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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, 2001
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or
[_] 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 10 outstanding shares of Duquesne Light Company
common stock, $1 par value.
[_] 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
Registrant Title of each class on 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 3/8 % Monthly Income Preferred Securities, Series A (1) New York Stock Exchange
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 Page
---- ----
GLOSSARY
PART I PART III
ITEM 1. BUSINESS ITEM 10. DIRECTORS AND EXECUTIVE
Corporate Structure 1 OFFICERS OF THE REGISTRANT 35
Employees 1
Property, Plant and Equipment 1 ITEM 11. EXECUTIVE COMPENSATION 35
Environmental Matters 2
Other 2 ITEM 12. SECURITY OWNERSHIP OF
Executive Officers of the Registrant 4 CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT 35
ITEM 2. PROPERTIES 5
ITEM 13. CERTAIN RELATIONSHIPS AND
ITEM 3. LEGAL PROCEEDINGS 5 RELATED TRANSACTIONS 35
ITEM 4. SUBMISSION OF MATTERS TO A PART IV
VOTE OF SECURITY HOLDERS 5
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
PART II SCHEDULES AND REPORTS ON
FORM 8-K 35
ITEM 5. MARKET FOR REGISTRANT'S
COMMON EQUITY AND RELATED SCHEDULE II
SHAREHOLDER MATTERS 5
SIGNATURES
ITEM 6. SELECTED FINANCIAL DATA 5
ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS 5
Results of Operations 5
Liquidity and Capital Resources 10
Rate Matters 12
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK 13
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA 13
Independent Auditors' Report 13
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 35
G L O S S A R Y O F T E R M S
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") gives consumers the right to contract for
electricity at market prices from PUC-approved electric generation suppliers.
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.
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.")
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.
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 in Part
II, Item 8 of this Report.
Duquesne Light Company is a wholly owned subsidiary of DQE, Inc. We are
engaged in the transmission and distribution of electric energy.
Our subsidiaries are primarily involved in operating our automated meter
reading technology and providing financing to certain affiliates.
See Note R to our consolidated financial statements for information on our
business segments.
DQE's Back-to-Basics Strategy
In the second half of 2001, following the completion of its strategic
review process, DQE announced a new management team and a change in its
strategic direction. Its Back-to-Basics strategy features, among other things, a
more concentrated focus on our electric utility operations. In addition, cost
reductions as a result of restructuring are expected to continue to enhance
profitability.
Service Area
Our utility operations provide service to approximately 586,000 direct
customers in southwestern Pennsylvania (including in the City of Pittsburgh), a
territory of approximately 800 square miles.
Regulation
We are subject to the accounting and reporting requirements of the
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, the electricity supply
segment does not meet the criteria of Statement of Financial Accounting
Standards (SFAS) No. 71,"Accounting for the Effects of Certain Types of
Regulation." Pursuant to the PUC's final restructuring order, and as provided in
the Pennsylvania Electricity Generation Customer Choice and Competition Act
(Customer Choice Act), generation-related transition costs are being recovered
through a competitive transition charge (CTC) collected in connection with
providing transmission and distribution services. 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.")
Business Segments
For the purposes of complying with SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information," we are required to disclose
information about our business segments separately. This information is set
forth in "Results of Operations" and in "Business Segments and Related
Information," Note R to our consolidated financial statements.
Forward-looking Statements
We use forward-looking statements in this report. Statements that are not
historical facts are forward-looking statements, and are based on beliefs and
assumptions of our management, and on information currently available to
management. Forward-looking statements include statements preceded by, followed
by or using such words as "believe," "expect," "anticipate," "plan," "estimate"
or similar expressions. Such statements speak only as of the date they are made,
and we undertake no obligation to update publicly any of them in light of new
information or future events. Actual results may materially differ from those
implied by forward-looking statements due to known and unknown risks and
uncertainties.
E M P L O Y E E S
At December 31, 2001, we had 1,302 employees. We are party to a labor
contract with the International Brotherhood of Electrical Workers, which
represents the majority of our employees. We are engaged in negotiations to
extend the contract, which currently expires in September 2002.
P R O P E R T Y, P L A N T A N D E Q U I P M E N T
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, 2001 and 2000 are as follows:
1
PP&E and Related Accumulated Depreciation at December 31,
- ----------------------------------------------------------------
(Millions of Dollars)
2001
-----------------------------------------
Accumulated Net
Investment Depreciation Investment
- ----------------------------------------------------------------
Electric delivery $ 1,926.6 $ 616.5 $ 1,310.1
Capital leases 10.2 7.0 3.2
Other 35.5 3.9 31.6
- ----------------------------------------------------------------
Total $ 1,972.3 $ 627.4 $ 1,344.9
================================================================
(Millions of Dollars)
2000
-----------------------------------------
Accumulated Net
Investment Depreciation Investment
- ----------------------------------------------------------------
Electric delivery $ 1,910.5 $ 612.5 $ 1,298.0
Capital leases 17.8 6.4 11.4
Other 36.8 1.9 34.9
- ----------------------------------------------------------------
Total $ 1,965.1 $ 620.8 $ 1,344.3
================================================================
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. 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 our Customer
Advanced Reliability System (CARS) acquisition in 2000.
E N V I R O N M E N T A L M A T T E R S
Various federal and state authorities regulate us with respect to air and
water quality and other environmental matters. FirstEnergy Corporation assumed
environmental compliance obligations with respect to the generation plants it
acquired in the December 1999 power station exchange. Orion Power MidWest, L.P.
assumed the environmental obligations related to all of the plants it acquired
in the April 2000 generation asset sale, both those we originally owned and
those we acquired in the exchange.
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
$1.1 million in 2001 to comply with these DEP regulations. We expect the costs
of compliance to be approximately $1.4 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.
We own, but do not operate, the Warwick Mine, including
approximately 1,200 acres of unmined coal lands and mining rights, located along
the Monongahela River in Greene County, Pennsylvania. This property had been
used in the electricity supply business segment.
Our current estimated liability for closing the Warwick Mine, including
final site reclamation, mine water treatment and certain labor liabilities, is
approximately $35 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.
O T H E R
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (FASB) issued three
new accounting standards, SFAS No. 141, "Business Combinations," SFAS No. 142,
"Goodwill and Other Intangibles," and SFAS No. 143, "Accounting for Asset
Retirement Obligations."
SFAS No. 141 eliminates the pooling-of-interests method of accounting for
business combinations, with limited exceptions for combinations initiated prior
to July 1, 2001. We do not believe that the adoption of SFAS No. 141 will have a
significant impact on our financial statements.
SFAS No. 142, which became effective January 1, 2002, discontinues the
requirement for amortization of goodwill and indefinite-lived intangible assets,
and instead requires an annual review for the impairment of those assets.
Impairment is to be examined more frequently if certain indicators appear.
Intangible assets with a determinable life will continue to be amortized. As of
December 31, 2001 we have no assets that will be subject to the transitional
assessment provisions of SFAS No. 142.
SFAS No. 143 addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. Specifically, this standard requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is
2
incurred. The entity is required to capitalize the cost by increasing the
carrying amount of the related long-lived asset. The capitalized cost is then
depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss. The standard is effective for fiscal years beginning
after June 15, 2002. We are currently evaluating, but have yet to determine, the
impact that the adoption of SFAS No. 143 will have on our financial statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed Of." The statement requires that all long-lived assets to be held and
used continue to be evaluated for impairment similar to SFAS No. 121. The
statement also requires that all long-lived assets to be sold be measured at the
lower of carrying amount or fair value less cost to sell, whether reported in
continuing operations or in discontinued operations. Therefore, discontinued
operations will no longer be measured on a net realizable value basis and will
not include amounts for future operating losses. The statement also broadens the
reporting requirements for discontinued operations to include disposal
transactions of all components of an entity (rather than segments of a
business). Components of an entity include operations and cash flows that can be
clearly distinguished from the rest of the entity that will be eliminated from
the ongoing operations of the entity in a disposal transaction. The statement is
effective for fiscal years beginning after December 15, 2001. We are currently
evaluating, but have yet to determine, the impact that the adoption of SFAS No.
144 will have on our financial statements.
Market Risk
Market risk represents the risk of financial loss that may impact our
consolidated financial position, results of operations, or cash flows due to
adverse changes in market prices and rates.
We manage our interest rate risk by balancing our exposure between fixed
and variable rates, while attempting to minimize our interest costs. Currently,
our variable interest rate debt is approximately $418.0 million or 39.4 percent
of long-term debt. This variable rate debt is low-cost, tax-exempt debt. We also
manage our interest rate risk by retiring and issuing debt from time to time and
by maintaining a balance of short-term, medium-term and long-term debt. A 10
percent increase in interest rates would have affected our variable rate debt
obligations by increasing interest expense by approximately $0.7 million, $2.0
million and $1.6 million for the years ended December 31, 2001, 2000 and 1999. A
10 percent reduction in interest rates would have increased the market value of
our fixed rate debt by approximately $40.6 million and $40.4 million as of
December 31, 2001 and 2000. Such changes would not have a significant near-term
effect on our future earnings or cash flows.
