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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2000
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From ____________ to ____________
Commission File Number
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1-956
Duquesne Light Company
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-0451600
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
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(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (412) 393-6000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements for
the past 90 days. Yes X No
--- ---
DQE, Inc., is the holder of all shares of Duquesne Light Company common stock,
$1 par value, consisting of 10 shares as of February 28, 2001.
[ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K.
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Registrant Title of each class which registered
---------- ------------------- ------------------------
Duquesne Light Preferred Stock New York Stock Exchange
Company
Involuntary
Series Liquidation Value
3.75% $50 per share
4.00% $50 per share
4.10% $50 per share
4.15% $50 per share
4.20% $50 per share
$2.10 $50 per share
8.375% $25 per share (1)
Sinking Fund Debentures, due March 1, 2010 (5%) New York Stock Exchange
7 3/8% Quarterly Interest Bonds, due 2038 New York Stock Exchange
(1) Issued by Duquesne Capital, L.P., and the payments of dividends and payments
on liquidation or redemption are guaranteed by Duquesne Light Company.
TABLE OF CONTENTS
Page
----
GLOSSARY
PART I
ITEM 1. BUSINESS
Corporate Structure 1
Employees 1
Property, Plant and Equipment 1
Environmental Matters 2
Current Trends and Outlook 2
Other 3
Executive Officers of the Registrant 4
ITEM 2. PROPERTIES 5
ITEM 3. LEGAL PROCEEDINGS 5
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS 5
PART II
ITEM 5. MARKET FOR REGISTRANT'S
COMMON EQUITY AND RELATED
SHAREHOLDER MATTERS 5
ITEM 6. SELECTED FINANCIAL DATA 5
ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Results of Operations 6
Liquidity and Capital Resources 9
Rate Matters 10
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK 11
ITEM 8. REPORT OF INDEPENDENT AUDITORS;
CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA 12
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 32
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT 32
ITEM 11. EXECUTIVE COMPENSATION 32
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT 32
ITEM 13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS 32
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES AND REPORTS ON
FORM 8-K 32
SCHEDULE II
SIGNATURES
GLOSSARY OF TERMS
With Pennsylvania at the forefront of the national trend toward electric utility
industry restructuring, a number of unique terms have developed and are used in
this report. Certain of these restructuring-specific terms are defined below.
Competitive Transition Charge (CTC) -- During the electric utility restructuring
from the traditional Pennsylvania regulatory framework to customer choice,
electric utilities have the opportunity to recover transition costs from
customers through this usage-based charge.
Customer Choice -- The Pennsylvania Electricity Generation Customer Choice and
Competition Act (see "Rate Matters" on page 10) gives consumers the right to
contract for electricity at market prices from PUC-approved electric generation
suppliers.
Divestiture -- The selling of major assets. We completed the divestiture of our
generation assets through the sale to Orion Power MidWest, L.P. in April 2000.
Federal Energy Regulatory Commission (FERC) -- The FERC is an independent five-
member commission within the United States Department of Energy. Among its many
responsibilities, the FERC sets rates and charges for the wholesale
transportation and sale of electricity.
Pennsylvania Public Utility Commission (PUC) -- The governmental body that
regulates all utilities (electric, gas, telephone, water, etc.) that do business
in Pennsylvania.
Price to Compare -- The PUC-determined price of electric generation (plus
transmission) for each utility during the CTC collection period. Customers will
experience savings if they can purchase power from an alternative electric
generation supplier at a lower price than that determined by the PUC.
Provider of Last Resort -- Under Pennsylvania's Customer Choice Act, the local
distribution utility is required to provide electricity for customers who do not
choose an alternative generation supplier, or whose supplier fails to deliver.
(See "Rate Matters" on page 10.)
Regional Transmission Organization (RTO) -- Organization formed by transmission-
owning utilities to put transmission facilities within a region under common
control.
Regulatory Assets -- Pennsylvania ratemaking practices grant regulated utilities
exclusive geographic franchises in exchange for the obligation to serve all
customers. Under this system, certain prudently incurred costs are approved by
the PUC for deferral and future recovery with a return from customers. These
deferred costs are capitalized as regulatory assets by the regulated utility.
Restructuring Plan -- Our plan, approved by the PUC, for restructuring and
recovery of our transition costs under Pennsylvania's Customer Choice Act.
Transition Costs -- Transition costs are the net present value of a utility's
known or measurable costs related to electric generation that are recoverable
through the CTC.
Transmission and Distribution -- Transmission is the flow of electricity from
generating stations over high voltage lines to substations where voltage is
reduced. Distribution is the flow of electricity over lower voltage facilities
to the ultimate customer (businesses and homes).
PART I
ITEM 1. BUSINESS.
CORPORATE STRUCTURE
Part I of this Annual Report on Form 10-K should be read in conjunction with
our audited consolidated financial statements, which are set forth on pages 12
through 30 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. On April 28, 2000, we sold our generation
assets to Orion Power MidWest, L.P. for approximately $1.7 billion. (See
"Generation Divestiture" discussion on page 10.)
Our various subsidiaries are primarily involved in operating our automated
meter reading technology and providing financing to certain affiliates.
DQE's Strategic Review Process
As announced on December 6, 2000, DQE has commenced a comprehensive, market-
based strategic and financial review of its entire company and the component
businesses. With a primary focus on maximizing shareholder value, this review
could result in the divestiture of some or all of the component businesses,
including the sale of DQE itself. The review process is expected to be completed
during the second quarter of 2001.
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 historically
sold electricity to other utilities. (See "Generation Divestiture" discussion on
page 10.)
Regulation
We are subject to the accounting and reporting requirements of the Securities
and Exchange Commission (SEC). Our electric utility operations are also 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
10), 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, 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. The balance of transition costs was adjusted by receipt of the
proceeds from the generation asset sale during the second quarter of 2000. 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 10.)
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" on page 6 and in "Business Segments and
Related Information," Note O in the Notes to the Consolidated Financial
Statements on page 28.
EMPLOYEES
At December 31, 2000, we had 1,420 employees. We have renegotiated our labor
contract with the International Brotherhood of Electrical Workers, which
represents the majority of our employees. The contract has been extended through
2002 or 2003, depending on the outcome of DQE's strategic review process, and
provides, among other things, employment security and income protection.
PROPERTY, PLANT AND EQUIPMENT
Investment in PP&E and Accumulated Depreciation
Our total investment in property, plant and equipment (PP&E) and the related
accumulated depreciation balances for major classes of property at December 31,
2000 and 1999 are as follows:
1
PP&E and Related Accumulated Depreciation at December 31,
- ---------------------------------------------------------------------------------------
(Millions of Dollars)
2000
----------------------------------------------------
Accumulated Net
Investment Depreciation Investment
- ---------------------------------------------------------------------------------------
Electric delivery $1,911.5 $ 612.5 $1,299.0
Electric supply -- -- --
Capital leases 19.3 6.8 12.5
Other 34.3 1.5 32.8
- ---------------------------------------------------------------------------------------
Total $1,965.1 $ 620.8 $1,344.3
=======================================================================================
(Millions of Dollars)
1999
----------------------------------------------------
Accumulated Net
Investment Depreciation Investment
- ---------------------------------------------------------------------------------------
Electric delivery $1,997.3 $ 745.3 $1,252.0
Electric supply 1,928.8 1,745.7 183.1
Capital leases 26.0 7.6 18.4
Other 7.1 2.1 5.0
- ---------------------------------------------------------------------------------------
Total $3,959.2 $2,500.7 $1,458.5
=======================================================================================
Electric delivery PP&E includes: (1) high voltage transmission wires used in
delivering electricity from generating stations to substations; (2) substations
and transformers; (3) lower voltage distribution wires used in delivering
electricity to customers; (4) related poles and equipment; and (5) internal
telecommunication equipment, vehicles and office equipment. In 1999, electric
supply PP&E included fossil generating stations. Electric supply accumulated
depreciation reflects the write-down of production plant values to the PUC-
determined market value. Our capital leases are primarily associated with other
electric plant. The other PP&E is comprised of various buildings, land and the
assets related to the Customer Advanced Reliability System (CARS) acquisition in
2000. (See "Acquisition and Dispositions" discussion on page 9.)
ENVIRONMENTAL MATTERS
Various federal and state authorities regulate us with respect to air and
water quality and other environmental matters. Environmental compliance
obligations with respect to the generation plants transferred to FirstEnergy
Corp. in the power station exchange have been assumed by FirstEnergy. Upon
completion of the generation asset sale, Orion assumed the environmental
obligations related to all of the plants sold, both those we originally owned
and those we acquired in the power station exchange. (See "Generation
Divestiture" discussion on page 10.)
In 1992, the Pennsylvania Department of Environmental Protection (DEP) issued
Residual Waste Management Regulations governing the generation and management of
non-hazardous residual waste, such as coal ash. Following the generation asset
divestiture, we retained certain facilities which remain subject to these
regulations. We have assessed our residual waste management sites, and the DEP
has approved our compliance strategies. We incurred costs of $2 million in 2000
to comply with these DEP regulations. We expect the costs of compliance to be
approximately $1.5 million over the next two years with respect to sites we will
continue to own. These costs are being recovered in the CTC, and the
corresponding liability has been recorded for current and future obligations.
Our current estimated liability for closing Warwick Mine, including final
site reclamation, mine water treatment and certain labor liabilities, is
approximately $40 million. We have recorded a liability for this amount on the
consolidated balance sheet.
We are involved in various other environmental matters. We believe that such
matters, in total, will not have a materially adverse effect on our financial
position, results of operations or cash flows.
CURRENT TRENDS AND OUTLOOK
Electric Utility Industry Trends
Spurred by regulatory and technology developments, a number of significant
market trends are affecting electric industry participants today. Perhaps the
most obvious is a heightened degree of price awareness: when customers have
choices, they pay more attention to prices. While the increased attention is
focused on wholesale electricity prices, there is a spillover effect on delivery
prices as well. Further, the present elevated level of wholesale electricity
prices may make it more difficult politically for regulators to grant increases
in delivery prices.
A second market trend is the increase in new service opportunities. With
choice, customers are likely to be interested in services to facilitate shopping
for alternative generation suppliers, such as customer aggregation, price
solicitation and/or gathering and price risk management. Customers will also
have the opportunity to use Internet-based communication to manage their energy
usage through usage measurement and analysis, usage control, and multi-commodity
integration. A third category of new opportunities is arising in the area of
asset management, where industrial and institutional customers may seek
management services concerning their electricity production assets, such as
facility design, construction, operation, fuel procurement and financing
services.
An additional market trend is an increased customer awareness of and interest
in the quality of electric service. With the growth in electricity usage by
equipment containing microprocessors (e.g., computers
2
and communication devices), outages and voltage fluctuations are more readily
noticed and less easily tolerated. In addition, in an era when many kinds of
information are available instantly on the Internet, customers increasingly
expect utilities to provide information about their electricity supply in a
timely manner; failure to do so leads to reduced customer satisfaction. With a
smaller bill subject to their jurisdiction, regulators are increasingly focused
on customer satisfaction. In this environment, failure to maintain and improve
performance in the delivery business can both damage relationships with
regulators and reduce opportunities to win customers for new kinds of services.
In addition to deregulation of the generation sector, major changes are
underway in the delivery sector, as well. At the most basic level, a number of
delivery businesses--especially those that have divested generation--discovered
a need to overhaul the core of their delivery businesses to address service
quality considerations. This typically involves resizing administrative
functions, redesigning customer service functions, and replacing information
systems that support those functions.
A second industry trend is the effort to broaden service offerings. Most
utilities focus on their existing service territories, where they possess the
advantage of existing customer relationships; the more ambitious are attempting
to expand their unregulated services geographically. Some utilities are using
acquisition of non-electric utilities as a means of increasing the available
customer base for introducing new services. Changes have already begun in the
provision of some kinds of services, particularly those involving commodity
price risk management, where scale is a distinct advantage.
Finally, the long-term trend toward industry consolidation is accelerating,
especially among utilities that have divested generation. Almost all U.S.
utilities that have divested generation in the course of industry restructuring
have either merged, been acquired or expanded significantly through purchases of
other utilities' divested generation assets. The difficulties of overhauling the
core business and introducing new services, and the advantages of acquiring
greater scale in these areas, provide a powerful impetus for consolidation.
Outlook
As discussed previously, DQE has commenced a strategic and financial review of
its entire company, focusing on maximizing shareholder value. This review could
result in the divestiture of one or more component businesses or DQE as a whole.
The review process is expected to be completed during the second quarter of
2001.
We are now a much smaller company, and are changing the role of our
administrative infrastructure. We have implemented our previously reported
Best-in-Class initiative, through which we anticipate approximately $30 million
in annual pre-tax savings beginning in 2001, and continue to restructure our
operations following the generation asset sale. The preceding sentence is
forward-looking; anticipated savings will depend on the effectiveness of our
administrative restructuring and our ability to operate with reduced
administrative resources.
OTHER
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities. This
statement, which became effective for us on January 1, 2001, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts (collectively referred to as
derivatives), and for hedging activities. We have evaluated the impact on our
financial statements and have determined that the adoption of this statement
will not have a material impact on our results of operations, financial position
or cash flows.
