In late 2001 and early 2002, we
entered into agreements with two generation suppliers to provide the electric
capacity required to meet our anticipated capacity credit obligations in PJM
West through 2004.
Our participation in the PJM West RTO was to be conditioned upon PUC
approval of the recovery of the cost of capacity under these agreements, and we
petitioned the PUC for such approval. However, on July 31, 2002, the FERC issued
a series of proposals designed to establish a standard market design and
transmission service for interstate electricity transactions, and extend its
deadline for joining an RTO until September 2004. In light of the FERC's
proposals, the PUC dismissed our petition without prejudice. As a result,
neither of the capacity agreements will take effect. We will continue to
evaluate the FERC's proposals and their impact on the possibility of joining an
RTO.
Competitive Transition Charge
In its 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. Following our application of net generation asset sale proceeds to
reduce transition costs, the CTC was fully collected for most of our residential
customers
16
during the first quarter of 2002 and a large number of our commercial customers
during the second quarter of 2002. As of June 30, 2002, the CTC balance has been
fully collected for approximately 95 percent of our customers, and 46 percent of
the KWH sales for the first six months of 2002. The transition costs, as
reflected on the consolidated balance sheet, are being amortized over the same
period that the CTC revenues are being recognized.
For regulatory purposes, the unrecovered balance of transition costs was
approximately $48.4 million ($29.5 million net of tax) at June 30, 2002, on
which we are allowed to earn an 11.0 percent pre-tax return. A lower amount is
shown on the balance sheet due to the accounting for unbilled revenues.
Provider of Last Resort
Although no longer a generation supplier, as the provider of last resort for
all customers in our service territory, we must provide electricity for any
customer who does not choose an alternative generation supplier, or whose
supplier fails to deliver. As part of the generation asset sale, a third party
agreed to supply all of the electric energy necessary to satisfy our provider of
last resort obligations during the CTC collection period. Under POLR II, we have
extended the arrangement (and the PUC-approved rates for the supply of
electricity) beyond the final CTC collection through December 31, 2004. POLR II
also permits us, following CTC collection for each rate class, an average margin
of 0.5 cents per KWH supplied through this arrangement. Except for this margin,
these agreements, in general, effectively transfer to the supplier the financial
risks and rewards associated with our provider of last resort obligations.
While there are certain safeguards in the provider of last resort
arrangements designed to mitigate losses in the event that the supplier defaults
on its performance under the arrangement, we may face the credit risk of such a
default. Contractually, we have various credit enhancements that would become
activated upon certain events. If the supplier were to fail to deliver, we would
have to contract with another supplier and/or make purchases in the market at
the time of default at a time when market prices could be higher. While the
Customer Choice Act provides generally for provider of last resort supply costs
to be borne by customers, recent litigation suggests that it may not be clear
whether we could pass any costs in excess of the existing PUC-approved provider
of last resort prices on to our customers. Additionally, the supplier has
recently been downgraded by the rating agencies. Although we are following the
situation closely, our knowledge is limited to public disclosure, and we do not
know whether the downgrade could affect the supplier's ability to perform. We
also retain the risk that customers will not pay for the provider of last resort
generation supply. However, a component of our delivery rate is designed to
cover the cost of a normal level of uncollectible accounts.
We are evaluating options to provide electricity for our provider of last
resort customers after POLR II expires. Such options include one or more of the
following: negotiating an extension of the POLR II arrangement, negotiating a
similar arrangement with one or more generation suppliers, and entering into
alternative supply arrangements, such as constructing a gas-turbine electric
generating facility (either independently or with partners).
DQE's Board of Directors has authorized, subject to receipt of appropriate
regulatory approvals, the development of a generating station by our affiliate,
Duquesne Power Inc. Any decision to build will be influenced by the recently
renewed interest many generating companies have shown in potentially supplying
us with long-term provider of last resort service. We are preparing to file with
the PUC in September 2002 a comprehensive plan that would extend fixed prices
for residential and small commercial provider of last resort customers as
protection from electric market volatility beyond 2004. Our goal is to mitigate
the risks associated with a supply plan and to enhance shareholder value through
a continuing earnings stream from the core electric business.
Rate Freeze
In connection with the POLR II agreement described above, we negotiated a
rate freeze for generation, transmission and distribution rates. The rate freeze
fixes new generation rates for retail customers who take electricity under the
extended provider of last resort arrangement through 2004, and continues the
transmission and distribution rates for all customers at current levels through
at least 2003. Under certain circumstances, affected interests may file a
complaint alleging that, under these frozen rates, we have exceeded reasonable
earnings, in which case the PUC could make adjustments to rectify such earnings.
17
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 $418.0 million or 39.2 percent of
long-term debt. 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 $0.3 million for the
six months ended June 30, 2002 and $0.6 million for the six months ended June
30, 2001. A 10 percent reduction in interest rates would have increased the
market value of our fixed-rate debt by approximately $48.2 million and $41.1
million as of June 30, 2002 and June 30, 2001. Such changes would not have had a
significant near-term effect on our future earnings or cash flows.
PART II. OTHER INFORMATION.
Item 1. Legal Proceedings.
As discussed elsewhere in this report, we requested and received PUC approval
to recover approximately $13 million of costs we will incur in 2002 due to the
RNR. On November 19, 2001, the Pennsylvania Office of Consumer Advocate (OCA)
filed a complaint with the PUC, objecting to the recovery approval and stating
various matters, such as rate of return and offsetting savings, that should be
considered before allowing RNR recovery in excess of rate caps. An initial
hearing on the OCA's complaint was held May 2, 2002 before a PUC administrative
law judge, who denied the OCA's objections. However, on May 9, 2002, the PUC
ordered that our quarterly earnings may be considered in the RNR proceedings.
Additional hearings were held in July 2002. On August 8, 2002, the PUC voted to
uphold dismissal of the OCA's case. The OCA has until early September 2002 to
appeal.
Although we cannot predict the ultimate outcome of this matter, we believe
the final resolution will not significantly affect our results of operations or
cash flows.
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 99.1 - Certification of Principal Executive Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
EXHIBIT 99.2 - Certification of Principal Financial Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
b. We filed a Form 8-K on May 30, 2002, to disclose a press release announcing
the Back-to-Basics plan.
18
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, 2002 /s/ Frosina C. Cordisco
-------------------- ------------------------------
(Signature)
Frosina C. Cordisco
Vice President and Treasurer
(Principal Financial Officer)
Date August 14, 2002 /s/ Stevan R. Schott
-------------------- --------------------------------
(Signature)
Stevan R. Schott
Vice President and Controller
(Principal Accounting Officer)
19