3
EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below are the names, ages as of March 10, 2002, and positions
during the past five years of our executive officers.
Victor A. Roque, Age 55. President since October 2001. Previously Senior
Vice President from November 1998 to April 2000; Vice President from April 1995
to October 1998; and General Counsel from November 1994 to April 2000. Executive
Vice President of DQE since November 1998. Vice President of DQE from April 1995
until November 1998. General Counsel of DQE from November 1994 to October 2001.
Secretary of DQE from May 2000 to October 2001.
Joseph G. Belechak, Age 42. Senior Vice President - Operations and Customer
Service since October 2001. Vice President - Asset Management and Operations
from August 2000 to October 2001. General Manager, Asset Management from March
1999 to August 2000. Manager, Substations and Telecommunications from June 1996
to March 1999.
Maureen L. Hogel, Age 41. Senior Vice President - Human Resources and
Administration since October 2001. Vice President - Development, Legal and
Administration from January 2001 to October 2001. Vice President - Legal from
September 1999 to January 2001. Assistant General Counsel from February 1996 to
September 1999.
Fred R. Allison, Age 52. Vice President - Information Technology and
Revenue Cycle Services since October 2001. General Manager, Customer Service
from November 1999 to October 2001. General Manager, Financial Services from
November 1998 to November 1999. Assistant Controller from May 1996 to November
1998.
Frosina C. Cordisco, Age 50. Vice President since October 2001 and
Treasurer since November 1998. Manager of Electronic Commerce from April 1996 to
April 1998. Held financial positions at various affiliates between 1996 and
1999. Also Vice President and Treasurer of DQE.
William J. DeLeo, Age 51. Vice President - Corporate Compliance and
Corporate Secretary since October 2001. Previously Vice President - Corporate
Services from November 1998 to April 2000, and Vice - President - Marketing and
Corporate Performance from April 1995 to November 1998. Vice President and Chief
Administrative Officer of DQE from November 1998 to October 2001. Also Vice
President - Corporate Compliance and Corporate Secretary of DQE.
David R. High, Age 47. Vice President and General Counsel since October
2001. Previously Associate General Counsel from January 1996 to September 1999.
Deputy General Counsel and Compliance Officer of DQE from June 2000 to October
2001. Associate General Counsel of DQE from September 1999 to June 2000. Also
Vice President and General Counsel of DQE.
James A. Lahtinen, Age 49. Vice President - Rates since October 2001. Vice
President - Rates & Regulatory Affairs of AquaSource, Inc. from June 1999 to
October 2001. Vice President - Planning, Budgeting & Rates of AquaSource, Inc.
from January 1999 to June 1999. Previously served as General Manager - Rates and
Regulatory Affairs and Manager, Transmission Services, at Duquesne Light.
Stevan R. Schott, Age 39. Vice President and Controller since October 2001.
Vice President - Finance and Customer Service from August 2000 to October 2001.
Vice President and Controller from August 1999 to August 2000. Controller of DQE
Financial from September 1998 to August 1999. Senior Manager, Public Utilities
Specialist at Deloitte & Touche LLP from September 1993 to September 1998. Also
Vice President and Controller of DQE.
James E. Wilson, Age 36. Vice President - Corporate Development since
October 2001. Vice President and Chief Accounting Officer from August 2000 to
October 2001. Previously Controller from November 1998 to August 1999, and
Assistant Controller from September 1996 to November 1998. Controller of DQE
from July 1999 to October 2001. Also Vice President - Corporate Development of
DQE.
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.
In April 2000, we sold our generation assets. We own 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.
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.
Our common stock is not publicly traded; DQE owns all 10 shares. We
declared quarterly dividends on our common stock totaling $52.7 million in 2001
and $282.0 million in 2000.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data for each year of the six-year period ended December
31, 2001, are set forth on page 34. The information is incorporated here by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
R E S U L T S O F O P E R A T I O N S
Overall Performance
2001 Compared to 2000
Our earnings available for common stock were $50.0 million in 2001,
compared to $89.2 million in 2000, a decrease of $39.2 million or 43.9 percent.
The decrease in earnings is primarily due to the $33.3 million decline in
earnings relating to the CTC business segment (see discussion below). Also
affecting earnings in 2001 was an after tax restructuring charge of $6.7
million. In the fourth quarter of 2001, as part of DQE's Back-to-Basics
strategy, we initiated a restructuring plan to improve operational effectiveness
and efficiency, and to reduce operational expenses. The restructuring charge
included costs related to (1) the consolidation and reduction of certain
administrative and back office functions through an involuntary termination
plan, (2) the abandonment of certain leased office facilities to relocate
employees to one centralized location, and (3) other lease costs related to
abandoned office facilities.
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
in 2000. We applied net proceeds from the sale to reduce the level of our
transition costs. As we earned a return on our unrecovered transition costs,
this reduction in the level of transition costs resulted in decreased earnings.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires us to
make estimates and assumptions with respect to values and conditions that affect
the reported amounts of assets and liabilities, and disclosure of contingent
assets and liabilities, at the date of the financial statements. The reported
amounts of revenues and expenses during the reporting period also may be
affected by the estimates and assumptions we are required to make. We evaluate
these estimates on an ongoing basis, using historical experience, consultation
with experts, and other methods we consider reasonable in the particular
circumstances. Nevertheless, actual results may differ significantly from our
estimates.
5
In preparing our financial statements and related disclosures, we have
adopted the following accounting policies which management believes are
particularly important to the financial statements and that require the use of
estimates and assumptions in the financial preparation process.
Accounting for the Effects of Regulation. Duquesne Light's financial
statements are prepared in accordance with the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation," which differs in
certain respects from the application of accounting principles generally
accepted in the United States of America by non-regulated businesses. In
general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises
should reflect the economic effects of regulation. As a result, a regulated
utility is required to defer the recognition of costs (a regulatory asset) if it
is probable that, through the rate-making process, there will be a corresponding
increase in future rates. Accordingly, we defer certain costs, which will be
amortized over future periods. To the extent that collection of such costs is no
longer probable as a result of changes in regulation or our competitive
position, the associated regulatory assets are charged to expense.
Unbilled Energy Revenues. We generally record revenues related to the sale
of energy when delivery is made to our customers. However, the determination of
such sales to individual customers is based on the reading of their meters,
which we read on a systematic basis throughout the month. At the end of each
month, we estimate the amounts delivered to customers since the date of the last
meter reading and record the corresponding unbilled revenue. We estimate this
unbilled revenue each month based on daily volumes, estimated customer usage by
class, line losses and applicable customer rates based on regression analyses
reflecting significant historical trends and experience. Customer accounts
receivable as of December 31, 2001 include unbilled revenues of $36.6 million.
Contingent Liabilities. We establish reserves for estimated loss
contingencies when it is management's assessment that a loss is probable and the
amount can be reasonably estimated. Revisions to contingent liabilities are
reflected in income in the period in which different facts or information become
known, or circumstances change, that affect the previous assumptions with
respect to the likelihood or amount of loss. Reserves for contingent liabilities
are based upon management's assumptions and estimates, advice of legal counsel,
or other third parties regarding the probable outcomes of the matter. Should the
ultimate outcome differ from the assumptions and estimates, revisions to the
estimated reserves for contingent liabilities would be recognized. Such
contingent liabilities for Duquesne Light include, but are not limited to,
restructuring liabilities (see Note C to the consolidated financial statements)
and other commitments and contingencies (see Note K to the consolidated
financial statements).
Results of Operations by Business Segment
We report the results of our business segments, determined by products,
services and regulatory environment as follows: (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.
Note R, "Business Segments and Related Information," in the Notes to the
Consolidated Financial Statements, shows the financial results of each principal
business segment in tabular form. Following is a discussion of these results.
2001 Compared to 2000
Electricity Delivery Business Segment. The electricity delivery business
segment contributed $37.7 million to net income in 2001, consisting of $44.4
million before a restructuring charge of $6.7 million, as previously discussed.
This is compared to $43.4 million in 2000, which included $7.3 million after tax
related to the cumulative effect of a change in accounting principle for
unbilled revenues. Excluding these one-time charges in both years, net income
from the electricity delivery business segment was $8.3 million higher in 2001,
primarily due to lower operating expenses resulting from the cost reduction
initiatives that were begun in 2000.
Operating revenues for this business segment are primarily derived from the
delivery of electricity. Sales to residential and commercial customers are
primarily influenced by weather conditions. Warmer summer and colder winter
seasons lead to increased customer use of electricity for cooling and heating.
Commercial sales also are affected by regional development. Sales to
residential, commercial and industrial customers are influenced by national and
global economic conditions.