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 million or 39 percent of long-
term debt. Most of 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 $2.0 million, $1.6
million and $1.6 million for the years ended December 31, 2000, 1999 and 1998. A
10 percent reduction in interest rates would have increased the market value of
our fixed rate debt by approximately $40.4 million and $20.3 million as of
December 31, 2000 and 1999. Such changes would not have a significant near-term
effect on our future earnings or cash flows.
--------------------------
Except for historical information contained herein, the matters discussed in
this annual report are forward-looking statements that involve risks and
uncertainties including, but not limited to: the outcome of DQE's strategic
review process; economic, competitive, governmental and technological factors
affecting operations, markets, products, services and prices; and other risks
discussed in our filings with the Securities and Exchange Commission.
3
EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below are the names, ages as of March 10, 2001, positions, and brief
accounts of the business experience during the past five years of our executive
officers.
Name Age Office
John R. Marshall 51 President since August 1999. Previously, Vice President -
Consumer and Small Business Market Unit of Entergy
Corporation from 1996 to August 1999. Vice President -
Information Systems of Entergy Corporation from 1995
to 1996.
Stevan R. Schott 38 Vice President - Finance and Customer Service since
August 2000. Vice President and Controller from August
1999 to August 2000. Previously, Controller of Montauk,
Inc. from October 1998 to August 1999. Deloitte & Touche
LLP - Senior Manager and Public Utilities Specialist
from September 1993 to September 1998.
Maureen L. Hogel 40 Vice President - Development, Legal and Administration
since January 2001. Vice President - Legal from
September 1999 to January 2001. Assistant General
Counsel from February 1996 to September 1999.
Previously, Associate with Drinker, Biddle & Reath from
September 1988 to February 1996.
Joseph G. Belechak 41 Vice President - Asset Management and Operations since
August 2000. General Manager, Asset Management from
March 1999 to August 2000. Manager, Substations and
Telecommunications from June 1996 to March 1999.
James E. Wilson 35 Vice President and Chief Accounting Officer since August
2000. Previously Controller from November 1998 to August
1999, and Assistant Controller from September 1996 to
November 1998. Controller for affiliates from 1995 to
1998. Currently Vice President and Controller of DQE
since March 2000. Previously Controller since July 1999
and Assistant Controller from 1996 to July 1999.
4
ITEM 2. PROPERTIES.
Our principal properties consist of electric transmission and distribution
facilities and supplemental properties and appurtenances, located substantially
in Allegheny and Beaver counties in southwestern Pennsylvania.
Substantially all of the electric utility properties are subject to a mortgage
lien of an Indenture of Mortgage and Deed of Trust dated as of April 1, 1992.
On April 28, 2000, we sold our generation assets. We own 9 transmission
substations and 561 distribution substations (367 of which are located on
customer-owned land and are used to service only that customer). We have 592
circuit-miles of transmission lines, comprised of 345,000, 138,000 and 69,000
volt lines. Street lighting and distribution circuits of 23,000 volts and less
include approximately 16,420 circuit-miles of lines and cable. These properties
are used in the electricity delivery business segment.
We own, but do not operate, the Warwick Mine, including 4,849 acres owned in
fee of unmined coal lands and mining rights, located on the Monongahela River in
Greene County, Pennsylvania. Mining operations ceased in March 2000, and
reclamation commenced in April 2000. This property had been used in the
electricity supply business segment.
ITEM 3. LEGAL PROCEEDINGS.
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
SHAREHOLDER MATTERS.
All of our common stock is held solely by DQE; none is publicly traded.
During 2000 and 1999, we declared quarterly dividends on our common stock
totaling $282 million and $203 million, respectively.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data for each year of the six-year period ended December
31, 2000, are set forth on page 31. The information is incorporated here by
reference.
5
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
RESULTS OF OPERATIONS
Overall Performance
2000 Compared to 1999
Our earnings available for common stock were $89.2 million in 2000, compared
to $147.0 million in 1999, a decrease of $57.8 million or 39.3 percent. The
decrease in earnings is primarily due to the sale of our generation assets. The
net proceeds from the sale were applied to reduce the level of our transition
costs. (See "Generation Divestiture" discussion on page 10.) As we record 11
percent pre-tax earnings on our unrecovered transition costs, this reduction in
the level of transition costs resulted in decreased earnings. While this sale
resulted in a reduction in earnings, customer rates--and consequently our cash
flow--will not be reduced until transition costs have been fully recovered in
early 2002 for most major rate classes.
1999 Compared to 1998
In the second quarter of 1998, the PUC issued its final restructuring order
related to our plan to recover our transition costs from electric utility
customers. As a result of the order, we recorded an extraordinary charge against
earnings of $82.6 million, or $1.06 per share of DQE common stock. The following
discussion of results of operations excludes the impact of that charge.
Our earnings available for common stock were $147.0 million in 1999 compared
to $144.5 million in 1998, an increase of $2.5 million or 1.7 percent. This
increase was due to decreased purchased power costs as a result of improved
generating station availability, and was partially offset by decreased revenues
due to customer choice.
Results of Operations by Business Segment
Prior to 1999, Duquesne Light was treated as a single integrated business
segment, due to our 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 Customer Choice Act, supply of electricity is deregulated and
charged at a separate rate from the delivery of electricity. For the purposes of
disclosing information about our business segments, we have allocated revenues
to our various lines of business.
We report our results by the following three principal business segments,
determined by products, services and regulatory environment: (1) the
transmission and distribution of electricity (electricity delivery business
segment), (2) the supply of electricity (electricity supply business segment)
and (3) the collection of transition costs (CTC business segment). With the
completion of our generation asset sale in April 2000, the electricity supply
business segment is now comprised solely of provider of last resort service.
During 2000, we dividended a non-electric operating subsidiary and a
financial, non-operating subsidiary to DQE. The operations of our remaining
subsidiaries support solely the electricity delivery business segment.
Therefore, we no longer report an "all other" category. We have restated prior
periods where appropriate to present segment information consistent with the
manner that is currently used by management. Note O, "Business Segments and
Related Information," in the Notes to the Consolidated Financial Statements on
page 28 shows the financial results of each principal business segment in
tabular form. Following is a discussion of these results.
2000 Compared to 1999
Electricity Delivery Business Segment. The electricity delivery business
segment contributed $43.3 million to net income in 2000, compared to $38.7
million in 1999, an increase of $4.6 million or 11.9 percent. Included in 2000
is $7.3 million related to the cumulative effect of a change in accounting
principle for unbilled revenues.
Operating revenues for this business segment are primarily derived from the
delivery of electricity. Sales to residential and commercial customers are
influenced by weather conditions. Warmer summer and colder winter seasons lead
to increased customer use of electricity for cooling and heating. Commercial
sales also are affected by regional development. Sales to industrial customers
are influenced primarily by national and global economic conditions.
Operating revenues increased by $9.1 million or 3.0 percent compared to 1999,
due to an increase in sales to electric utility customers of 1.7 percent in
2000, and more revenues allocated to this segment after the generation asset
sale. Residential sales decreased 0.5 percent primarily due to milder weather
conditions in 2000. Commercial sales increased 2.3 percent, due to an increase
in the number of commercial customers, while industrial sales increased 2.9
percent, due to increased consumption by steel manufacturers. The following
table sets forth kilowatt-hours (KWH) delivered to electric utility customers.
6
- ----------------------------------------------------------------------
KWH Delivered
-----------------------------------
(In Millions)
-----------------------------------
2000 1999 Change
- ----------------------------------------------------------------------
Residential 3,509 3,526 (0.5)%
Commercial 6,162 6,024 2.3%
Industrial 3,581 3,481 2.9%
- -----------------------------------------------------------
Billed KWH Sales 13,252 13,031 1.7%
Unbilled KWH Accrual 483 -- --%
- -----------------------------------------------------------
Total Sales 13,735 13,031 5.4%
======================================================================
Operating expenses for the electricity delivery business segment are primarily
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 $14.5
million or 7.8 percent compared to 1999, due to cost reductions realized from
the corporate center excellence and best-in-class initiatives we began in 2000;
cost savings related to the implementation of our automated Customer Advanced
Reliability System (CARS), which replaced our traditional, labor-intensive meter
reading process; and a reduction to employee pension costs.
Depreciation and amortization expense includes the depreciation of electric
delivery-related plant and equipment. There was an increase of $5.9 million or
11.7 percent compared to 1999. The increase is primarily attributed to more
general plant being allocated to the delivery business in 2000, and the
acquisition of the CARS system.
Other income increased $3.2 million compared to 1999, primarily due to
interest income earned from the generation asset sale proceeds, and was
partially offset by the dividend of certain subsidiaries to DQE.
Interest and other charges include interest on long-term debt and other
interest. In 2000, there was $23.6 million or 51.4 percent more interest and
other charges allocated to the electricity delivery business segment compared to
1999. Although we used the generation asset sale proceeds to retire debt, thus
reducing our overall level of interest expense, all remaining financing costs
after recapitalization are borne by the electricity delivery business segment.
Electricity Supply and CTC Business Segments. In 2000, the electricity supply
and CTC business segments reported combined net income of $45.8 million compared
to $108.3 million in 1999, a decrease of $62.5 million or 57.7 percent. Included
in 2000 is $8.2 million related to the cumulative effect of a change in
accounting principle for unbilled revenues.
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, beginning in
1999, the collection of generation-related transition costs from electricity
delivery customers.
Energy requirements for our retail electric utility customers will fluctuate
as customers participate in customer choice. 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 reflect the generation divestiture in April
2000. Prior to the divestiture, fluctuations are related to customer energy
requirements, the energy market and transmission conditions, and the
availability of generating stations.
Operating revenues decreased by $92.0 million or 10.8 percent compared to
1999. The decrease in revenues can be attributed to a 71.2 percent decrease in
sales to other utilities in 2000 compared to 1999. The following table sets
forth KWH supplied for customers who have not chosen an alternative generation
supplier.
- ----------------------------------------------------------------------
KWH Supplied
-----------------------------------
(In Millions)
-----------------------------------
2000 1999 Change
- ----------------------------------------------------------------------
Residential 2,422 2,533 (4.4)%
Commercial 4,436 3,811 16.4%
Industrial 3,332 2,581 29.1%
- -------------------------------------------------------
Billed KWH Sales 10,190 8,925 14.2%
Unbilled KWH Accrual 341 -- --%
Sales to Other Utilities 963 3,347 (71.2)%
- -------------------------------------------------------
Total Sales 11,494 12,272 (6.3)%
======================================================================
Operating expenses for the electricity supply business segment are primarily
made up of energy costs; costs to operate and maintain the power stations;
administrative expenses; income taxes; and non-income taxes, such as gross
receipts, property and payroll taxes.
Fluctuations in energy costs generally result from changes in the cost of
fuel; the mix between coal and nuclear generated power and purchased power;
total KWH supplied; and generating station availability.
7
Operating expenses decreased $87.7 million or 16.2 percent from 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, related to our provider of last resort arrangement, following the
generation asset sale.
In 2000, fuel and purchased power expense increased by $122.7 million or 54.5
percent compared to 1999. Although fuel costs were incurred only through the
April 28, 2000 generation asset sale, there was an increase in purchased power
costs following the sale related to the provider of last resort arrangement with
Orion. The cost under the arrangement is an average of $0.04 per KWH across all
rate classes. (See "Provider of Last Resort" discussion on page 11.) 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 depreciation of the power
stations' plant and equipment through the date of the generation asset sale,
accrued nuclear decommissioning costs during 1999, and amortization of
transition costs. There was an increase of $129.9 million or 106.6 percent
compared to 1999. By applying the $967 million of net proceeds from the
generation asset sale to reduce transition costs, we now anticipate termination
of the CTC collection period in early 2002 for most major rate classes. As a
result, there was higher CTC amortization in 2000 compared to 1999. In addition,
we recorded $13.8 million of CTC amortization included in the cumulative effect
of a change in accounting principle for unbilled revenues in 2000.
Other income decreased $4.6 million or 62.2 percent compared to 1999,
primarily due to less income being allocated to these business segments in 2000
following the generation asset sale.
Interest and other charges include interest on long-term debt and other
interest. In 2000 there was a $68.1 million or 76.3 percent decrease in interest
and other charges compared to 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 business segments in 2000
due to the generation asset sale.
1999 Compared to 1998
In the second quarter of 1998, the PUC issued its final restructuring order
related to our plan to recover our transition costs from electric utility
customers. As a result of the order, we recorded an extraordinary charge against
earnings of $82.6 million, or $1.06 per share of DQE common stock. The following
discussion of results of operations for business segments excludes the impact of
that charge.
Electricity Delivery Business Segment. The electricity delivery business
segment contributed $38.7 million to net income in 1999, compared to $72.6
million in 1998, a decrease of $33.9 million or 46.7 percent.
Operating revenues decreased by $16.4 million or 5.1 percent compared to 1998
due to a lower level of other revenues allocated to this segment in 1999, offset
by an increase in sales to electric utility customers of 2.7 percent in 1999.
Residential and commercial sales increased as a result of warmer summer
temperatures during 1999 compared to 1998. Industrial sales increased primarily
due to an increase in electricity consumption by steel manufacturers. The
following table sets forth KWH delivered to electric utility customers.