Operating revenues increased by $3.5 million or 1.1 percent compared to
2000. Residential sales increased 2.1 percent, primarily due to warmer summer
weather in 2001. Commercial sales increased 1.3 percent, due to an increase in
the number of commercial customers, while industrial sales decreased 8.3
percent, due to decreased consumption by steel manufacturers, including one
major customer who has filed for protection under Chapter 11 of
6
the U.S. Bankruptcy Code. The following table sets forth kilowatt-hours (KWH)
delivered to electric utility customers.
- ----------------------------------------------------------------------
KWH Delivered
-------------------------------
(In Millions)
-------------------------------
2001 2000 Change
- ----------------------------------------------------------------------
Residential 3,584 3,509 2.1%
Commercial 6,241 6,162 1.3%
Industrial 3,283 3,581 (8.3)%
- ------------------------------------------------------------
KWH Sales 13,108 13,252 (1.1)%
Cumulative effect of a change
in accounting principle -- 483 %
- ------------------------------------------------------------
Total Sales 13,108 13,735 (4.6)%
======================================================================
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, billing and collection costs; customer
service; administrative expenses; income taxes; and non-income taxes, such as
gross receipts, property and payroll taxes. Operating expenses decreased by
$11.2 million or 6.5 percent compared to 2000, due to cost reduction initiatives
that were begun in 2000, as well as a reduction to our employee pension costs.
(See Note L.)
Depreciation and amortization expense includes the depreciation of electric
delivery-related plant and equipment. There was an increase of $3.3 million or
5.9 percent compared to 2000 due primarily to net additions to property, plant
and equipment during 2001.
Other income consists primarily of interest income from the DQE loan
receivable and our investment in the DQE Capital cash pool. Gains or losses
resulting from the disposition of certain assets are also included here.
Other income increased $5.8 million or 31.7 percent compared to 2000,
primarily due to increased interest income from higher cash balances in 2001.
(See Note A.)
Interest and other charges include interest on long-term debt, other
interest, and preferred stock dividends. In 2001, there was $8.9 million or 12.8
percent more interest and other charges allocated to the electricity business
segment compared to 2000. 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 Business Segment. In 2001, the electricity supply
business segment reported net income of zero, compared with net income of $0.2
million in 2000. For all of 2001, and for the period from April 29 through
December 31, 2000, this segment's financial results reflect our provider of last
resort service arrangement with Orion, which is designed to be income neutral.
Included in 2000 was $8.2 million related to the cumulative effect of a change
in accounting principle for unbilled revenues.
Operating revenues for this business segment are derived primarily from the
supply of electricity for delivery to retail customers and the supply of
electricity to wholesale customers. Retail energy requirements fluctuate as the
number of customers participating in customer choice changes. Energy
requirements for residential and commercial customers are also influenced by
weather conditions; temperature extremes lead to increased customer use of
electricity for cooling and heating. Commercial energy requirements are also
affected by regional development. Energy requirements for industrial customers
are primarily influenced by national and global economic conditions.
Short-term sales to other utilities are made at market rates. Prior to the
generation asset divestiture in April 2000, fluctuations in such sales were
related to customer energy requirements, the energy market and transmission
conditions, and the availability of generating stations. Following the
divestiture, fluctuations result from excess daily energy deliveries to our
electricity delivery system.
Operating revenues increased $4.9 million or 1.2 percent compared to 2000.
The increase in revenue is due to an increase in the average generation rate
charged to customers as well as an increase in the percentage of customers who
receive electricity through our provider of last resort service arrangement.
The following table sets forth KWH supplied for customers who have not
chosen an alternative generation supplier.
- ----------------------------------------------------------------------
KWH Supplied
-------------------------------
(In Millions)
-------------------------------
2001 2000 Change
- ----------------------------------------------------------------------
Residential 2,348 2,422 (3.1)%
Commercial 5,367 4,436 21.0%
Industrial 3,079 3,332 (7.6)%
- ------------------------------------------------------------
KWH Sales 10,794 10,190 5.9%
Cumulative effect of a change
in accounting principle -- 341
Sales to Other Utilities 363 963 (62.3)%
- ------------------------------------------------------------
Total Sales 11,157 11,494 (2.9)%
======================================================================
Operating expenses for the electricity supply business segment in 2001
consist of energy costs (i.e., to obtain energy from Orion for our provider of
last resort service) and gross receipts tax, both of which fluctuate in direct
relation to operating revenues. In 2000, such operating expenses included energy
costs; costs to operate and
7
maintain the power stations; administrative expenses; income taxes; and non-
income taxes, such as gross receipts, property and payroll taxes.
Fluctuations in energy costs in 2001 resulted from total KWH supplied through
our provider of last resort arrangement. Fluctuations in energy costs in 2000
generally resulted from changes in the total KWH supplied, the mix between coal
generated power and purchased power, the cost of fuel, and generating station
availability.
Operating expenses increased $17.5 million or 4.2 percent from 2000 as a
result of an increase in the KWH supplied. This increase resulted from higher
purchased power costs (related to our provider of last resort arrangement)
following the generation asset sale, as opposed to the cost of power generated
by our previously owned power stations. The cost under the arrangement is an
average of $0.04 per KWH across all rate classes. (See "Provider of Last
Resort.")
Depreciation and amortization expense in 2000 included the depreciation of
the power stations' plant and equipment through the generation asset sale.
Other income decreased $2.8 million from 2000, because no other income has
been allocated to this business segment since the generation asset sale.
Interest and other charges include interest on long-term debt, other
interest, and preferred stock dividends. In 2001, no interest expense was
allocated to this business segment; in 2000, there was $21.2 million of
allocated interest expense. All remaining financing costs following the
generation asset sale are borne by the electricity delivery business segment.
CTC Business Segment. 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 competitive transition charge (CTC) from
electric utility customers. On January 18, 2001, the PUC issued an order
approving our final accounting for the proceeds of our April 2000 generation
asset sale, including the net recovery of $276 million of sale-related
transaction costs.
For the CTC business segment, operating revenues are derived from the billing
of generation-related transition costs of our electric delivery customers. We
are allowed to earn an 11 percent pre-tax return on the net of tax CTC balance.
As revenues are billed to customers on a monthly basis, we amortize the CTC
balance. The resulting decrease in the CTC balance causes a decline in the
return earned.
In 2001, the CTC business segment reported net income of $12.3 million
compared to $45.6 million in 2000, a decrease of $33.3 million or 73.0 percent.
Operating revenues decreased $30.7 million or 9.2 percent due to a decrease
in the average CTC rate charged to customers from 2000 to 2001.
Operating expenses consist of gross receipts tax and income taxes, which
fluctuate in direct relation to operating revenues and pre-tax earnings,
respectively.
Operating expenses decreased $19.1 million or 48.7 percent compared to 2000.
As previously discussed, the decrease in the CTC balance from 2000 to 2001
caused a decline in the return we earned, which caused a corresponding decline
in income tax expense.
Depreciation and amortization expense consists of the amortization of
transition costs. There was an increase of $21.7 million or 8.7 percent compared
to 2000. As a result of the lower average CTC balance, there was less return
earned in 2001. We now anticipate termination of the CTC collection period by
mid-year 2002 for most major rate classes.
2000 Compared to 1999
Electricity Delivery Business Segment. The electricity delivery business
segment contributed $43.4 million to net income in 2000, compared to $38.7
million in 1999, an increase of $4.7 million or 12.1 percent. Included in 2000
is $7.3 million related to the cumulative effect of a change in accounting
principle for unbilled revenues.
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. 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. 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.
- ----------------------------------------------------------------------
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 %
- -----------------------------------------------------------
KWH Sales 13,252 13,031 1.7 %
Cumulative effect of a change
in accounting principle 483 -- --
- -----------------------------------------------------------
Total Sales 13,735 13,031 5.4 %
======================================================================
Operating expenses decreased by $14.6 million or 7.8 percent compared to
1999, due to cost reduction initiatives we began in 2000; cost savings related
to the implementation of our automated Customer Advanced Reliability System
(CARS); and a reduction in employee pension costs.
Depreciation and amortization expense increased $5.9 million or 11.7 percent
compared to 1999. The increase is primarily attributed to more fixed assets
plant being allocated to the delivery business in 2000, and the CARS system.
8
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 reduced income following the dividend of certain
subsidiaries to DQE.
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.
All remaining financing costs after recapitalization are borne by the
electricity delivery business segment.
Electricity Supply Business Segment. In 2000, the electricity supply business
segment reported net income of $0.2 million compared to $11.7 million in 1999, a
decrease of $11.5 million or 98.3 percent. Included in 2000 is $8.2 million
related to the cumulative effect of a change in accounting principle for
unbilled revenues.
Operating revenues decreased by $103.1 million or 19.5 percent compared to
1999. The decrease in revenues can be attributed primarily to a 71.2 percent
decrease in sales to other utilities in 2000 compared to 1999. Subsequent to our
generation asset sale, energy sales to other utilities are not significant. 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 %
- -----------------------------------------------------------
KWH Sales 10,190 8,925 14.2 %
Cumulative effect of a change
in accounting principle 341 -- --
Sales to Other Utilities 963 3,347 (71.2)%
- -----------------------------------------------------------
Total Sales 11,494 12,272 (6.3)%
=======================================================================
Operating expenses decreased $41.2 million or 9.1 percent from 1999, as a
result of reduced maintenance costs due to 1999 generation station outages and
reduced non-fuel operating expenses associated with the December 1999 power
station exchange. Partially offsetting these decreases was an increase in
purchased power costs, related to our provider of last resort arrangement with
Orion following the generation asset sale. The cost under the arrangement is an
average of $0.04 per KWH across all rate classes. (See "Provider of Last Resort"
discussion.) 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 April 2000 generation
asset sale and accrued nuclear decommissioning costs during 1999. There was a
decrease of $24.1 million or 91.6 percent compared to 1999 due to the sale of
the power stations' plant and equipment and the absence of nuclear
decommissioning costs in 2000.
Other income decreased $4.6 million or 62.2 percent compared to 1999,
primarily due to less income being allocated to this business segment in 2000
following the generation asset sale.
In 2000 there was a $22.7 million or 51.7 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 this business segment in 2000 due to the
generation asset sale.
CTC Business Segment. In 2000, the CTC business segment reported net income
of $45.6 million compared to $96.6 million in 1999, a decrease of $51.0 million
or 52.8 percent.
Operating revenues increased by $11.1 million or 3.4 percent compared to
1999. The increase in revenues can be attributed to a 1.7 percent increase in
sales to electric utility customers from 1999.
Operating expenses decreased $46.5 million or 54.3 percent from 1999 due to
the decrease in pre-tax earnings.
Depreciation and amortization expense increased by $154.0 million compared to
1999. By applying the $967 million of net proceeds from the generation asset
sale to reduce transition costs, we earned a significantly lower return in 2000
compared to 1999. As a result, there was higher CTC amortization in 2000 as
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.
Interest and other charges include interest on long-term debt, other
interest, and preferred stock dividends. In 1999 there was $45.4 million of
interest and other charges allocated to this business segment, while none was
allocated in 2000.
9
L I Q U I D I T Y A N D C A P I T A L R E S O U R C E S
SEC Statement on Disclosure
On January 22, 2002, the SEC issued a statement encouraging expanded
disclosure of certain items: off-balance sheet arrangements, contract trading
activities, and transactions with related parties.
We do not currently have any off-balance sheet financing arrangements. We are
not involved in any commodity contract trading activities. As a wholly owned
subsidiary of DQE, we are involved in various transactions with affiliates. (See
Notes A and D.)
Future Capital 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.
All of our customers are now buying their generation directly from
alternative suppliers or indirectly from Orion through the provider of last
resort service arrangement. Although we bill provider of last resort customer
revenues, we pass them on (net of gross receipts tax) to Orion. In addition, the
bill for an average residential provider of last resort customer is expected to
decrease, ultimately, by 16 percent with the final CTC collection. This decrease
reflects the additional cost of electric capacity required by regional
transmission organization (RTO) membership and the additional cost of RNR
recovery (defined below). We also agreed to freeze our generation rates through
2004 and our transmission and distribution rates through 2003. However, we
expect to realize a 0.5 cent per KWH margin through our extended provider of
last resort arrangement. The margin ultimately realized will depend on, among
other things, the number of customers who use the provider of last resort
service from time to time, as well as the life of the extended arrangement with
Orion. (See "Rate Matters.")
We maintain a $150.0 million revolving credit agreement expiring in October
2002. We may convert the revolver into a term loan facility for a one-year
period, for any amounts then outstanding upon expiration of the revolving credit
period. The interest rate can, in accordance with the option selected at the
time of the borrowing, be based on one of several indicators, including prime
and Eurodollar rates. Commitment fees are based on the unborrowed amount of the
commitment. We plan to extend the facility prior to its expiration. At December
31, 2001, no borrowings were outstanding.
Under our credit facility, we are subject to financial covenants requiring us
to maintain a maximum debt-to-capitalization ratio of 65.0 percent. At December
31, 2001 we were in compliance, having a debt-to-capitalization ratio of 58.8
percent.
On October 29, 2001, we filed a shelf registration statement for up to $400.0
million of first mortgage bonds with the SEC. We expect to refinance existing
debt using this shelf registration. Our ability to issue such debt will depend
on, among other things, market demand and interest rates.
In the first quarter of 2002, Moody's Investor Service, Standard & Poor's,
and Fitch Ratings assessed our short and long term credit profiles. The ratings
reflect the agencies' opinion of our overall financial strength.
Ratings impact our ability to access capital markets for investment and capital
requirements, as well as the relative costs related to such liquidity
capability. In general, the agencies reduced our long term credit ratings,
although staying within the range considered to be investment grade. This
ratings downgrade does not limit our ability to access our revolving credit
facility; it does, however, impact the cost of maintaining the credit facility
and the cost of any new debt. The agencies maintained the existing credit
ratings for our short term debt. These ratings are not a recommendation to buy,
sell or hold any of our securities, may be subject to revisions or withdrawal by
the agencies at any time, and should be evaluated independently of each other
and any other rating that may be assigned to our securities.
Financing
In January 2002, we issued $125.0 million of commercial paper and loaned the
proceeds to DQE; this loan is payable on demand. This commercial paper may, in
turn, be refunded through other debt instruments available to us. In addition,
$100.0 million of our first mortgage bonds mature in 2003, and will be funded
with cash generated from operations, through new financings and short-term
borrowings.
During 2001, we invested $59.1 million in capital expenditures. We also paid
$56.2 million in dividends on capital stock.
At December 31, 2001, we had no current debt maturities, and no commercial
paper borrowings outstanding. During 2001, there were no bank loans or
commercial paper borrowings outstanding.
During 2000, we invested $89.8 million in capital expenditures and $32.0
million in acquisitions. We also paid $285.5 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 6.8 percent.
During 1999, we invested $100.0 million in capital expenditures, and $62.0
million in nuclear decommissioning and other long-term investments. In
10
connection with the power station exchange, we paid approximately $234.0 million
in termination costs and $43.0 million in related taxes to cancel the Beaver
Valley Unit 2 lease.
At December 31, 1999, we had $137.0 million of commercial paper borrowings
outstanding, and $400.0 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.
Capital Expenditures
We spent approximately $59.1 million, $89.8 million and $100.3 million in
2001, 2000 and 1999 for electric utility construction. We estimate that we will
spend, excluding allowance for funds used during construction (AFC),
approximately $70.0 million for electric utility construction in each of the
years 2002, 2003 and 2004.
Acquisitions and Dispositions
During 2001, we sold a portion of our affordable housing portfolio, receiving
proceeds of approximately $3.4 million, which approximated book value.
In 2000, we completed the sale of our generation assets to Orion for
approximately $1.7 billion dollars.
Also during 2000, we purchased from Itron, Inc. the CARS system, the
automated electronic meter reading system developed by Itron for use with our
electricity utility customers. We had previously leased these assets.
During 1999, we completed the power station exchange with FirstEnergy, which
included the assumption of $359.2 million of sale leaseback obligation bonds in
conjunction with the termination of the Beaver Valley Unit 2 lease.
Long-Term Investments
We did not make long-term investments in 2001 and 2000. In 2000 we declared a
dividend involving our investments in landfill and coal-bed methane gas reserves
to DQE.
During 1999, we invested approximately $60.0 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. Cash related to this funding was
collected during the year through the CTC component of customer bills.
Contractual Obligations and Commercial Commitments
We have certain contractual obligations and commercial commitments that
extend beyond 2002, as set forth in the following tables:
Payments Due By Period
- ---------------------------------------------------------------------------------------------------------------------
(In Millions)
--------------------------------------------------------------------
2002 2003 2004 2005 2006 After
--------------------------------------------------------------------
Long-Term Debt $ -- $ 100.0 $ 100.4 $ 0.4 $ 0.4 $ 862.6
Capital Lease Obligations 0.7 0.7 0.7 0.7 0.7 0.9
Operating Leases 3.3 3.3 3.5 3.8 3.8 20.3
- ---------------------------------------------------------------------------------------------------------------------
Total Contractual Cash Obligations $ 4.0 $ 104.0 $ 104.6 $ 4.9 $ 4.9 $ 883.8
=====================================================================================================================
Other Commercial Commitments
- ---------------------------------------------------------------------------------------------------------------------
(In Millions)
--------------------------------------------------------------------
Less than More than
1 year 1-3 years 4-5 years 5 years Total
--------------------------------------------------------------------
Revolving Credit Agreement (a) $ -- $ 150.0 $ -- $ -- $ 150.0
Standby Letters of Credit (a) 9.5 -- -- -- 9.5
Surety Bonds (b)
Commercial 43.3 -- -- -- 43.3
Contract 0.3 -- -- -- 0.3
- ---------------------------------------------------------------------------------------------------------------------
Total Commercial Commitments $ 53.1 $ 150.0 $ -- $ -- $ 203.1
=====================================================================================================================
(a) Revolving Credit Agreement and Letters of Credit are typically for a 364-day
period and are renewed annually. See "Short-Term Borrowing and Revolving Credit
Arrangements," Note H.