- ----------------------------------------------------------------------
KWH Delivered
-----------------------------------
(In Millions)
-----------------------------------
1999 1998 Change
- ----------------------------------------------------------------------
Residential 3,526 3,382 4.3%
Commercial 6,024 5,896 2.2%
Industrial 3,481 3,412 2.0%
- -----------------------------------------------------------
Sales to Electric
Utility Customers 13,031 12,690 2.7%
======================================================================
Operating expenses decreased by $3.8 million or 2.0 percent compared to 1998,
due to a lower level of taxes on the decreased operating income allocated to
this segment. Partially offsetting this decrease were increased meter reading
costs,higher gross receipts taxes, and increased costs related to the customer
assistance programs.
In 1999, there was $7.7 million or 20.2 percent more interest and other
charges allocated to the electricity delivery business segment compared to 1998.
The increase was the result of additional short-term borrowings during the
fourth quarter of 1999.
Electricity Supply and CTC Business Segments. In 1999, the electricity supply
and CTC business segments reported net income of $108.3 million, compared to
$71.9 million in 1998, an increase of $36.4 million or 50.6 percent.
Operating revenues decreased by $3.5 million or 0.4 percent compared to 1998.
The decrease in revenues resulted primarily from two factors: (1) 26.4 percent
less energy supplied to electric utility customers due to greater participation
in customer choice, and (2) the 1998 inclusion in revenues of $23.3 million
related to deferred energy costs. Partially offsetting this decrease was a 75.3
percent increase in energy supplied to other utilities in 1999, due to our
decision to make 600 megawatts available to licensed generation suppliers during
the first six months of 1999 to stimulate competition, and increased capacity
available to sell as a result of participation in customer choice. The following
table sets forth KWH supplied for customers who had not chosen an alternative
generation supplier.
8
- ----------------------------------------------------------------------
KWH Supplied
-----------------------------------
(In Millions)
-----------------------------------
1999 1998 Change
- ----------------------------------------------------------------------
Residential 2,533 3,190 (20.6)%
Commercial 3,811 5,580 (31.7)%
Industrial 2,581 3,358 (23.1)%
- -----------------------------------------------------------
Sales to Electric
Utility Customers 8,925 12,128 (26.4)%
Sales to Other Utilities 3,347 1,909 75.3%
- -----------------------------------------------------------
Total Sales 12,272 14,037 (12.6)%
======================================================================
Operating expenses decreased $39.9 million or 6.9 percent from 1998, as a
result of lower energy costs and the reclassification of Beaver Valley Unit 2
lease costs to financing charges in 1999. (See "Generation Divestiture"
discussion on page 10.)
In 1999, fuel and purchased power expense decreased by $37.4 million or 14.2
percent compared to 1998. This decrease was the result of reduced energy supply
requirements, due to customer choice, and a favorable energy supply mix.
Generating station availability was improved in 1999.
Depreciation and amortization expense decreased $36.2 million or 22.9 percent
compared to 1998. During 1998, prior to the PUC's final restructuring order, we
accelerated depreciation of generation assets to minimize potential transition
costs. Depreciation for the remainder of 1998 and CTC amortization for 1999 were
in accordance with PUC-approved rates.
In 1999 there was a $30.7 million or 52.4 percent increase in interest and
other charges compared to 1998. The increase reflects $35.2 million of Beaver
Valley Unit 2 lease-related costs reclassified as financing costs in 1999,
partially offset by a reduced allocation of total financing cost to the
electricity supply business segment.
LIQUIDITY AND CAPITAL RESOURCES
Capital Expenditures
We spent approximately $89.8 million, $100.3 million and $118.4 million in
2000, 1999 and 1998 for electric utility construction. We estimate that we will
spend, excluding allowance for funds used during construction (AFC),
approximately $61 million for electric utility construction in each of the years
2001, 2002 and 2003.
Acquisitions and Dispositions
On April 28, 2000, we completed the sale of our generation assets to Orion for
approximately $1.7 billion dollars. (See "Generation Divestiture" discussion on
page 10.) Additionally, we dividended two of our non-electric subsidiaries to
DQE in 2000.
Also during 2000, we purchased from Itron, Inc. the CARS automated electronic
meter reading system developed by Itron for use with our electricity utility
customers. We had previously leased these assets.
Long-Term Investments
We did not make any long-term investments during 2000, and dividended our
investments in landfill and coal-bed methane gas reserves to DQE.
During 1999, we invested approximately $60 million in the nuclear
decommissioning trust funds, in order to fully fund the decommissioning
liability, prior to transferring both the trust funds and the liability to
FirstEnergy in the power station exchange. (See "Generation Divestiture"
discussion on page 10.) Cash related to this funding was collected during the
year through the CTC component of customer bills. We also invested approximately
$2.3 million in other long-term investments.
During 1998, we invested approximately $35 million in the nuclear
decommissioning trust funds and other long-term investments.
Financing
In 2000, we needed to raise less capital than in 1999 due to the receipt of
generation asset sale proceeds in April 2000. With the proceeds, we retired $350
million of long-term bonds, $399 million of maturing bonds, and $137 million of
commercial paper. Additionally during 2000, we invested $89.8 million in capital
expenditures and $32 million in acquisitions. We also paid approximately $286
million in dividends on capital stock.
At December 31, 2000, we had $0.8 million of current debt maturities and no
commercial paper borrowings outstanding. During 2000, the maximum amount of bank
loans and commercial paper borrowings outstanding was $189.5 million, the amount
of average daily borrowings was $7.0 million, and the weighted average daily
interest rate was 6.0 percent.
During 1999, we raised capital to effect the termination of the Beaver Valley
Unit 2 lease, and to begin our recapitalization program in anticipation of the
generation divestiture. We invested $100 million in capital expenditures, and
$62 million in nuclear decommissioning and other long-term investments during
1999. Additionally, in connection with the power station exchange, we paid
approximately $234 million in termination costs and $43 million in related taxes
to cancel the Beaver Valley Unit 2 lease. Of this total amount, $107 million
represents costs previously approved for recovery through the CTC. The remaining
$170 million is included on the consolidated balance sheet as divestiture costs
as of December 31, 1999. As part of this transaction, the lease liability
recorded on the consolidated balance sheet was eliminated. Prior to cancelling
the Beaver Valley Unit 2 lease, we paid
9
approximately $42 million to terminate our nuclear fuel lease (the nuclear fuel
was transferred to FirstEnergy in the power station exchange). Additional
capital was required for the maturity of $75 million of mortgage bonds,and the
payment of $207 million of dividends.
To meet these capital requirements, and to serve as a bridge until the receipt
in 2000 of our generation divestiture proceeds, we undertook several financing
initiatives during 1999. At year-end, we had $137 million of commercial paper
borrowings outstanding, and $400 million of current debt maturities. During
1999, the maximum amount of bank loans and commercial paper borrowings
outstanding was $163.1 million, the amount of average daily borrowings was $19.4
million, and the weighted average daily interest rate was 5.6 percent. We issued
$290 million of first mortgage bonds with a one-year term, callable in May 2000.
The interest rate on the bonds was 6.53 percent. This debt was used to fund the
Beaver Valley Unit 2 lease termination costs.
During 1998, our requirement to access new sources of funding was much more
modest. While we invested $118 million in capital expenditures, and $35 million
in nuclear decommissioning and other long-term investments, our cash balance of
$165 million at the beginning of the year allowed us to minimize new financing
activities. Additional capital was required during the year for the retirement
of approximately $200 million of current maturities and the payment of $212
million of dividends. During 1998, we issued $140 million of first mortgage
bonds to accomplish these debt retirements.
Future Capital Requirements and Availability
We expect to meet our current obligations and debt maturities through 2005
with funds generated from operations, through new financings and short-term
borrowings.
We have $100 million of first mortgage bonds that mature in 2003.
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 December 31, 2000 and 1999,
no borrowings were outstanding.
With customer choice fully in effect, and our generation asset divestiture
complete, all of our electric utility customers are now buying their generation
directly from alternative suppliers or indirectly from Orion through the
provider of last resort service arrangement. Customer revenues on the income
statement 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, rates for residential customers will drop by 21 percent with the final
CTC collection. We also agreed to freeze generation rates through 2004 and
transmission and distribution rates through 2003. The margin earned through our
extended provider of last resort arrangement is expected to partially offset
this revenue reduction. (See "Provider of Last Resort" and "Rate Freeze"
discussions on page 11.)
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 Customer Choice Act enables Pennsylvania's electric utility customers to
shop, purchasing electricity at market prices from a variety of electric
generation suppliers (customer choice). All customers now have customer choice.
As of February 28, 2001, approximately 30.8 percent of our customers had chosen
alternative generation suppliers, representing approximately 25.6 percent of our
non-coincident peak load. The remaining customers are provided with electricity
through our provider of last resort service arrangement with Orion (discussed on
the next page). Recently, two alternative generation suppliers have decided to
exit the retail supply business, which is expected to increase the number of
customers participating in our provider of last resort service.
Customers who select an alternative generation supplier pay for generation
charges set competitively by that supplier, and pay us the CTC and transmission
and distribution charges. Electricity delivery (including transmission,
distribution and customer service) remains regulated in substantially the same
manner as under historical regulation.
Generation Divestiture
On December 3, 1999, we completed the exchange of our partial interests in
five power plants for three wholly owned power plants from FirstEnergy. In
connection with this exchange, we terminated the $359.2 million Beaver Valley
Unit 2 lease in the fourth quarter of 1999.
On April 28, 2000, we completed the sale of our generation assets to Orion.
Orion purchased all of our
10
power stations, including those received from FirstEnergy, for approximately
$1.7 billion.
In its final restructuring order issued in the second quarter of 1998, 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. As originally approved, our
transition costs were to be recovered over a seven-year period ending in 2005.
However, due to the success of the generation asset sale to Orion, this recovery
period has been significantly shortened. On January 18, 2001, the PUC issued an
order approving our final accounting for the sale proceeds, including the net
recovery of $276 million of transaction costs related to the generation exchange
and sale. Applying the net generation asset sale proceeds to reduce transition
costs, we now anticipate termination of the CTC collection period in early 2002
for most major rate classes. Rates will then decrease 21 percent for residential
customers who continue to take provider of last resort service from us pursuant
to the second agreement with Orion discussed below. Once the CTC collection
period ends for all rate classes, rates will decrease on average 17 percent
system-wide for provider of last resort customers. 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 that remain following the generation
asset sale was approximately $411 million ($251 million net of tax) at December
31, 2000. A slightly lower amount is shown on the balance sheet due to the
accounting for the cumulative effect of a change in accounting principle for
unbilled revenues. We are allowed to earn an 11 percent pre-tax return on this
net amount.
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, Orion agreed to
supply us with all of the electric energy necessary to satisfy our provider of
last resort obligations during the CTC collection period. On December 20, 2000,
the PUC approved a second agreement that extends Orion's provider of last resort
arrangement (and the PUC-approved rates for the supply of electricity) beyond
the final CTC collection through 2004. The agreement also permits us, following
CTC collection, an average margin of 0.5 cents per KWH supplied through this
arrangement. Except for this margin, these agreements, in general, effectively
transfer 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.
Rate Freeze
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 agreed to extend this
rate cap for an additional six months through the end of 2001. Subsequently, in
connection with the December 20 provider of last resort agreement described
previously, 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, 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.
FERC Order No. 2000
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. On October 16, 2000, we informed the FERC of our plan to join a regional
transmission organization at the earliest practicable date. We are actively
negotiating with the Pennsylvania-New Jersey-Maryland Interconnection to
establish the PJM West regional transmission organization. Our ultimate decision
will depend in part on the outcome of DQE's strategic review process.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The information regarding market risk required by this Item is set forth in
Item 1 under the heading "Market Risk" on page 3.
11
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT AUDITORS
To the Directors and Shareholder of Duquesne Light Company:
We have audited the accompanying consolidated balance sheets of Duquesne Light
Company (a wholly owned subsidiary of DQE, Inc.) and its subsidiaries as of
December 31, 2000 and 1999, and the related consolidated statements of income,
comprehensive income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2000. Our audits also included the
financial statement schedule listed in the Index at Item 14. These financial
statements and financial statement schedule are the responsibility of Duquesne
Light Company's management. Our responsibility is to express an opinion on the
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Duquesne Light Company and its
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
As discussed in Note A to the financial statements, Duquesne Light Company
changed its method of accounting for unbilled revenues as of January 1, 2000.