(b) Surety bonds are renewed annually. Some of the commercial bonds cover
regulatory and contractual obligations which exceed a one-year period.
11
RATE MATTERS
Competition and the Customer Choice Act
The Pennsylvania Electricity Generation Customer Choice and Competition Act
(Customer Choice Act) enables electric utility customers to purchase electricity
at market prices from a variety of electric generation suppliers. As of December
31, 2001 and February 28, 2002, approximately 78.1 percent and 78.4 percent
measured on a KWH basis, respectively, and approximately 76.8 percent and 75.5
percent on a non-coincident peak load basis, respectively, of our customers
received electricity through our provider of last resort service arrangement
with Orion (discussed below). The remaining customers are provided with
electricity through alternative generation suppliers. As alternative generation
suppliers enter and exit the retail supply business, the number of customers
participating in our provider of last resort service will fluctuate.
Customers who select an alternative generation supplier pay for generation
charges set competitively by that supplier, and pay us a CTC (discussed below)
and transmission and distribution charges. Electricity delivery (including
transmission, distribution and customer service) remains regulated in
substantially the same manner as under historical regulation.
Customer choice and electricity generation deregulation impact traditional
Pennsylvania tax revenues. In order for the state's total revenues to remain
unchanged, a revenue neutral reconciliation tax (RNR) is applied to recover a
shortfall or refund any excess revenues on an annual basis. On November 30,
2001, the Pennsylvania Department of Revenue published an increased RNR rate of
15 mills, effective January 1, 2002, in order to recover a current shortfall.
Pennsylvania electric distribution companies, such as Duquesne Light, are
permitted to recover this cost from consumers on a current basis. On December
21, 2001, the PUC approved our request for the recovery of approximately $13
million of costs we will incur in 2002 due to the RNR. Since January 2002, our
customer bills have reflected an approximate two percent increase.
Regional Transmission Organization
FERC Order No. 2000 calls on transmission-owning utilities such as Duquesne
Light to join regional transmission organizations (RTOs). We are committed to
ensuring a stable, plentiful supply of electricity for our customers. Toward
that end, we anticipate joining the PJM West RTO, which is currently in the
final stages of approval before the FERC. In late 2001 and early 2002, we
entered into agreements under which FirstEnergy Solutions and Orion will supply
the electric capacity required to meet our anticipated capacity credit
obligations in PJM West through 2004. These agreements are subject to, among
other conditions, regulatory approval which we will be seeking. We will also be
seeking to recover the cost of capacity under these agreements from customers,
as contemplated by the PUC's order approving the extension of our provider of
last resort arrangement.
Our participation in the PJM West RTO is conditioned upon regulatory approval
of the agreements, as well as satisfactory recovery of associated costs.
Notwithstanding any such additional costs, customer bills are expected to
decrease as the CTC is collected for each customer class. (See "Competitive
Transition Charge" and "Provider of Last Resort" discussions below.) Our
inclusion in this RTO will put the region's transmission facilities under common
control to enhance reliability to customers.
Competitive Transition Charge
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. On January 18, 2001, the PUC
approved our final accounting for the proceeds of our April 2000 generation
asset sale, including the net recovery of $276.0 million of sale-related
transaction costs. Applying the net generation asset sale proceeds to reduce
transition costs, we now anticipate termination of the CTC collection period by
mid-year 2002 for most major rate classes. Ultimately, the bill is expected to
decrease approximately 16 percent for an average residential customer who takes
provider of last resort service from us pursuant to the second agreement with
Orion discussed below. This decrease reflects the additional cost of electric
capacity required by RTO membership and the additional cost of RNR recovery.
(See "Regional Transmission Organization" and "Competition and Customer Choice
Act" discussions above.) 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
remained following the generation asset sale was approximately $141.9 million
($86.6 million net of tax) at December 31, 2001, on which we are allowed to earn
an 11.0 percent pre-tax return. This amount includes recovery of an additional
$10 million approved by the PUC in early 2002 relating to the December 1999
power station exchange. A lower amount is shown on the balance sheet due to the
accounting for unbilled revenues.
Provider of Last Resort
Although no longer a generation supplier, as the provider of last resort for
all customers in our service territory, we must provide electricity for any
customer who does not choose an alternative generation supplier,
12
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. In
December 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 (POLR II). 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 POLR II agreement described above, we negotiated a rate
freeze for generation, transmission and distribution rates. The rate freeze
fixes new generation rates for retail customers who take electricity under the
extended provider of last resort arrangement, 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.
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."
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEPENDENT AUDITORS' REPORT
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, 2001 and 2000, 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, 2001. 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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, 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 consolidated financial statements, Duquesne
Light Company changed its method of accounting for unbilled revenues as of
January 1, 2000.
/s/ Deloitte & Touche LLP
Pittsburgh, Pennsylvania
January 29, 2002
13
Consolidated Statements of Income
- -------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------------------
Year Ended December 31,
-----------------------------------------
2001 2000 1999
- -------------------------------------------------------------------------------------------------------
Operating Revenues:
Sales of Electricity:
Residential $ 371,666 $ 373,154 $ 401,409
Commercial 456,330 425,451 437,904
Industrial 189,386 206,687 183,112
- -------------------------------------------------------------------------------------------------------
Customer revenues 1,017,382 1,005,292 1,022,425
Utilities 10,686 29,412 76,303
- -------------------------------------------------------------------------------------------------------
Total Sales of Electricity 1,028,068 1,034,704 1,098,728
Other 25,521 41,160 60,072
- -------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,053,589 1,075,864 1,158,800
- -------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel and purchased power 414,309 347,859 225,182
Other operating 99,576 140,409 253,252
Restructuring 10,806 -- --
Maintenance 23,704 50,623 75,400
Depreciation and amortization 331,044 308,154 172,424
Taxes other than income taxes 51,500 58,172 84,532
Income taxes 18,383 27,476 88,246
- -------------------------------------------------------------------------------------------------------
Total Operating Expenses 949,322 932,693 899,036
- -------------------------------------------------------------------------------------------------------
Operating Income 104,267 143,171 259,764
- -------------------------------------------------------------------------------------------------------
Other Income and (Deductions):
Interest and dividend income 31,925 20,892 5,923
Income taxes (13,042) (14,105) (12,119)
Other 5,232 14,357 28,686
- -------------------------------------------------------------------------------------------------------
Total Other Income 24,115 21,144 22,490
- -------------------------------------------------------------------------------------------------------
Income Before Interest and Other Charges 128,382 164,315 282,254
- -------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 62,308 73,545 79,454
Other interest 660 3,149 40,054
Allowance for borrowed funds used during construction (570) (2,030) (836)
- -------------------------------------------------------------------------------------------------------
Total Interest Charges 62,398 74,664 118,672
- -------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily Redeemable Preferred
Trust Securities Dividend Requirements 12,562 12,562 12,562
- -------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect 53,422 77,089 151,020
Cumulative Effect of Change in Accounting Principle - Net -- 15,495 --
- -------------------------------------------------------------------------------------------------------
Net Income After Cumulative Effect 53,422 92,584 151,020
=======================================================================================================
Dividends on Preferred and Preference Stock 3,456 3,411 3,998
- -------------------------------------------------------------------------------------------------------
Earnings for Common Stock, After Cumulative Effect $ 49,966 $ 89,173 $ 147,022
=======================================================================================================
See notes to consolidated financial statements.
14
Consolidated Balance Sheets
- ------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
----------------------------
As of December 31,
----------------------------
ASSETS 2001 2000
- ------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment:
Electric plant in service $ 1,877,887 $ 1,853,043
Construction work in progress 48,742 57,462
Property held under capital leases 10,231 17,842
Other 35,469 36,765
- ------------------------------------------------------------------------------------------------------------
Gross property, plant and equipment 1,972,329 1,965,112
Less: Accumulated depreciation and amortization (627,443) (620,767)
- ------------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment - Net 1,344,886 1,344,345
- ------------------------------------------------------------------------------------------------------------
Long-Term Investments:
Investment in DQE common stock 23,699 41,306
Other investments 5,223 8,253
- ------------------------------------------------------------------------------------------------------------
Total Long-Term Investments 28,922 49,559
- ------------------------------------------------------------------------------------------------------------
Current Assets:
Investment in DQE Capital Cash Pool 314,804 173,524
- ------------------------------------------------------------------------------------------------------------
Receivables:
Electric customer accounts receivable 133,701 134,187
DQE loan receivable 250,000 250,000
Other utility receivables 3,186 16,578
Affiliate receivables 23,935 12,924
Other receivables 12,940 20,828
Less: Allowance for uncollectible accounts (6,307) (9,813)
- ------------------------------------------------------------------------------------------------------------
Total Receivables - Net 417,455 424,704
- ------------------------------------------------------------------------------------------------------------
Materials and supplies 22,166 24,077
Other current assets 19,323 28,969
- ------------------------------------------------------------------------------------------------------------
Total Current Assets 773,748 651,274
- ------------------------------------------------------------------------------------------------------------
Other Non-Current Assets:
Transition costs 134,340 396,379
Regulatory assets 267,167 277,333
Other 11,140 9,470
- ------------------------------------------------------------------------------------------------------------
Total Other Non-Current Assets 412,647 683,182
- ------------------------------------------------------------------------------------------------------------
Total Assets $ 2,560,203 $ 2,728,360
============================================================================================================
See notes to consolidated financial statements.