/s/ Deloitte & Touche LLP
Pittsburgh, Pennsylvania
February 1, 2001
12
Statement of Consolidated Income
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------------------
Year Ended December 31,
-----------------------------------------
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues:
Sales of Electricity:
Residential $ 373,154 $ 401,409 $ 410,960
Commercial 425,451 437,904 495,194
Industrial 206,687 183,112 189,617
- ---------------------------------------------------------------------------------------------------------------------------------
Customer revenues 1,005,292 1,022,425 1,095,771
Utilities 29,412 76,303 36,203
- ---------------------------------------------------------------------------------------------------------------------------------
Total Sales of Electricity 1,034,704 1,098,728 1,131,974
Other 41,160 60,072 46,772
- ---------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,075,864 1,158,800 1,178,746
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 53,041 167,080 176,913
Purchased power 294,818 58,102 85,647
Other operating 140,409 253,252 270,458
Maintenance 50,623 75,400 74,908
Depreciation and amortization 308,154 172,424 204,204
Taxes other than income taxes 58,172 84,532 80,035
Income taxes 27,476 88,246 82,495
- ---------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 932,693 899,036 974,660
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Income 143,171 259,764 204,086
- ---------------------------------------------------------------------------------------------------------------------------------
Other Income and (Deductions):
Interest and dividend income 20,892 5,923 13,242
Income taxes (14,105) (12,119) (7,582)
Other 14,357 28,686 31,551
- ---------------------------------------------------------------------------------------------------------------------------------
Total Other Income 21,144 22,490 37,211
- ---------------------------------------------------------------------------------------------------------------------------------
Income Before Interest and Other Charges 164,315 282,254 241,297
- ---------------------------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 73,545 79,454 81,076
Other interest 3,149 40,054 1,290
Allowance for borrowed funds used during construction (2,030) (836) (2,179)
- ---------------------------------------------------------------------------------------------------------------------------------
Total Interest Charges 74,664 118,672 80,187
- ---------------------------------------------------------------------------------------------------------------------------------
Monthly Income Preferred Securities Dividend Requirements 12,562 12,562 12,562
- ---------------------------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item and Cumulative Effect 77,089 151,020 148,548
Extraordinary Item - Net of Tax -- -- (82,548)
Cumulative Effect of Change in Accounting Principle - Net 15,495 -- --
- ---------------------------------------------------------------------------------------------------------------------------------
Net Income After Extraordinary Item and Cumulative Effect 92,584 151,020 66,000
=================================================================================================================================
Dividends on Preferred and Preference Stock 3,411 3,998 4,036
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock, After Extraordinary Item and Cumulative Effect $ 89,173 $ 147,022 $ 61,964
=================================================================================================================================
See notes to consolidated financial statements.
13
Consolidated Balance Sheet
- -----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
---------------------------
As of December 31,
---------------------------
ASSETS 2000 1999
- -----------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment:
Electric plant in service $1,853,043 $ 3,855,390
Construction work in progress 57,462 69,343
Property held under capital leases 19,321 25,998
Other 35,286 8,505
- -----------------------------------------------------------------------------------------------------------------
Gross property, plant and equipment 1,965,112 3,959,236
Less: Accumulated depreciation and amortization (620,767) (2,500,719)
- -----------------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment - Net 1,344,345 1,458,517
- -----------------------------------------------------------------------------------------------------------------
Long-Term Investments:
Investment in DQE common stock 41,306 52,536
Other investments 8,253 28,355
- -----------------------------------------------------------------------------------------------------------------
Total Long-Term Investments 49,559 80,891
- -----------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments 173,524 16,068
- -----------------------------------------------------------------------------------------------------------------
Receivables:
Electric customer accounts receivable 134,187 82,314
DQE loan receivable 250,000 --
Other utility receivables 16,578 32,582
Other receivables 33,752 25,481
Less: Allowance for uncollectible accounts (9,813) (8,730)
- -----------------------------------------------------------------------------------------------------------------
Total Receivables - Net 424,704 131,647
- -----------------------------------------------------------------------------------------------------------------
Materials and supplies (at average cost):
Operating and construction 24,077 37,536
Coal -- 17,705
- -----------------------------------------------------------------------------------------------------------------
Total Materials and Supplies 24,077 55,241
- -----------------------------------------------------------------------------------------------------------------
Other current assets 28,969 55,893
- -----------------------------------------------------------------------------------------------------------------
Total Current Assets 651,274 258,849
- -----------------------------------------------------------------------------------------------------------------
Other Non-Current Assets:
Transition costs 396,379 2,008,171
Regulatory assets 326,581 224,002
Divestiture costs -- 218,653
Other 9,470 32,329
- -----------------------------------------------------------------------------------------------------------------
Total Other Non-Current Assets 732,430 2,483,155
- -----------------------------------------------------------------------------------------------------------------
Total Assets $2,777,608 $ 4,281,412
=================================================================================================================
See notes to consolidated financial statements.
14
Consolidated Balance Sheet
- -----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
---------------------------
As of December 31,
---------------------------
CAPITALIZATION AND LIABILITIES 2000 1999
- -----------------------------------------------------------------------------------------------------------------
Capitalization:
Common stock (authorized - 90,000,000 shares, issued and outstanding - 10 shares) $ -- $ --
Capital surplus 483,275 746,051
Retained earnings 47,104 39,931
Accumulated other comprehensive income 9,178 12,692
- -----------------------------------------------------------------------------------------------------------------
Total Common Stockholder's Equity 539,557 798,674
- -----------------------------------------------------------------------------------------------------------------
Non-redeemable Monthly Income Preferred Securities 150,000 150,000
Non-redeemable preferred stock 60,608 65,108
Non-redeemable preference stock 18,028 25,279
- -----------------------------------------------------------------------------------------------------------------
Total preferred and preference stock before deferred ESOP benefit 228,636 240,387
Deferred employee stock ownership plan (ESOP) benefit (6,583) (10,875)
- -----------------------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock 222,053 229,512
- -----------------------------------------------------------------------------------------------------------------
Long-term debt 1,060,834 1,410,754
- -----------------------------------------------------------------------------------------------------------------
Total Capitalization 1,822,444 2,438,940
- -----------------------------------------------------------------------------------------------------------------
Obligations Under Capital Leases 10,319 16,534
- -----------------------------------------------------------------------------------------------------------------
Current Liabilities:
Accounts payable 107,477 92,266
Accrued liabilities 34,644 102,694
Dividends declared 18,035 29,343
Current debt maturities 795 399,759
Notes payable -- 136,594
Other 27,173 1,030
- -----------------------------------------------------------------------------------------------------------------
Total Current Liabilities 188,124 761,686
- -----------------------------------------------------------------------------------------------------------------
Non-Current Liabilities:
Deferred income taxes - net 568,674 760,677
Warwick mine liability 40,110 49,308
Deferred income -- 93,246
Other 147,937 161,021
- -----------------------------------------------------------------------------------------------------------------
Total Non-Current Liabilities 756,721 1,064,252
- -----------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes B through M)
- -----------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $2,777,608 $4,281,412
=================================================================================================================
See notes to consolidated financial statements.
15
Statement of Consolidated Cash Flows
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------------
Year Ended December 31,
------------------------------------------
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income $ 92,584 $ 151,020 $ 66,000
Principal non-cash charges (credits) to net income:
Depreciation and amortization 308,154 172,424 204,204
Capital lease, nuclear fuel and investment amortization 4,156 35,216 49,547
Gain on disposition of investments -- (7,573) (1,322)
Investment income (2,995) (34,753) (66,552)
Extraordinary items, net -- -- 82,548
Cumulative effect of a change in accounting principles - net (15,495) -- --
Deferred taxes (109,006) 12,578 34,151
Changes in working capital other than cash (5,491) (27,536) 36,300
Other (33,908) 13,816 (81,727)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 237,999 315,192 323,149
- ---------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Proceeds from sale of generation assets, net of
federal income tax payment of $157,424 1,547,607 -- --
Proceeds from disposition of investments 21,144 20,149 1,322
Funding of nuclear decommissioning trust -- (59,861) (8,878)
Long-term investments -- (2,289) (26,172)
Acquisition (32,000) -- --
Capitalized divestiture costs (78,752) (47,449) --
Construction expenditures (89,774) (100,280) (118,447)
Loan to DQE (250,000) -- --
Other (13,684) 5,168 11,836
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided From (Used In) Investing Activities 1,104,541 (184,562) (140,339)
- ---------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Reductions of long-term obligations:
Capital leases (110) (42,423) (12,897)
Long-term debt (749,236) (75,000) (198,172)
Dividends on capital stock (285,500) (206,997) (211,954)
Commercial paper (136,594) 136,594 --
Issuance of debt -- 290,000 140,000
Beaver Valley lease termination -- (277,226) --
Other (13,644) 7,339 (11,805)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used In Financing Activities (1,185,084) (167,713) (294,828)
- ---------------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash 157,456 (37,083) (112,018)
Cash, beginning of period 16,068 53,151 165,169
- ---------------------------------------------------------------------------------------------------------------------------------
Cash, End of Period $ 173,524 $ 16,068 $ 53,151
=================================================================================================================================
Supplemental Cash Flow Information
- ---------------------------------------------------------------------------------------------------------------------------------
Cash paid during the year for:
Interest (net of amount capitalized) $ 79,054 $ 76,950 $ 78,046
- ---------------------------------------------------------------------------------------------------------------------------------
Income taxes $ 290,431 $ 83,962 $ 117,094
- ---------------------------------------------------------------------------------------------------------------------------------
Non-cash investing and financing activities:
Dividend of subsidiary companies' assets $ (61,578) $ -- $ --
Assumption of debt in conjunction with Beaver Valley 2 lease termination $ -- $ 359,236 $ --
Capital lease obligations recorded $ -- $ -- $ 7,855
- ---------------------------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
16
Statement of Consolidated Comprehensive Income
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------------
Year Ended December 31,
------------------------------------------
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
Net income $ 92,584 $ 151,020 $ 66,000
Other comprehensive income:
Unrealized holding gains (losses) arising during the year,
net of tax of $(2,492), $(6,387) and $5,426 (3,514) (9,005) 7,651
- ---------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 89,070 $ 142,015 $ 73,651
=================================================================================================================================
See notes to consolidated financial statements.
Statement of Consolidated Retained Earnings
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------------
Year Ended December 31,
------------------------------------------
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at beginning of year $ 39,931 $ 27,646 $ 172,682
Net income 92,584 151,020 66,000
Dividends declared 85,411 138,735 211,036
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at End of Year $ 47,104 $ 39,931 $ 27,646
=================================================================================================================================
See notes to 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. On April 28, 2000, we sold our generation
assets to Orion Power MidWest, L.P. for approximately $1.7 billion. (See
"Generation Divestiture," Note F, on page 20.)
Our various subsidiaries are primarily involved in operating our automated
meter reading technology and providing financing to certain affiliates.
All material intercompany balances and transactions have been eliminated in
the preparation of the consolidated financial statements.
DQE's Strategic Review Process
As announced on December 6, 2000, DQE has commenced a comprehensive, market-
based strategic and financial review of its entire company and the component
businesses. With a primary focus on maximizing shareholder value, this review
could result in the divestiture of some or all of the component businesses,
including the sale of DQE itself. The review process is expected to be completed
during the second quarter of 2001.
Basis of Accounting
We are subject to the accounting and reporting requirements of the Securities
and Exchange Commission (SEC). Our electric utility operations are also 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 F, on page 20), 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, 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
balance of transition costs was adjusted by receipt of the generation asset sale
proceeds during the second quarter of 2000. 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
17
electric utility customers through the ratemaking process. (See "Rate Matters,"
Note F, on page 20.) These regulatory assets consist of a regulatory tax
receivable of approximately $286.0 million, unamortized debt costs of
approximately $30.4 million, and deferred employee costs of approximately $10.2
million.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America 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 also may be affected by the estimates and
assumptions management is required to make. Actual results could differ from
those estimates.
Revenues from Utility Sales
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 historically
sold electricity to other utilities. (See "Generation Divestiture" discussion,
Note F, on page 20.) Our meters are read monthly and electric utility customers
are billed on the same basis. On January 1, 2000, we adopted the policy of
recording unbilled customer revenues to better reflect the revenues generated
from the amount of energy supplied and delivered to electric utility customers
in a given accounting period. Previously, revenues from electric utility
customers were recorded in the accounting period for which they were billed.
Revenues recorded now reflect actual customer usage in an accounting period,
regardless of when billed. The effect of this new policy is reflected on the
income statement, net of tax and associated expenses, as a cumulative effect of
a change in accounting principle in 2000.
Maintenance
Effective January 1, 1999, as a result of the PUC's final restructuring order,
all electric utility maintenance costs are expensed as incurred. Historically,
incremental maintenance costs incurred for refueling outages at our nuclear
units (which all were acquired by FirstEnergy Corp. in the December 1999 power
station exchange) were deferred for amortization over the period between
refueling outages (generally 18 months). We would accrue, over the periods
between outages, anticipated costs for scheduled major fossil generating station
outages. Maintenance costs incurred for non-major scheduled outages and for
forced outages were charged to expense as such costs were incurred. Subsequent
to the generation asset sale, all electric utility maintenance costs now relate
to transmission and distribution, and are expensed as incurred.
Depreciation and Amortization
Depreciation of utility property, plant and equipment is recorded on a
straight-line basis over the estimated remaining useful lives of properties.
Depreciation expense of $58.6 million, $62.6 million and $152.6 million was
recorded in 2000, 1999 and 1998. Depreciation and amortization of other
properties are calculated on various bases. Amortization of transition costs
represents the difference between CTC revenues billed to customers (net of gross
receipts tax) and the allowed return on our unrecovered net transition cost
balance (11 percent pre-tax).
In 1998 we recorded nuclear decommissioning costs under the category of
depreciation and amortization expense, and accrued a liability, equal to that
amount, for nuclear decommissioning expense. In 1999, these costs are included
in transition cost amortization.