15
Consolidated Balance Sheets
- ---------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------
As of December 31,
-----------------------------
CAPITALIZATION AND LIABILITIES 2001 2000
- ---------------------------------------------------------------------------------------------------------------------
Capitalization:
Common stock (authorized - 90,000,000 shares, issued and outstanding - 10 shares) $ -- $ --
Capital surplus 483,295 483,275
Retained earnings 44,370 47,104
Accumulated other comprehensive income (loss) (1,012) 9,178
- ---------------------------------------------------------------------------------------------------------------------
Total Common Stockholder's Equity 526,653 539,557
- ---------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily Redeemable Preferred Trust Securities 150,000 150,000
- ---------------------------------------------------------------------------------------------------------------------
Preferred and Preference Stock
(aggregate involuntary liquidation value of $80,304 and $81,035):
Non-redeemable preferred stock 60,608 60,608
Non-redeemable preference stock 17,239 18,028
- ---------------------------------------------------------------------------------------------------------------------
Total preferred and preference stock before deferred ESOP benefit 77,847 78,636
Deferred employee stock ownership plan (ESOP) benefit (3,363) (6,583)
- ---------------------------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock 74,484 72,053
- ---------------------------------------------------------------------------------------------------------------------
Long-term debt 1,061,078 1,060,834
- ---------------------------------------------------------------------------------------------------------------------
Total Capitalization 1,812,215 1,822,444
- ---------------------------------------------------------------------------------------------------------------------
Obligations Under Capital Leases 3,061 10,319
- ---------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Accounts payable 94,248 106,021
Payable to affiliates 37,294 1,456
Accrued liabilities 17,631 34,644
Dividends declared 14,879 18,035
Current debt maturities -- 795
Other 22,239 27,173
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 186,291 188,124
- ---------------------------------------------------------------------------------------------------------------------
Non-Current Liabilities:
Deferred income taxes - net 418,299 519,426
Warwick mine liability 35,033 40,110
Other 105,304 147,937
- ---------------------------------------------------------------------------------------------------------------------
Total Non-Current Liabilities 558,636 707,473
- ---------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes A through P)
- ---------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 2,560,203 $ 2,728,360
=====================================================================================================================
See notes to consolidated financial statements.
16
Consolidated Statements of Cash Flows
- -------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
---------------------------------------
Year Ended December 31,
---------------------------------------
2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income $ 53,422 $ 92,584 $ 151,020
Principal non-cash charges (credits) to net income:
Depreciation and amortization 331,044 308,154 172,424
Restructuring charge 10,806 -- --
Capital lease, nuclear fuel and investment amortization 999 4,156 35,216
Gain on disposition of investments (58) -- (7,573)
Investment income -- (2,995) (34,753)
Cumulative effect of a change in accounting principles - net -- (15,495) --
Deferred taxes (82,714) (109,006) 12,578
Changes in working capital other than cash (178,170) (179,015) (27,536)
Other (16,202) (33,908) 13,816
- -------------------------------------------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 119,127 64,475 315,192
- -------------------------------------------------------------------------------------------------------------------
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 4,981 21,144 20,149
Funding of nuclear decommissioning trust -- -- (59,861)
Long-term investments -- -- (2,289)
Acquisition -- (32,000) --
Capitalized divestiture costs -- (78,752) (47,449)
Construction expenditures (59,098) (89,774) (100,280)
Loan to DQE -- (250,000) --
Other (3,823) (13,684) 5,168
- -------------------------------------------------------------------------------------------------------------------
Net Cash Provided From (Used In) Investing Activities (57,940) 1,104,541 (184,562)
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Reductions of long-term obligations:
Capital leases (7,611) (110) (42,423)
Long-term debt -- (749,236) (75,000)
Dividends on capital stock (56,156) (285,500) (206,997)
Commercial paper -- (136,594) 136,594
Issuance of debt -- -- 290,000
Beaver Valley lease termination -- -- (277,226)
Other 2,580 (13,644) 7,339
- -------------------------------------------------------------------------------------------------------------------
Net Cash Used In Financing Activities $ (61,187) (1,185,084) (167,713)
- -------------------------------------------------------------------------------------------------------------------
Net decrease in cash -- (16,068) (37,083)
Cash, beginning of period -- 16,068 53,151
- -------------------------------------------------------------------------------------------------------------------
Cash, End of Period $ -- $ -- $ 16,068
===================================================================================================================
Supplemental Cash Flow Information
- -------------------------------------------------------------------------------------------------------------------
Cash paid during the year for:
Interest (net of amount capitalized) $ 61,205 $ 79,054 $ 76,950
Income taxes $ 83,034 $ 290,431 $ 83,962
- -------------------------------------------------------------------------------------------------------------------
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
- -------------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
17
Consolidated Statements of Comprehensive Income
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------
Year Ended December 31,
------------------------------
2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------
Net income $ 53,422 $ 92,584 $ 151,020
Other comprehensive income:
Unrealized holding losses arising during the year,
net of tax of $(7,227), $(2,492) and (6,387) (10,190) (3,514) (9,005)
- ---------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 43,232 $ 89,070 $ 142,015
===============================================================================================================
See notes to consolidated financial statements.
Consolidated Statements of Retained Earnings
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------
As of December 31,
------------------------------
2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------
Balance at beginning of year $ 47,104 $ 39,931 $ 27,646
Net income 53,422 92,584 151,020
Dividends declared (56,156) (85,411) (138,735)
- ---------------------------------------------------------------------------------------------------------------
Balance at End of Year $ 44,370 $ 47,104 $ 39,931
===============================================================================================================
See notes to consolidated financial statements.
Notes to Consolidated Financial Statements
A. ACCOUNTING POLICIES
Consolidation
Duquesne Light Company is a wholly owned subsidiary of DQE, Inc. We are
engaged in the transmission and distribution of electric energy.
Our subsidiaries are primarily involved in operating our automated meter
reading technology and providing financing to certain affiliates.
The consolidated financial statements include the accounts of Duquesne Light
and our wholly owned subsidiaries. The equity method of accounting is used when
we have 20 to 50 percent interest in other companies. Under the equity method,
original investments are recorded at cost and adjusted by our share of
undistributed earnings or losses of these companies. All material intercompany
balances and transactions have been eliminated in the consolidation.
Basis of Accounting
We are subject to the accounting and reporting requirements of the Securities
and Exchange Commission (SEC). Our electricity delivery business is also subject
to regulation by the Pennsylvania Public Utility Commission (PUC) and the
Federal Energy Regulatory Commission (FERC) with respect to rates for delivery
of electric power, accounting and other matters.
As a result of our PUC-approved restructuring plan, the electricity supply
segment does not meet the criteria of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." Pursuant to the PUC's final restructuring order, and as provided in
the Pennsylvania Electricity Generation Customer Choice and Competition Act
(Customer Choice Act), generation-related transition costs are being recovered
through a competitive transition charge (CTC) collected in connection with
providing transmission and distribution services, and these assets have been
reclassified accordingly. The 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 electric utility customers through
the ratemaking process. (See Note B.) These regulatory assets as of December 31,
2001 and 2000 consist of a regulatory tax receivable of approximately $225.6
million and $236.7 million, unamortized debt costs of approximately $28.9
million and $30.4 million and deferred employee costs of approximately $12.7
million and $10.2 million, respectively.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates
18
and assumptions with respect to values and conditions that affect the reported
amounts of assets and liabilities, and disclosure of contingent assets and
liabilities, at the date of the financial statements. The reported amounts of
revenues and expenses during the reporting period also may be affected by the
estimates and assumptions management is required to make. We evaluate these
estimates on an ongoing basis, using historical experience, consultation with
experts, and other methods we consider reasonable in the particular
circumstances. Nevertheless, actual results could differ significantly from our
estimates.
Revenues from Utility Sales
Our electric utility operations provide service to approximately 586,000
direct customers in southwestern Pennsylvania (including in the City of
Pittsburgh), a territory of approximately 800 square miles. 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, which totaled
$15.5 million.
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 $59.7 million, $58.6 million and $62.6 million was
recorded in 2001, 2000 and 1999. 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 of tax transition
cost balance (11 percent pre-tax).