Income Taxes
We use the liability method in computing deferred taxes on all differences
between book and tax bases of assets. These book/tax differences occur when
events and transactions recognized for financial reporting purposes are not
recognized in the same period for tax purposes. The deferred tax liability or
asset is also adjusted in the period of enactment for the effect of changes in
tax laws or rates.
For the electricity delivery business segment, we recognize a regulatory asset
for deferred tax liabilities that are expected to be recovered from customers
through rates. (See "Rate Matters," Note F, and "Income Taxes," Note H, on pages
20 and 21.) Reversals of accumulated deferred income taxes are included in
income tax expense.
Other Operating Revenues and Other Income
Other operating revenues include non-kilowatt-hour (KWH) electric utility
revenues in 1999 and 1998 from the joint owners of Beaver Valley Units 1 and 2
for their share of administrative and general costs of operating those units
(now owned by FirstEnergy following the power station exchange).
Other income primarily is made up of income from long-term investments entered
into by subsidiaries. The income is separated from other revenues, as the
investment income does not result from operating activities.
18
Receivables
Receivables on the balance sheet are comprised of outstanding billings for
electric customers and other utilities. In addition, at December 31, 2000,
electric customer receivables reflects a $41.5 million accrual for the
cumulative effect of a change in accounting principle for unbilled revenues.
Property, Plant and Equipment
The asset values of our utility properties are stated at original construction
cost, which includes related payroll taxes, pensions and other fringe benefits,
as well as administrative costs. Also included in original construction cost is
an allowance for funds used during construction (AFC), which represents the
estimated cost of debt and equity funds used to finance construction.
Additions to, and replacements of, property units are charged to plant
accounts. Maintenance, repairs and replacement of minor items of property are
recorded as expenses when they are incurred. The costs of electricity delivery
business segment properties that are retired (plus removal costs and less any
salvage value) are charged to accumulated depreciation and amortization.
The asset values of the electricity supply business segment properties, as
reflected on the balance sheet as of December 31, 1999, were written down to
market value in conjunction with the PUC's final restructuring order.
Substantially all of the electric utility properties are subject to a first
mortgage lien.
Temporary Cash Investments
Temporary cash investments are short-term, highly liquid investments with
original maturities of three or fewer months. They are stated at market, which
approximates cost. We consider temporary cash investments to be cash
equivalents.
Stock-Based Compensation
We account for stock-based compensation using the intrinsic value method
prescribed in APB Opinion No. 25, Accounting for Stock Issued to Employees, and
related interpretations. Accordingly, compensation cost for stock options is
measured as the excess, if any, of the quoted market price of DQE common stock
at the date of the grant over the amount any employee must pay to acquire the
stock. Compensation cost for stock appreciation rights is recorded based on the
quoted market price of the stock at the end of the year.
Reclassification
The 1999 and 1998 consolidated financial statements have been reclassified to
conform with the 2000 presentation.
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities. This
statement, which became effective for us on January 1, 2001, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts (collectively referred to as
derivatives), and for hedging activities. We have evaluated the impact on our
financial statements and have determined that the adoption of this statement
will not have a material impact on our results of operations, financial position
or cash flows.
B. CHANGES IN WORKING CAPITAL OTHER THAN CASH
Changes in Working Capital Other than Cash (Net of Dispositions and
Acquisitions) for the Year Ended December 31,
- -----------------------------------------------------------------------------
(Thousands of Dollars)
---------------------------------------
2000 1999 1998
- -----------------------------------------------------------------------------
Receivables $ (2,976) $ (1,695) $ (3,981)
Materials and supplies (8,878) 37,128 (10,943)
Other current assets 27,115 (26,567) (192)
Accounts payable (761) (13,132) 29,400
Other current liabilities (19,991) (23,270) 22,016
- -----------------------------------------------------------------------------
Total $ (5,491) $(27,536) $ 36,300
=============================================================================
C. PROPERTY, PLANT AND EQUIPMENT
On April 28, 2000, we sold our generation assets. We own 9 transmission
substations and 561 distribution substations (367 of which are located on
customer-owned land and are used to service only those customers). We have 592
circuit-miles of transmission lines, comprised of 345,000, 138,000 and 69,000
volt lines. Street lighting and distribution circuits of 23,000 volts and less
include approximately 16,420 circuit-miles of lines and cable. These properties
are used in the electricity delivery business segment.
We own, but do not operate, the Warwick Mine, including 4,849 acres owned in
fee of unmined coal lands and mining rights, located on the Monongahela River in
Greene County, Pennsylvania. Mining operations ceased in March 2000, and
reclamation commenced in April 2000. This property had been used in the
electricity supply business segment.
19
D. LONG-TERM INVESTMENTS
At December 31, 2000 and 1999, the fair market value of our investment in DQE
common stock was $41.3 million and $52.5 million, and the cost of our investment
was $25.6 million and $30.8 million.
Deferred income, as shown on the consolidated balance sheet at December 31,
1999, primarily relates to certain gas reserve investments. These assets were
dividended to DQE during 2000.
E. ACQUISITIONS AND DISPOSITIONS
In March 2000, we purchased the Customer Advanced Reliability System (CARS)
from Itron, Inc., which had developed this automated electronic meter reading
system for use with our electric utility customers. We had previously leased
these assets.
On April 28, 2000, we completed the sale of our generation assets to Orion for
approximately $1.7 billion. (See "Generation Divestiture" discussion, Note F,
below.) Additionally, we dividended two of our non-electric subsidiaries to DQE
in 2000.
F. 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 Customer Choice Act enables Pennsylvania's electric utility customers to
shop, purchasing electricity at market prices from a variety of electric
generation suppliers (customer choice). All customers now have customer choice.
As of February 28, 2001, approximately 30.8 percent of our customers had chosen
alternative generation suppliers, representing approximately 25.6 percent of our
non-coincident peak load. The remaining customers are provided with electricity
through our provider of last resort service arrangement with Orion (discussed
below). Recently, two alternative generation suppliers have decided to exit the
retail supply business, which is expected to increase the number of customers
participating in our provider of last resort service.
Customers who select an alternative generation supplier pay for generation
charges set competitively by that supplier, and pay us for the CTC and
transmission and distribution charges. Electricity delivery (including
transmission, distribution and customer service) remains regulated in
substantially the same manner as under historical regulation.
Generation Divestiture
On December 3, 1999, we completed the exchange of our partial interests in
five power plants for three wholly owned power plants from FirstEnergy. In
connection with this exchange, we terminated the $359.2 million Beaver Valley
Unit 2 lease in the fourth quarter of 1999.
On April 28, 2000, we completed the sale of our generation assets to Orion.
Orion purchased all of our power stations, including those received from
FirstEnergy, for approximately $1.7 billion.
In its final restructuring order issued in the second quarter of 1998, 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. As originally approved, our
transition costs were to be recovered over a seven-year period ending in 2005.
However, due to the success of the generation asset sale to Orion, this recovery
period has been significantly shortened. On January 18, 2001, the PUC issued an
order approving our final accounting for the sale proceeds, including the net
recovery of $276 million of transaction costs related to the generation exchange
and sale. Applying the net generation asset sale proceeds to reduce transition
costs, we now anticipate termination of the CTC collection period in early 2002
for most major rate classes. Rates will then decrease 21 percent for residential
customers who continue to take provider of last resort service from us pursuant
to the second agreement with Orion discussed below. Once the CTC collection
period ends for all rate classes, rates will decrease on average 17 percent
system-wide for provider of last resort customers. 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 that remain following the generation
asset sale was approximately $411 million ($251 million net of tax) at December
31, 2000. A slightly lower amount is shown on the balance sheet due to the
accounting for the cumulative effect of a change in accounting principle for
unbilled revenues. We are allowed to earn an 11 percent pre-tax return on this
net amount.
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
20
who does not choose an alternative generation supplier, or whose supplier fails
to deliver. As part of the generation asset sale, Orion agreed to supply us with
all of the electric energy necessary to satisfy our provider of last resort
obligations during the CTC collection period. On December 20, 2000, the PUC
approved a second agreement that extends Orion's provider of last resort
arrangement (and the PUC-approved rates for the supply of electricity) beyond
the final CTC collection through 2004. The agreement also allows us, following
the CTC collection, an average margin of 0.5 cents per KWH supplied through this
arrangement. Except for this margin, these agreements, in general, effectively
transfer 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.
Rate Freeze
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 agreed to extend this
rate cap for an additional six months through the end of 2001. Subsequently, in
connection with the December 20 provider of last resort 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, 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.
FERC Order No. 2000
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. On October 16, 2000, we informed the FERC of our plan to join a regional
transmission organization at the earliest practicable date. We are actively
negotiating with the Pennsylvania-New Jersey-Maryland Interconnection to
establish the PJM West regional transmission organization. Our ultimate decision
will depend in part on the outcome of DQE's strategic review process.
G. SHORT-TERM BORROWING AND REVOLVING CREDIT ARRANGEMENTS
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 December 31, 2000 and 1999,
no borrowings were outstanding. At December 31, 2000, we were in compliance with
all of our financial covenants. During 2000, the maximum amount of bank loans
and commercial paper borrowings outstanding was $189.5 million, the amount of
average daily borrowings was $7.0 million, and the weighted average daily
interest rate was 6.0 percent.
H. INCOME TAXES
We file consolidated tax returns with DQE and other companies in the
affiliated group. The annual federal corporate income tax returns have been
audited by the Internal Revenue Service (IRS) and are closed for the tax years
through 1992. The years 1993 and 1994 are completed and under appeal with the
IRS. The IRS is auditing our 1995 through 1997 returns, and the tax years 1998
and 1999 remain subject to IRS review. We do not believe that final settlement
of the federal income tax returns for the years 1993 through 1999 will have a
materially adverse effect on our financial position, results of operations or
cash flows.
Deferred Tax Assets (Liabilities) at December 31,
- ---------------------------------------------------------------------
(Thousands of Dollars)
------------------------------
2000 1999
- ---------------------------------------------------------------------
Warwick Mine closing costs $ 16,643 $ 20,460
Tax benefit -- long term
investments -- 75,275
Unbilled revenue -- 12,475
Other 4,921 83,452
- ---------------------------------------------------------------------
Deferred tax assets 21,564 191,662
- ---------------------------------------------------------------------
Property depreciation (320,234) (403,354)
Transition costs (138,733) (442,271)
Regulatory assets (118,670) (76,091)
Deferred coal and energy costs -- (17,379)
Loss on reacquired
debt unamortized (12,601) (13,244)
- ---------------------------------------------------------------------
Deferred tax liabilities (590,238) (952,339)
- ---------------------------------------------------------------------
Net $(568,674) $(760,677)
=====================================================================
21
Income Taxes
- ---------------------------------------------------------------------
(Thousands of Dollars)
--------------------------------------
Year Ended December 31,
--------------------------------------
2000 1999 1998
- ---------------------------------------------------------------------
Currently payable:
Federal $ 298,941 $ 95,815 $ 93,493
State -- 28,453 25,599
Deferred - net:
Federal (271,626) (25,130) (31,642)
State 161 (8,048) 2,211
ITC deferred - net -- (2,844) (7,166)
- ---------------------------------------------------------------------
Total Included in
Operating Expenses $ 27,476 $ 88,246 $ 82,495
- ---------------------------------------------------------------------
Included in other
income and deductions:
Federal $ 14,105 $ (35,991) $ (62,409)
State -- (490) (757)
Deferred - net:
Federal -- 48,623 73,968
State -- -- --
ITC -- (23) (3,220)
- ---------------------------------------------------------------------
Total Included in
Other Income and
Deductions 14,105 12,119 7,582
- ---------------------------------------------------------------------
Total Income
Tax Expense $ 41,581 $ 100,365 $ 90,077
=====================================================================
Total income taxes differ from the amount computed by applying the statutory
federal income tax rate to income before income taxes, as set forth in the
following table.
Income Tax Expense Reconciliation
- ---------------------------------------------------------------------
(Thousands of Dollars)
--------------------------------------
Year Ended December 31,
--------------------------------------
2000 1999 1998
- ---------------------------------------------------------------------
Federal taxes at
statutory rate (35%) $ 41,535 $ 87,985 $ 83,519
Increase (decrease) in
taxes resulting from:
State income taxes 105 12,945 16,639
Investment tax benefits -- (270) (641)
Amortization of
deferred ITC -- (2,867) (10,385)
Other (59) 2,572 945
- ---------------------------------------------------------------------
Total Income
Tax Expense $ 41,581 $100,365 $ 90,077
=====================================================================
I. LEASES
We lease office buildings, computer equipment, and other property and
equipment. For most of 1999, we also leased nuclear fuel and a portion of Beaver
Valley Unit 2 power station.
Capital Leases at December 31,
- ----------------------------------------------------------------------
(Thousands of Dollars)
--------------------------
2000 1999
- ----------------------------------------------------------------------
Electric plant $19,321 $19,632
Other -- 6,366
- ----------------------------------------------------------------------
Total 19,321 25,998
Less: Accumulated amortization (6,753) (7,649)
- ----------------------------------------------------------------------
Capital Leases - Net (a) $12,568 $18,349
======================================================================
(a) Includes $1,479 in 2000 and $1,746 in 1999 of capital leases with associated
obligations retired.
In 1987, we sold and leased back our 13.74 percent interest in Beaver Valley
Unit 2; the sale was exclusive of transmission and common facilities. In
conjunction with the PUC restructuring order, it was determined that costs
related to the lease were transition costs to be recovered through the CTC. We
terminated the lease in connection with the power station exchange with
FirstEnergy.
Summary of Rental Expense
- -------------------------------------------------------------------
(Thousands of Dollars)
--------------------------------
Year Ended December 31,
--------------------------------
2000 1999 1998
- -------------------------------------------------------------------
Operating leases $18,143 $51,723 $57,324
Amortization of capital leases 711 18,889 12,943
Interest on capital leases 775 1,512 2,955
- -------------------------------------------------------------------
Total Rental Payments $19,629 $72,124 $73,222
===================================================================
Future Minimum Lease Payments
- ----------------------------------------------------------------------
(Thousands of Dollars)
--------------------------
Operating Capital
Year Ended December 31, Leases Leases
- ----------------------------------------------------------------------
2001 $11,732 $ 739
2002 11,605 739
2003 3,117 739
2004 1,913 739
2005 and thereafter 3 2,219
- ----------------------------------------------------------------------
Total $28,370 $ 5,175
Less: Amount representing interest (1,673)
- ----------------------------------------------------------------------
Present value (a) $ 3,502
======================================================================
(a) Includes current obligations of $0.4 million at December 31, 2000.
Future minimum lease payments for operating leases are related principally to
certain corporate offices. Future minimum lease payments for capital leases are
related principally to building leases.
Future payments due to us as of December 31, 2000, under subleases of certain
corporate office space, are approximately $6.6 million in each of the years
2001, 2002 and 2003.
22
J. COMMITMENTS AND CONTINGENCIES
Construction
We estimate that we will spend, excluding AFC, approximately $61 million for
each of 2001, 2002 and 2003 for electric utility construction.
Employees
We have renegotiated our labor contract with the International Brotherhood of
Electrical Workers (IBEW), which represents the majority of our employees. The
contract has been extended through 2002 or 2003, depending on the outcome of
DQE's strategic review process, and provides, among other things, employment
security and income protection.
Other
In 1992, the Pennsylvania Department of Environmental Protection (DEP) issued
Residual Waste Management Regulations governing the generation and management of
non-hazardous residual waste, such as coal ash. Following the generation asset
divestiture, we retained certain facilities which remain subject to these
regulations. We have assessed our residual waste management sites, and the DEP
has approved our compliance strategies. We incurred costs of $2 million in 2000
to comply with these DEP regulations. We expect the costs of compliance to be
approximately $1.5 million over the next two years with respect to sites we will
continue to own. These costs are being recovered in the CTC, and the
corresponding liability has been recorded for current and future obligations.
Our current estimated liability for closing Warwick Mine, including final site
reclamation, mine water treatment and certain labor liabilities, is
approximately $40 million. We have recorded a liability for this amount on the
consolidated balance sheet.
We are involved in various other legal proceedings and environmental matters.
We believe that such proceedings and matters, in total, will not have a
materially adverse effect on our financial position, results of operations or
cash flows.
K. LONG-TERM DEBT
Long-Term Debt at December 31,
- ------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------
Interest Principal Outstanding
Rate Maturity 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
First mortgage bonds (a) 6.450%-8.375% 2003-2038 $ 643,000 $ 643,000 (c)
Pollution control notes Adjustable (b) 2009-2030 417,985 417,985
Sinking fund debentures 5.00% 2010 2,791 2,791
Collateralized lease bonds 8.70% 2001-2016 -- 350,162 (d)
Less: Unamortized debt discount and premium - net (2,942) (3,184)
- ------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt $1,060,834 $1,410,754
==============================================================================================================================
(a) Includes $100 million of first mortgage bonds not callable until 2003.
(b) The pollution control notes have adjustable interest rates. The interest
rates at year-end averaged 4.7 percent in 2000 and 3.8 percent in 1999.
(c) Excludes $390 million related to current maturities during 2000.
(d) Excludes $9.1 million related to current maturities during 2000.
At December 31, 2000, there were no sinking fund requirements or maturities of
long-term debt outstanding for 2001 and 2002. Sinking fund requirements and
maturities of long-term debt for 2003 through 2005 were $100.0 million in 2003,
$100.4 million in 2004 and $0.4 million in 2005.
Total interest and other charges were $74.7 million in 2000, $118.7 million in
1999 and $80.2 million in 1998. Interest costs attributable to debt were $73.5
million, $79.5 million and $81.1 million in 2000, 1999 and 1998. Of these
amounts, $2.1 million in 2000, $0.8 million in 1999 and $2.2 million in 1998
were capitalized as AFC. Debt discount or premium and related issuance expenses
are amortized over the lives of the applicable issues. Interest and other
charges in 1999 also includes $35.2 million related to the Beaver Valley Unit 2
lease expense, previously classified as other operating expenses.
At December 31, 2000, the fair value of long-term debt, including current
maturities and sinking fund requirements, estimated on the basis of quoted
market prices for the same or similar issues, or current rates offered for debt
of the same remaining maturities, was $1,027 million. The principal amount
included in the consolidated balance sheet, excluding unamortized discounts and
premiums, is $1,064 million.
At December 31, 2000 and 1999, we were in compliance with all of our debt
covenants.
23
L. PREFERRED AND PREFERENCE STOCK
Preferred and Preference Stock at December 31,
- ------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------------------------------------
2000 1999
Call Price --------------------------------------------------------
Per Share Shares Amount Shares Amount
- ------------------------------------------------------------------------------------------------------------------------------
Preferred Stock Series:
3.75% (a) $51.00 148,000 7,407 148,000 7,407
4.00% (a) 51.50 549,709 27,486 549,709 27,486
4.10% (a) 51.75 119,860 6,012 119,860 6,012
4.15% (a) 51.73 132,450 6,643 132,450 6,643
4.20% (a) 51.71 100,000 5,021 100,000 5,021
$2.10 (a) 51.84 159,400 8,039 159,400 8,039
9.00% (b) -- -- -- 10 3,000
8.375% (c) -- 6,000,000 150,000 6,000,000 150,000
6.5% (d) -- -- -- 15 1,500
- ------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock 210,608 215,108
- ------------------------------------------------------------------------------------------------------------------------------
Preference Stock Series:
Plan Series A (e) 35.78 579,276 18,028 752,018 25,279
- ------------------------------------------------------------------------------------------------------------------------------
Deferred ESOP benefit (6,583) (10,875)
- ------------------------------------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock $222,053 $229,512
==============================================================================================================================
(a) 4,000,000 authorized shares; $50 par value; cumulative; $50 per share
involuntary liquidation value 3.6 percent to 4.3
(b) 500 authorized shares; $300,000 par value; these shares were redeemed at par
value on March 2, 2000
(c) Cumulative Monthly Income Preferred Securities, Series A (MIPS); 6,000,000
authorized shares; $25 involuntary liquidation value
(d) 1,500 authorized shares; $100,000 par value; $100,000 involuntary
liquidation value; holders entitled to 6.5 percent annual dividend each
September
(e) 8,000,000 authorized shares; $1 par value; cumulative; $35.50 per share
involuntary liquidation value
Duquesne Capital L.P., a special-purpose limited partnership of which we are
the sole general partner, has outstanding $150.0 million principal amount of
8 3/8 percent Monthly Income Preferred Securities (MIPS) Series A, with a stated
liquidation value of $25.00. The holders of MIPS are entitled to annual
dividends of 8 3/8 percent, payable monthly. The sole assets of Duquesne Capital
are our 8 3/8 percent debentures. We have the option to redeem these securities
on or after May 31, 2001. Although we have no current plans to redeem, we are
evaluating our options. We have guaranteed the payment of distributions on, and
redemption price and liquidation amount in respect of the MIPS, if Duquesne
Capital has funds available for such payment from the debt securities. Upon
maturity or prior redemption of such debt securities, the MIPS will be
mandatorily redeemed.
Holders of our preferred stock are entitled to cumulative quarterly dividends.
If four quarterly dividends on any series of preferred stock are in arrears,
holders of the preferred stock are entitled to elect a majority of our board of
directors until all dividends have been paid. As previously reported, on
November 2, 2000, we made a preliminary SEC filing regarding a potential tender
offer for the preferred stock. Holders of our preference stock are entitled to
receive cumulative quarterly dividends, if dividends on all series of preferred
stock are paid. If six quarterly dividends on any series of preference stock are
in arrears, holders of the preference stock are entitled to elect two of our
directors until all dividends have been paid. At December 31, 2000, we had made
all dividend payments. Preferred and preference dividends were $16.0 million in
2000 and $16.6 million 1999 and 1998. Total preferred and preference stock had
involuntary liquidation values of $231.0 million and $242.6 million, which
exceeded par by $20.0 million and $26.9 million, at December 31, 2000 and 1999.
Although outstanding preferred stock is generally callable on notice of not
less than 30 days, at stated prices plus accrued dividends, the outstanding MIPS
and preference stock are not currently callable. None of our remaining preferred
or preference stock issues has mandatory purchase requirements.
We have an Employee Stock Ownership Plan (ESOP) to provide matching
contributions for a 401(k) Retirement Savings Plan for Management Employees.
(See "Employee Benefits," Note N, on page 25.) We issued and sold 845,070 shares
of preference stock, plan series A to the trustee of the ESOP. As consideration
for the stock, we received a note valued at $30 million from the trustee.
24
The preference stock has an annual dividend rate of $2.80 per share, and each
share of the preference stock is exchangeable for one and one-half shares of DQE
common stock. At December 31, 2000, $6.6 million of preference stock issued in
connection with the establishment of the ESOP had been offset, for financial
statement purposes, by the recognition of a deferred ESOP benefit. Dividends on
the preference stock and cash contributions from DQE are used to fund the
repayment of the ESOP note. We made cash contributions of approximately $1.0
million and $0.2 million for 2000 and 1999. We were not required to make a cash
contribution for 1998. These cash contributions were the difference between the
ESOP debt service and the amount of dividends on ESOP shares ($1.7 million in
2000, $2.1 million in 1999 and $2.2 million in 1998). As shares of preference
stock are allocated to the accounts of participants in the ESOP, we recognize
compensation expense, and the amount of the deferred compensation benefit is
amortized. We recognized compensation expense related to the 401(k) plans of
$3.6 million in 2000 and 1999 and $1.6 million in 1998.
M. EQUITY
In July 1989, we became a wholly owned subsidiary of DQE, whose common stock
replaced the outstanding shares of our common stock, except for the 10 shares
DQE holds.
Payments of dividends on our common stock may be restricted by obligations to
holders of our preferred and preference stock, pursuant to our Restated Articles
of Incorporation, and by obligations of a subsidiary to holders of its preferred
securities. No dividends or distributions may be made on our common stock if we
have not paid dividends or sinking fund obligations on our preferred or
preference stock. Further, the aggregate amount of our common stock dividend
payments or distributions may not exceed certain percentages of net income, if
the ratio of total common shareholder's equity to total capitalization is less
than specified percentages. Because DQE owns all of our common stock, if we
cannot pay common dividends, DQE may not be able to pay dividends on its common
or preferred stock. No part of our retained earnings was restricted at December
31, 2000.
Following is a table describing our accumulated other comprehensive income.
Accumulated Other Comprehensive Income
Balances as of December 31,
- ------------------------------------------------------------------
(Thousands of Dollars)
----------------------------
2000 1999
- ------------------------------------------------------------------
January 1 $12,692 $ 21,697
Unrealized gains, net of tax
of $(2,492) and $(6,387) (3,514) (9,005)
- ------------------------------------------------------------------
December 31 $ 9,178 $ 12,692
==================================================================
N. EMPLOYEE BENEFITS
Pension and Postretirement Benefits
We maintain retirement plans to provide pensions for all eligible employees.
Upon retirement, an eligible employee receives a monthly pension based on his or
her length of service and compensation. The cost of funding the pension plans is
determined by the unit credit actuarial cost method. Our policy is to record
this cost as an expense and to fund the pension plans by an amount that is at
least equal to the minimum funding requirements of the Employee Retirement
Income Security Act of 1974, but which does not exceed the maximum tax-
deductible amount for the year. As a result, we were able to record a credit of
$13.5 million to expense or construction for pension costs in 2000. Pension
costs charged to expense or construction were $11.2 million for 1999 and $12.0
million for 1998.
In 1999, we offered an early retirement program for certain employees affected
by the generation asset divestiture. The total increase in the projected benefit
obligation to the retirement plans is estimated to be $29.4 million. Of this
amount, $17.4 million was recognized in 1999 as special termination benefits in
the table on the next page. The remaining $12.0 million was reflected in the
unrecognized actuarial gain/loss account in the table. In its January 18, 2001
order approving our final generation asset sale proceeds accounting, the PUC
also approved recovery of costs associated with the early retirement program.
These recovered costs are to be contributed to the pension plans over future
years.
In addition to pension benefits, we provide certain health care benefits and
life insurance for some retired employees. The life insurance plan is non-
contributory. Participating retirees make contributions, which may be adjusted
annually, to the health care plan. Health care benefits terminate when retirees
reach age 65. We fund actual expenditures for obligations under the plans on a
"pay-as-you-go" basis. We have the right to modify or terminate the plans.