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 B, and "Income Taxes," Note
I.) 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, such as transmission fees charged to other utilities that use our
transmission system. In addition, we charge rental fees to third parties who
have cable or other equipment attached to our utility poles and transmission
towers, or who have cable included in our underground ducts.
Following our generation asset sale, other income consists primarily of
interest income from the DQE loan receivable and our investment in the DQE
Capital cash pool. Our average loan and investment balance in 2001 and 2000 was
$474.1 million and $205.7 million, respectively, which earned interest at an
average rate of 6.1 percent and 7.7 percent, respectively. Gains or losses
resulting from the disposition of certain assets are also included here.
Receivables
Receivables on the balance sheet are comprised of outstanding billings for
electric customers and other utilities. In addition, at December 31, 2001 and
2000, electric customer receivables reflect amounts related to unbilled revenues
of $36.6 million and $41.5 million, respectively.
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.
Substantially all of the electric utility properties are subject to a first
mortgage lien.
19
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.
Investment in DQE Capital Cash Pool
We participate in a cash pool arrangement with our affiliate, DQE Capital
Corporation, and its affiliates. Through this arrangement, available cash is
invested and interest is earned daily at a market rate. The amounts shown on the
consolidated balance sheets as investment in the DQE Capital cash pool reflect
the amounts DQE Capital uses in its on-lending operations to affiliates.
Provisions of the DQE Capital cash pool provide us immediate accessibility for
our operational cash needs. Interest is paid monthly and is reflected in other
income on the consolidated statements of income.
Contingent Liabilities
We establish reserves for estimated loss contingencies when it is
management's assessment that a loss is probable and the amount can be reasonably
estimated. Revisions to contingent liabilities are reflected in income in the
period in which different facts or information become known, or circumstances
change, that affect the previous assumptions with respect to the likelihood or
amount of loss. Reserves for contingent liabilities are based upon management's
assumptions and estimates, advice of legal counsel, or other third parties
regarding probable outcomes of the matter. Should the ultimate outcome differ
from the assumptions and estimates, revisions to the estimated reserves for
contingent liabilities would be recognized. Such contingent liabilities for
Duquesne Light include, but are not limited to, restructuring liabilities (see
Note C) and other commitments and contingencies (see Note K).
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.
Derivatives
On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," the impact of which was not significant to
our financial statements.
Dividends
DQE's dividend policy requires subsidiaries to dividend their net income, if
cash is available. In addition, special dividends are declared periodically
related to proceeds from asset sales and other special circumstances. During the
years ended December 31, 2001 and 2000, we declared cash dividends of $52.7
million and $82.0 million, respectively, to DQE as estimates of our net income
for the year. Following the sale of our generation assets in 2000, we declared a
special cash dividend of $200.0 million to DQE. This dividend was reflected on
the consolidated balance sheets as a reduction to capital surplus.
Reclassification
The 2000 and 1999 consolidated financial statements have been reclassified to
conform with the 2001 presentation.
Recent Accounting Pronouncements
In June 2001 the Financial Accounting Standards Board (FASB) issued three new
accounting standards, SFAS No. 141, "Business Combinations," SFAS No. 142,
"Goodwill and Other Intangibles" and SFAS No. 143, "Accounting for Asset
Retirement Obligations."
SFAS No. 141 eliminates the pooling-of-interests method of accounting for
business combinations with limited exceptions for combinations initiated prior
to July 1, 2001. We do not believe that the adoption of SFAS No. 141 will have a
significant impact on our financial statements.
SFAS No. 142, which became effective January 1, 2002, discontinues the
requirement for amortization of goodwill and indefinite-lived intangible assets,
and instead requires an annual review for the impairment of those assets.
Impairment is to be examined more frequently if certain indicators appear.
Intangible assets with a determinable life will continue to be amortized. As of
December 31, 2001, we have no goodwill or other intangible assets that will be
subject to the transitional assessment provisions of SFAS No. 142.
SFAS No. 143 addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. Specifically, this standard requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred, if a reasonable estimate of fair value can be made. The
entity is required to capitalize the cost by increasing the carrying amount of
the related long-lived asset. The capitalized cost is then depreciated over the
useful life of the related asset. Upon settlement of the liability, an entity
either settles the obligation for its recorded amount or incurs a gain or loss.
The standard is effective for fiscal years beginning after June 15, 2002. We are
currently evaluating, but have yet to determine, the impact that the adoption of
SFAS No. 143 will have on our financial statements.
In August 2001 the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets," which replaces SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of."
The statement requires that all long-lived assets to be held and used continue
to be evaluated for impairment similar to SFAS No. 121. The statement also
requires that all long-lived assets to be sold be measured at the lower of
carrying amount or fair value less cost to sell, whether reported in continuing
20
operations or in discontinued operations. Therefore, discontinued operations
will no longer be measured on a net realizable value basis and will not include
amounts for future operating losses. The statement also broadens the reporting
requirements for discontinued operations to include disposal transactions of all
components of an entity (rather than segments of a business). Components of an
entity include operations and cash flows that can be clearly distinguished from
the rest of the entity that will be eliminated from the ongoing operations of
the entity in a disposal transaction. The statement is effective for fiscal
years beginning after December 15, 2001. We are currently evaluating, but have
yet to determine, the impact that the adoption of SFAS No. 144 will have on our
financial statements.
B. R A T E M A T T E R S
Competition and the Customer Choice Act
The Customer Choice Act enables electric utility customers to purchase
electricity at market prices from a variety of electric generation suppliers. As
of December 31, 2001, approximately 78.1 percent of our customers measured on a
KWH basis and approximately 76.8 percent on a non-coincident peak load basis
received electricity through our provider of last resort service arrangement
with Orion (discussed below). The remaining customers are provided with
electricity through alternative generation suppliers. As alternative generation
suppliers enter and exit the retail supply business, the number of customers
participating in our provider of last resort service will fluctuate.
Customers who select an alternative generation supplier pay for generation
charges set competitively by that supplier, and pay us a CTC (discussed below)
and transmission and distribution charges. Electricity delivery (including
transmission, distribution and customer service) remains regulated in
substantially the same manner as under historical regulation.
Customer choice and electricity generation deregulation impact traditional
Pennsylvania tax revenues. In order for the state's total revenues to remain
unchanged, a revenue neutral reconciliation tax (RNR) is applied to recover a
shortfall or refund any excess revenues on an annual basis. On November 30,
2001, the Pennsylvania Department of Revenue published an increased RNR rate of
15 mills, effective January 1, 2002, in order to recover a current shortfall.
Pennsylvania electric distribution companies, such as Duquesne Light, are
permitted to recover this cost from consumers on a current basis. On December
21, 2001, the PUC approved our request for the recovery of approximately $13
million of costs we will incur in 2002 due to the RNR. Since January 2002, our
customer bills have reflected an approximate two percent increase.
Regional Transmission Organization
FERC Order No. 2000 calls on transmission-owning utilities such as Duquesne
Light to join regional transmission organizations (RTOs). We are committed to
ensuring a stable, plentiful supply of electricity for our customers. Toward
that end, we anticipate joining the PJM West RTO, which is currently in the
final stages of approval before the FERC. In late 2001 and early 2002, we
entered into agreements under which FirstEnergy Solutions and Orion will supply
the electric capacity required to meet our anticipated capacity credit
obligations in PJM West through 2004. These agreements are subject to, among
other conditions, regulatory approval which we will be seeking. We will also be
seeking to recover the cost of capacity under these agreements from customers as
contemplated by the PUC's order approving the extension of our provider of last
resort arrangement.
Our participation in the PJM West RTO is conditioned upon regulatory approval
of the agreements, as well as satisfactory recovery of associated costs.
Notwithstanding any such additional costs, customer bills are expected to
decrease as the CTC is collected for each customer class. (See "Competitive
Transition Charge" and "Provider of Last Resort" discussions below.) Our
inclusion in this RTO will put the region's transmission facilities under common
control to enhance reliability to customers.
Competitive Transition Charge
On December 3, 1999, we completed the exchange of our partial interests in
five power plants for three wholly owned power plants from FirstEnergy Corp. In
connection with this exchange, we terminated the 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 its
generation assets, including plant and regulatory assets, through the collection
of the CTC from electric utility customers. On January 18, 2001, the PUC
approved our final accounting for the proceeds of our April 2000 generation
asset sale, including the net recovery of $276.0 million of sale-related
transaction costs. Applying the net generation asset sale proceeds to reduce
transition costs, we now anticipate termination of the CTC collection period by
mid-year 2002 for most major rate classes. Ultimately, the bill is expected to
decrease approximately 16 percent for an average residential customer who takes
provider of last resort service from us pursuant to the second agreement
21
with Orion discussed below. This decrease reflects the additional cost of
electric capacity required by RTO membership and the additional cost of RNR
recovery. (See "Regional Transmission Organization" and "Competition and
Customer Choice Act" discussions above.) 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
remained following the generation asset sale was approximately $141.9 million
($86.6 million net of tax) at December 31, 2001, on which we are allowed to earn
an 11.0 percent pre-tax return. This amount includes recovery of an additional
$10 million approved by the PUC in early 2002 relating to the December 1999
power station exchange. A lower amount is shown on the balance sheet due to the
accounting for unbilled revenues.