25
We accrue the actuarially determined costs of the aforementioned
postretirement benefits over the period from the date of hire until the date the
employee becomes fully eligible for benefits. We have elected to amortize the
transition obligation over a 20-year period.
We sponsor several qualified and nonqualified pension plans and other
postretirement benefit plans for our employees. The following tables provide a
reconciliation of the changes in the plans' benefit obligations and fair value
of plan assets over the two-year period ending December 31, 2000, a statement of
the funded status as of December 31, 2000 and 1999, and a summary of assumptions
used in the measurement of our benefit obligation:
Funded Status of the Pension and Postretirement Benefit Plans at December 31,
- -----------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------------------------------
Pension Postretirement
-----------------------------------------------------
2000 1999 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of year $ 578,726 $ 605,597 $ 57,558 $ 46,358
Service cost 6,230 14,374 979 1,800
Interest cost 39,574 39,929 2,837 3,100
Actuarial (gain) loss (24,142) (77,348) (7,547) 4,206
Benefits paid (36,810) (29,533) (3,749) (2,306)
Plan amendments -- -- (1,613) --
Curtailments (gain) loss (17,546) 8,372 (21,948) 4,400
Settlements (291) (41) -- --
Special termination benefits 732 17,376 5,343 --
- -----------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year 546,473 578,726) 31,860 57,558
- -----------------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of year 744,155 681,244 -- --
Actual return on plan assets 24,465 92,331 -- --
Employer contributions -- -- -- --
Benefits paid (36,394) (29,420) -- --
- -----------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 732,226 744,155 -- --
- -----------------------------------------------------------------------------------------------------------------------------
Funded status 185,753 165,429 (31,860) (57,558)
Unrecognized net actuarial (gain) loss (272,242) (285,795) (7,187) 5,108
Unrecognized prior service cost (gain) 14,561 32,022 -- --
Unrecognized net transition obligation 4,053 8,109 7,889 21,227
- -----------------------------------------------------------------------------------------------------------------------------
Accrued benefit cost $ (67,875) $ (80,235) $ (31,158) $(31,223)
=============================================================================================================================
Weighted-Average Assumptions as of December 31,
- -----------------------------------------------------------------------------------------------------------------------------
Pension Postretirement
-----------------------------------------------------
2000 1999 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Discount rate used to determine projected
benefits obligation 7.50% 7.50% 7.50% 7.50%
Assumed rate of return on plan assets 7.50% 7.50% -- --
Assumed change in compensation levels 4.25% 4.25% -- --
Ultimate health care cost trend rate -- -- 6.00% 6.00%
26
All of our plans for postretirement benefits, other than pensions, have no
plan assets. The aggregate benefit obligation for those plans was $31.9 million
as of December 31, 2000 and $57.6 million as of December 31, 1999. The
accumulated postretirement benefit obligation comprises the present value of the
estimated future benefits payable to current retirees, and a pro rata portion of
estimated benefits payable to active employees after retirement.
Following the early retirement program offered in 1999 (described previously)
the total increase in the projected benefit obligation of the postretirement
benefits is estimated to be $4.4 million. In 1999, this increase was reflected
in the unrecognized actuarial gain/loss account in the preceding table. The
PUC's January 18, 2001 order approved recovery of the postretirement benefits
costs associated with the early retirement program. The recovered costs are to
be used to offset the postretirement benefits for those employees.
Pension assets consist primarily of common stocks (exclusive of DQE common
stock), United States obligations and corporate debt securities.
Components of Net Pension Cost as of December 31,
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------------------------
2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------------
Components of net pension cost:
Service cost $ 6,230 $ 14,374 $ 14,043
Interest cost 39,574 39,929 37,723
Expected return on plan assets (50,441) (45,562) (41,067)
Amortization of unrecognized net transition obligation 1,148 1,759 1,812
Amortization of prior service cost 2,027 3,458 3,515
Recognized net actuarial gain (12,052) (2,717) (4,014)
- ----------------------------------------------------------------------------------------------------------------------------------
Net pension (gain) cost (13,514) 11,241 12,012
Curtailment cost (gain) 943 (14) --
Settlement cost 287 78 224
Special termination benefits 732 17,376 --
- ----------------------------------------------------------------------------------------------------------------------------------
Net Pension (Gain) Cost After Curtailments,
Settlements and Special Termination Benefits $(11,552) $ 28,681 $ 12,236
==================================================================================================================================
Components of Postretirement Cost as of December 31,
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------------------------
2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------------
Components of postretirement cost:
Service cost $ 979 $ 1,799 $ 1,832
Interest cost 2,837 3,099 3,078
Amortization of unrecognized net transition obligation 925 1,642 1,687
Amortization of prior service costs (7) -- --
Recognized net actuarial gain (16) -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Net postretirement cost 4,718 6,540 6,597
Curtailment (gain) cost (6,377) 2,443 --
Special termination benefits 5,343 -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Net Postretirement Cost After Curtailments $ 3,684 $ 8,983 $ 6,597
==================================================================================================================================
Effect of a One Percent Change in Health Care Cost Trend Rates as of December 31, 2000
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------------------------
One Percent One Percent
Increase Decrease
- ----------------------------------------------------------------------------------------------------------------------------------
Effect on total of service and interest cost components of
net periodic postretirement health care benefit cost $ 394 $ (346)
Effect on the health care component of the accumulated
postretirement benefit obligation $ 2,671 $(2,369)
27
Retirement Savings Plan and Other Benefit Options
We sponsor separate 401(k) retirement plans for our management and IBEW-
represented employees.
The 401(k) Retirement Savings Plan for Management Employees provides for
employer contributions. These contributions may include one or more of the
following: a participant base match and a participant incentive match. In 2000,
all employees eligible for an incentive match achieved their incentive targets.
We are funding our automatic and matching contributions to the 401(k)
Retirement Savings Plan for Management Employees with payments to an ESOP
established in December 1991. (See "Preferred and Preference Stock" Note L, on
page 24.)
The 401(k) Retirement Savings Plan for IBEW Represented Employees
provides that we will match employee contributions with a base match and an
additional incentive match, if certain targets are met. In 2000, all IBEW-
represented employees achieved their incentive targets.
DQE's shareholders have approved a long-term incentive plan through which we
may grant management employees options to purchase, during the years 1987
through 2006, up to a total of 9.9 million shares of DQE common stock at prices
equal to the fair market value of such stock on the dates the options were
granted. At December 31, 2000, approximately 3.1 million of these shares were
available for future grants. The following paragraph sets forth option
information for all DQE affiliates under the plan, including Duquesne Light.
As of December 31, 2000, 1999 and 1998, active grants totaled 1,292,485;
1,031,434 and 1,230,946 shares. Exercise prices of these options ranged from
$17.5834 to $47.3438 at December 31, 2000; from $17.5834 to $43.4375 at December
31, 1999; and from $15.8334 to $43.4375 at December 31, 1998. Expiration dates
of these grants ranged from 2001 to 2010 at December 31, 2000; from 2001 to 2009
at December 31, 1999; and from 2000 to 2008 at December 31, 1998. As of December
31, 2000, 1999 and 1998, stock appreciation rights (SARs) had been granted in
connection with 975,292; 933,014 and 867,104 of the options outstanding. During
2000, 208,236 SARs were exercised; 197,595 options were exercised at prices
ranging from $24.125 to $38.50; and 33,879 options were cancelled. During 1999,
45,265 SARs were exercised; 254,225 options were exercised at prices ranging
from $17.5834 to $35.0625; and 33,000 options were cancelled. During 1998,
233,532 SARs were exercised; 170,476 options were exercised at prices ranging
from $15.8334 to $31.5625; and no options were cancelled. Of the active grants
at December 31, 2000, 1999 and 1998, 495,816; 132,105 and 750,463 were not
exercisable.
O. 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).
28
Business Segments as of December 31,
- -----------------------------------------------------------------------------------------------------------------
(Millions of Dollars)
--------------------------------------------------------
Electricity Electricity Consoli-
Delivery) Supply CTC dated
--------------------------------------------------------
2000
- -----------------------------------------------------------------------------------------------------------------
Operating revenues $ 316.1 $ 425.4 $ 334.4 $1,075.9
Operating expenses 172.5 412.8 39.2 624.5
Depreciation and amortization expense 56.4 2.2 249.6 308.2
- -----------------------------------------------------------------------------------------------------------------
Operating income 87.2 10.4 45.6 143.2
Other income 18.3 2.8 -- 21.1
Interest and other charges 69.5 21.2 -- 90.7
- -----------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock
before accounting change 36.0 (8.0) 45.6 73.6
Cumulative effect of change in
accounting principle 7.3 8.2 -- 15.5
- -----------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 43.3 $ 0.2 $ 45.6 $ 89.1
=================================================================================================================
Assets $2,381.2 $ -- $ 396.4 $2,777.6
=================================================================================================================
Capital expenditures $ 85.1 $ 4.7 $ -- $ 89.8
=================================================================================================================
- -----------------------------------------------------------------------------------------------------------------
(Millions of Dollars)
--------------------------------------------------------
Electricity Electricity Consoli-
Delivery) Supply CTC dated
--------------------------------------------------------
1999
- -----------------------------------------------------------------------------------------------------------------
Operating revenues $ 307.0 $ 528.5 $ 323.3 $1,158.8
Operating expenses 187.0 454.0 85.7 726.7
Depreciation and amortization expense 50.5 26.3 95.6 172.4
- -----------------------------------------------------------------------------------------------------------------
Operating income 69.5 48.2 142.0 259.7
Other income 15.1 7.4 -- 22.5
Interest and other charges 45.9 43.9 45.4 135.2
- -----------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 38.7 $ 11.7 $ 96.6 $ 147.0
=================================================================================================================
Assets $1,628.9 $ 425.7 $2,226.8 $4,281.4
=================================================================================================================
Capital expenditures $ 69.9 $ 30.4 $ -- $ 100.3
=================================================================================================================
29
Business Segments as of December 31,
- ----------------------------------------------------------------------------------------------------------
(Millions of Dollars)
-------------------------------------------------
Electricity Electricity Consoli-
Delivery Supply dated
-------------------------------------------------
1998
- ----------------------------------------------------------------------------------------------------------
Operating revenues $ 323.4 $ 855.3 $1,178.7
Operating expenses 190.8 579.6 770.4
Depreciation and amortization expense 46.1 158.1 204.2
- ----------------------------------------------------------------------------------------------------------
Operating income 86.5 117.6 204.1
Other income 24.3 12.9 37.2
Interest and other charges 38.2 58.6 96.8
- ----------------------------------------------------------------------------------------------------------
Earnings for common stock before extraordinary item 72.6 71.9 144.5
Extraordinary item, net of tax -- (82.6) (82.6)
- ----------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock after extraordinary item $ 72.6 $ (10.7) $ 61.9
==========================================================================================================
Assets $1,598.1 $2,711.5 $4,309.6
==========================================================================================================
Capital expenditures $ 76.8 $ 41.6 $ 118.4
==========================================================================================================
P. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summary of Selected Quarterly Financial Data (Thousands of Dollars, Except Per Share Amounts)
- -----------------------------------------------------------------------------------------------------------------
The quarterly data reflect seasonal weather variations in the electric utility's service territory.
- -----------------------------------------------------------------------------------------------------------------
2000 (a) First Quarter Second Quarter Third Quarter Fourth Quarter
- -----------------------------------------------------------------------------------------------------------------
Operating revenues $258,021 $272,885 $296,548 $248,410
Operating income 57,268 19,318 26,982 39,603
Income before cumulative effect of a
change in accounting principle 37,664 3,593 9,215 26,617
Net income $ 53,159 $ 3,593 $ 9,215 $ 26,617
=================================================================================================================
1999 (b) First Quarter Second Quarter Third Quarter Fourth Quarter
- -----------------------------------------------------------------------------------------------------------------
Operating revenues $281,976 $273,239 $336,165 $267,420
Operating income 49,397 54,478 65,236 90,653
Net income $ 35,868 $ 28,576 $ 37,040 $ 49,536
=================================================================================================================
(a) Restated to reflect the cumulative effect of a change in accounting
principle related to unbilled revenues.
(b) Restated to conform with 2000 presentation.
30
SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------------------------------------------------------
Amounts in Thousands of Dollars 2000 1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT ITEMS
Total operating revenues $1,075,864 $1,158,800 $1,178,746 $1,175,941 $1,187,407 $1,189,784
Operating income $ 143,171 $ 259,764 $ 204,086 $ 207,385 $ 222,079 $ 246,637
Income before extraordinary item
and cumulative effect $ 77,089 $ 151,020 $ 148,548 $ 141,820 $ 149,860 $ 151,070
Extraordinary item $ -- $ -- $ (82,548) $ -- $ -- $ --
Cumulative effect of change
in accounting principle $ 15,495 $ -- $ -- $ -- $ -- $ --
Net income after extraordinary item
and cumulative effect $ 92,584 $ 151,020 $ 66,000 $ 141,820 $ 149,860 $ 151,070
Earnings for common stock
before extraordinary item
and cumulative effect $ 73,678 $ 147,022 $ 144,512 $ 137,798 $ 145,815 $ 145,750
Earnings for common stock
after extraordinary item
and cumulative effect $ 89,173 $ 147,022 $ 61,964 $ 137,798 $ 145,815 $ 145,750
- --------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET ITEMS
Property, plant and equipment - net $1,344,345 $1,458,517 $1,447,299 $2,562,919 $2,717,473 $2,978,903
Total assets $2,777,608 $4,281,412 $4,309,626 $3,840,179 $3,897,086 $4,067,665
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Common stockholder's equity $ 539,557 $ 798,674 $ 868,500 $1,003,833 $ 989,424 $1,131,334
Non-redeemable preferred and
preference stock 222,053 229,512 227,782 226,503 223,072 70,966
Redeemable preferred and
preference stock -- -- -- -- -- --
Long-term debt 1,060,834 1,410,754 1,160,348 1,218,276 1,271,961 1,322,531
- --------------------------------------------------------------------------------------------------------------------------------
Total capitalization $1,822,444 $2,438,940 $2,256,630 $2,448,612 $2,484,457 $2,524,831
- --------------------------------------------------------------------------------------------------------------------------------
31
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information relating to our board of directors is set forth in Exhibit 99.2
hereto. The information is incorporated here by reference. Information relating
to our executive officers is set forth in Part I of this Report under the
caption "Executive Officers of the Registrant." Information relating to
compliance with section 16(a) of the Securities Exchange Act of 1934 is set
forth in Exhibit 99.1 hereto, and incorporated here by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The information relating to executive compensation is set forth in Exhibit
99.1, filed as part of this Report. The information is incorporated here by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
DQE is the beneficial owner and holder of all shares of our outstanding common
stock, $1 par value, consisting of 10 shares as of February 28, 2001.
Information relating to the ownership of equity securities of DQE and Duquesne
Light by our directors and executive officers is set forth in Exhibit 99.1,
filed as part of this Report. The information is incorporated here by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a)(1) The following information is set forth here in Item 8 (Consolidated
Financial Statements and Supplementary Data) on pages 12 through 30 of this
Report. The following financial statements and Report of Independent Auditors
are incorporated here by reference:
Report of Independent Auditors.
Statement of Consolidated Income for the Three Years Ended December 31, 2000.
Consolidated Balance Sheet, December 31, 2000 and 1999.
Statement of Consolidated Cash Flows for the Three Years Ended December 31,
2000.
Statement of Consolidated Comprehensive Income for the Three Years Ended
December 31, 2000.
Statement of Consolidated Retained Earnings for the Three Years Ended December
31, 2000.
Notes to Consolidated Financial Statements.
(a)(2) The following financial statement schedule and the related Report of
Independent Auditors are filed here as a part of this Report:
Schedule for the Three Years Ended December 31, 2000:
II - Valuation and Qualifying Accounts.
The remaining schedules are omitted because of the absence of the conditions
under which they are required or because the information called for is shown in
the financial statements or notes to the consolidated financial statements.
(a)(3) Exhibits are set forth in the Exhibit Index below, incorporated here by
reference. Documents other than those designated as being filed here are
incorporated here by reference. Documents incorporated by reference to a DQE
Annual Report on Form 10-K, a Quarterly Report on Form 10-Q or a Current Report
on Form 8-K are at Securities and Exchange Commission File No. 1-10290.
Documents incorporated by reference to a Duquesne Light Company Annual Report on
Form 10-K, a Quarterly Report on Form 10-Q or a Current Report on Form 8-K are
at Securities and Exchange Commission File No. 1-956. The Exhibits include the
management contracts and compensatory plans or arrangements required to be filed
as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.
(b) We have filed no reports on Form 8-K since those reported in our last Form
10-Q.
32
Exhibits Index
Exhibit Method of
No. Description Filing
2.1 Generation Exchange Agreement by and between Exhibit 2.1 to the Form 8-K
Duquesne Light Company, on the one hand, and Current Report of DQE
The Cleveland Electric Illuminating Company, dated March 26, 1999.
Ohio Edison Company and Pennsylvania Power
Company, on the other, dated as of March 25, 1999.
2.2 Nuclear Generation Conveyance Agreement by and Exhibit 2.2 to the Form 8-K
between Duquesne Light Company, on the one hand, Current Report of DQE
and Pennsylvania Power Company and the Cleveland dated March 26, 1999.
Electric Illuminating Company, on the other, dated
as of March 25, 1999.
2.3 Asset Purchase Agreement, dated as of September 24, Exhibit 2.1 to the Form 8-K
1999, by and between Duquesne Light Company, Current Report of Duquesne
Orion Power Holdings, Inc., and The Cleveland Electric Light dated September 24, 1999.
Illuminating Company, Ohio Edison and Pennsylvania
Power Company.
2.4 POLR Agreement, dated as of September 24, 1999 Exhibit 2.2 to the Form 8-K
by and between Duquesne Light Company and Orion Current Report of Duquesne
Power Holdings, Inc. Light dated September 24, 1999.
3.1 Restated Articles of Incorporation of Duquesne Light Exhibit 3.1 to the Form 10-Q
as currently in effect. Quarterly Report of Duquesne
Light for the quarter ended
June 30, 1999.
3.2 By-Laws of Duquesne Light, as amended through Exhibit 3.2 to the Form 10-Q
June 29, 1999 and as currently in effect. Quarterly Report of Duquesne
Light for the quarter ended
June 30, 1999.
4.1 Indenture dated March 1, 1960, relating to Duquesne Exhibit 4.3 to the Form 10-K
Light Company's 5% Sinking Fund Debentures. Annual Report of DQE for the
year ended December 31, 1989.
4.2 Indenture of Mortgage and Deed of Trust dated as of Exhibit 4.3 to Registration
April 1, 1992, securing Duquesne Light Company's Statement (Form S-3)
First Collateral Trust Bonds. No. 33-52782.
4.3 Supplemental Indentures supplementing the said
Indenture of Mortgage and Deed of Trust -
Supplemental Indenture No. 1. Exhibit 4.4 to Registration
Statement (Form S-3)
No. 33-52782.
Supplemental Indenture No. 2 through Supplemental Exhibit 4.4 to Registration
Indenture No. 4. Statement (Form S-3)
No. 33-63602.
33
Exhibit Method of
No. Description Filing
Supplemental Indenture No. 5 through Supplemental Exhibit 4.6 to the Form 10-K
Indenture No. 7. Annual Report of Duquesne
Light Company for the year
ended December 31, 1993.
Supplemental Indenture No. 8 and Supplemental Exhibit 4.6 to the Form 10-K
Indenture No. 9. Annual Report of Duquesne
Light Company for the year
ended December 31, 1994.
Supplemental Indenture No. 10 through Supplemental Exhibit 4.4 to the Form 10-K
Indenture No. 12. Annual Report of Duquesne
Light Company for the year
ended December 31, 1995.
Supplemental Indenture No. 13. Exhibit 4.3 to the Form 10-K
Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
Supplemental Indenture No. 14. Exhibit 4.3 to the Form 10-K
Annual Report of Duquesne
Light Company for the year
ended December 31, 1997.
Supplemental Indenture No. 15. Exhibit 4.3 to the Form 10-K
Annual Report of Duquesne
Light Company for the year
ended December 31, 1999.
Supplemental Indenture No. 16. Exhibit 4.3 to the Form 10-K
Annual Report of Duquesne
Light Company for the year
ended December 31, 1999.
4.4 Amended and Restated Agreement of Limited Partnership Exhibit 4.4 to the Form 10-K
of Duquesne Capital L.P., dated as of May 14, 1996. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
4.5 Payment and Guarantee Agreement, dated as of May 14, Exhibit 4.5 to the Form 10-K
1996, by Duquesne Light Company with respect to MIPS. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
4.6 Indenture, dated as of May 1, 1996, by Duquesne Light Exhibit 4.6 to the Form 10-K
Company to the First National Bank of Chicago as Trustee. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
10.1 Deferred Compensation Plan for the Directors of Exhibit 10.1 to the Form 10-K
Duquesne Light Company, as amended to date. Annual Report of DQE for the
year ended December 31, 1992.
34
Exhibit Method of
No. Description Filing
10.2 Incentive Compensation Program for Certain Executive Exhibit 10.2 to the Form 10-K
Officers of Duquesne Light Company, as amended to date. Annual Report of DQE for the
year ended December 31, 1992.
10.3 Description of Duquesne Light Company Pension Exhibit 10.3 to the Form 10-K
Service Supplement Program. Annual Report of DQE for the
year ended December 31, 1992.
10.4 Duquesne Light Company Outside Directors' Exhibit 10.59 to the Form 10-K
Retirement Plan, as amended to date. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
10.5 Duquesne Light/DQE Charitable Giving Program, Exhibit 10.1 to the Form 10-Q
as amended. Quarterly Report of DQE for
the quarter ended March 31,
1998.
10.6 Performance Incentive Program for DQE, Inc. and Exhibit 10.7 to the Form 10-K
Subsidiaries. Formerly known as the Duquesne Light Annual Report of DQE for the
Company Performance Incentive Program. year ended December 31, 1996.
10.7 Non-Competition and Confidentiality Agreement dated Exhibit 10.14 to the Form 10-K
as of October 3, 1996 by and among DQE, Inc., Duquesne Annual Report of DQE for the
Light Company and David D. Marshall, together with a year ended December 31, 1996.
schedule listing substantially identical agreement with
Victor A. Roque.
10.8 Schedule to Exhibit 10.14 to the Form 10-K Annual Report Exhibit 10.12 to the Form 10-K
of DQE for the year ended December 31, 1996, listing a Annual Report of DQE for the
Non-Competition and Confidentiality Agreement dated as year ended December 31, 1998.
of October 3, 1996, with William J. DeLeo, substantially
identical to the agreement filed as Exhibit 10.14 to the
1996 10-K.
10.9 Schedule to Exhibit 10.14 to the Form 10-K Annual Report Exhibit 10.12 to the Form 10-K
of DQE for the year ended December 31, 1996, listing a Annual Report of DQE for the
Non-Competition and Confidentiality Agreement for year ended December 31, 2000.
Jack E. Saxer, Jr., dated as of April 22, 1996.
10.10 Schedule to Exhibit 10.14 to the Form 10-K Annual Report Filed here.
of DQE for the year ended December 31, 1996, listing
Non-Competition and Confidentiality Agreements for
John R. Marshall (dated June 24, 1999), Maureen L. Hogel
(dated April 2, 1997), Stevan R. Schott (dated August 9, 1999)
and Joseph G. Belechak (dated August 1, 2000), substantially
identical to the agreement filed as Exhibit 10.14 to the 1996 10-K.
10.11 Amended and Restated POLR II Agreement by and between Duquesne Light Filed here.
Company and Orion Power MidWest, L.P., dated as of December 7, 2000.
35
Exhibit Method of
No. Description Filing
12.1 Ratio of Earnings to Fixed Charges. Filed here.
18.1 Letter regarding change in accounting principle. Filed here.
21.1 Subsidiaries of the registrant:
Duquesne Light has no significant subsidiaries
23.1 Independent Auditors' Consent. Filed here.
99.1 Executive Compensation and Security Ownership of Filed here.
Directors and Officers for 2000.
99.2 Directors of Duquesne Light. Filed here.
Copies of the exhibits listed above will be furnished, upon request, to
holders or beneficial owners of any class of our stock as of February 28, 2001,
subject to payment in advance of the cost of reproducing the exhibits requested.
36
SCHEDULE II
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2000, 1999 and 1998
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
---------- ---------- ---------- ---------- ---------- ----------
Additions
------------------------
Balance at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Year Expenses Accounts Deductions of Year
------------- ----------- ----------- ----------- ------------ ---------
Year Ended December 31, 2000
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $ 8,730 $ 8,500 $2,660(A) $10,077(B) $9,813
Year Ended December 31, 1999
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $ 9,137 $ 9,000 $3,260(A) $12,667(B) $8,730
Year Ended December 31, 1998
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $15,016 $11,000 $3,290(A) $20,169(B) $9,137
Notes: (A) Recovery of accounts previously written off.
(B) Accounts receivable written off.
37
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
Duquesne Light Company
(Registrant)
Date: March 26, 2001 By: /s/ John R. Marshall
------------------------
(Signature)
John R. Marshall
President and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
Signature Title Date
/s/ John R. Marshall President and Director March 26, 2001
- -----------------------
John R. Marshall (Principle Executive Officer)
/s/ Frosina C. Cordisco Treasurer March 26, 2001
- -----------------------
Frosina C. Cordisco (Principle Financial Officer)
/s/ James E. Wilson Vice President and Chief Accounting Officer March 26, 2001
- -----------------------
James E. Wilson (Principal Accounting Officer)
/s/ David D. Marshall Director March 26, 2001
- -----------------------
David D. Marshall
/s/ Morgan K. O'Brien Director March 26, 2001
- -----------------------
Morgan K. O'Brien
/s/ Victor A.Roque Director March 26, 2001
- -----------------------
Victor A. Roque
/s/ William J. DeLeo Director March 26, 2001
- -----------------------
William J. DeLeo
/s/ Jack E. Saxer, Jr. Director March 26, 2001
- -----------------------
Jack E. Saxer, Jr.
38