Provider of Last Resort
Although no longer a generation supplier, as the provider of last resort for
all customers in our service territory, we must provide electricity for any
customer who does not choose an alternative generation supplier, or whose
supplier fails to deliver. As part of the generation asset sale, 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. In December 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 (POLR II). 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 POLR II agreement described above, we negotiated a rate
freeze for generation, transmission and distribution rates. The rate freeze
fixes new generation rates for retail customers who take electricity under the
extended provider of last resort arrangement, and continues the transmission and
distribution rates for all customers at current levels through at least 2003.
Under certain circumstances, affected interests may file a complaint alleging
that, under these frozen rates, we have exceeded reasonable earnings, in which
case the PUC could make adjustments to rectify such earnings.
C. R E S T R U C T U R I N G C H A R G E
During the fourth quarter of 2001, as part of DQE's Back-to-Basics strategy,
we initiated a restructuring plan to improve operational effectiveness and
efficiency, and to reduce operational expenses. We recorded a pre-tax
restructuring charge of $10.8 million ($6.7 million after tax). The
restructuring charge included costs related to (1) the consolidation and
reduction of certain administrative and back-office functions through an
involuntary termination plan, (2) the abandonment of certain office facilities
to relocate employees to one centralized location, and (3) other lease costs
related to abandoned office facilities.
The following is a summary of the restructuring charge that was reflected as
a separately stated charge against operating income for the year ended December
31, 2001.
Restructuring Charge at December 31,
- -----------------------------------------------------------
(Thousands of Dollars)
--------------------------
2001
- -----------------------------------------------------------
Employee termination benefits $ 8,337
Facilities consolidation:
Future minimum lease payments 1,491
Other lease costs 978
- -----------------------------------------------------------
Total Restructuring Charge $ 10,806
===========================================================
The employee-related termination benefits of $8.3 million primarily include
severance costs for approximately 100 management, professional and
administrative personnel.
The facilities consolidation involved relocation to our existing leased
space in downtown Pittsburgh. In December 2001, we extended the lease at this
facility to December 2011.
We accrued liabilities related to these restructuring actions in the period
in which we committed to execute the restructuring plan and communicated the
plan to employees. The following table summarizes the components of the accrued
restructuring liability for the period ended December 31, 2001.
Restructuring Liability at December 31,
- --------------------------------------------------------------
(Thousands of Dollars)
--------------------------
2001
- --------------------------------------------------------------
Beginning balance $ 10,544
Charges paid/incurred (1,701)
- --------------------------------------------------------------
Ending Balance $ 8,843
==============================================================
22
We believe that the remaining provision is adequate to complete the
restructuring plan. We also expect that the remaining restructuring liabilities
will be paid and/or incurred on a monthly basis throughout 2006.
D. T R A N S A C T I O N S W I T H A F F I L I A T E S
As a wholly owned subsidiary of DQE, we have various transactions with our
parent company and its subsidiaries, including the following items.
We generally pay quarterly dividends to DQE that approximate our net income.
(See Note A.) As a holder of DQE common stock, we receive dividend income from
DQE.
We participate in a cash pool arrangement with our affiliate, DQE Capital,
and its affiliates. (See Note A.) Following the sale of our generation assets in
2000, we loaned $250.0 million of the sale proceeds to DQE, which remains
outstanding as of December 31, 2001. The demand note bears a market rate of
interest and is reflected on the consolidated balance sheet as DQE loan
receivable.
DQE charges a fee for administrative and other expenses based on an
allocation method that considers, among other things, the subsidiaries' assets,
revenues and employees.
We participate in a tax sharing agreement with DQE to provide, among other
things, for the payment of taxes for periods which DQE and we are included in
the same consolidated group for Federal tax purposes. We share in the
consolidated tax liability to the extent of our income or loss for the year.
(See Note I.)
Certain of our revenues and expenses relate to transactions with DQE and its
subsidiaries, including the following:
- -------------------------------------------------------------------
(Thousands of Dollars)
------------------------------
Year Ended December 31,
------------------------------
2001 2000 1999
- -------------------------------------------------------------------
Revenues and Other Income:
Interest income $ 29.2 $ 16.1 $ --
Affiliate electric energy sales 3.3 5.5 5.2
Dividend income from
DQE common stock 2.1 2.1 2.4
Pole rental revenue 0.9 0.9 0.6
Expenses:
Administrative cost allocations $ 4.8 $ 13.1 $ 8.5
Office building rent expense 3.2 4.3 4.1
Rental of communication fiber 0.2 0.2 0.2
- -------------------------------------------------------------------
E. A C Q U I S I T I O N S A N D D I S P O S I T I O N S
During 2001, we sold a portion of our affordable housing portfolio, receiving
proceeds of approximately $3.4 million, which approximated book value.
In 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 Note B.) We also dividended two non-
electric subsidiaries to DQE.
F. P R O P E R T Y, P L A N T A N D E Q U I P M E N T
In April 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.
G. L O N G - T E R M I N V E S T M E N T S
At December 31, 2001 and 2000, the fair market value of our investment in DQE
common stock was $23.7 million and $41.3 million, and the cost of our investment
was $25.4 million and $25.6 million.
H. S H O R T - T E R M B O R R O W I N G A N D R E V O L V I N G
C R E D I T A R R A N G E M E N T S
We maintain a $150 million revolving credit agreement expiring in October
2002. We may convert the revolver into a term loan facility for a one-year
period, for any amounts then outstanding upon expiration of the revolving credit
period. The interest rate can, in accordance with the option selected at the
time of the borrowing, be based on one of several indicators, including prime
and Eurodollar rates. Commitment fees are based on the unborrowed amount of the
commitment. We plan to extend the facility prior to its expiration. At December
31, 2001 and 2000, no borrowings were outstanding.
Under our credit facility, we are subject to financial covenants requiring us
to maintain a maximum debt-to-
23
capitalization ratio of 65 percent. At December 31, 2001 we were in compliance,
having debt-to-capitalization ratio of 58.8 percent.
During 2001 there were no bank loans or commercial paper borrowings
outstanding.
I. I N C O M E T A X E S
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 1993. The IRS examination of the 1994 tax year has been completed and
the IRS issued a notice of proposed upward adjustment to DQE's 1994 taxable
income with respect to certain structured transactions. This resulted in an
increased 1994 tax liability of approximately $22 million for DQE, including
penalties and interest, all of which was paid by DQE in December 2001. DQE has
protested the proposed IRS adjustment for 1994, and that protest is currently
pending with the IRS Appeals Office. The IRS currently is auditing the 1995
through 1997 tax returns, which include deductions relating to the same
transactions disallowed in the IRS audit of the 1994 tax year, as well as
certain other structured transactions. Tax years 1998 through 2001 remain
subject to IRS review. The IRS has indicated that it is considering proposing
adjustments to DQE's reporting of these structured transactions on its tax
returns for the open years. While it is impossible to predict the amount of any
proposed IRS adjustment for any of the open tax years, or whether or to what
extent any IRS proposed adjustments for 1994 will be sustained, DQE does do not
believe that the ultimate resolution of any federal income tax liability for the
years 1994 through 2001 will have a material adverse effect on its financial
position, results of operations or cash flows.
Deferred Tax Assets (Liabilities) at December 31,
- -------------------------------------------------------------
(Thousands of Dollars)
---------------------------
2001 2000
- -------------------------------------------------------------
Warwick Mine closing costs $ 14,536 $ 16,643
Other 45,401 49,545
- -------------------------------------------------------------
Deferred tax assets 59,937 66,188
- -------------------------------------------------------------
Property depreciation (290,339) (291,420)
Transition costs (47,019) (138,733)
Regulatory assets (93,588) (98,236)
Loss on reacquired
debt unamortized (11,972) (12,601)
Other (35,318) (44,624)
- -------------------------------------------------------------
Deferred tax liabilities (478,236) (585,614)
- -------------------------------------------------------------
Net $ (418,299) $ (519,426)
=============================================================
Income Tax Expense (Benefit)
- --------------------------------------------------------------------
(Thousands of Dollars)
--------------------------------------
Year Ended December 31,
--------------------------------------
2001 2000 1999
- --------------------------------------------------------------------
Currently payable:
Federal $ 99,326 $ 298,941 $ 95,815
State 1,771 -- 28,453
Deferred - net:
Federal (84,613) (271,626) (25,130)
State 1,899 161 (8,048)
ITC deferred - net -- -- (2,844)
- --------------------------------------------------------------------
Total Included in
Operating Expenses 18,383 27,476 88,246
- --------------------------------------------------------------------
Included in other income
and deductions:
Federal 13,042 14,105 (35,991)
State -- -- (490)
Deferred - net:
Federal -- -- 48,623
State -- -- --
ITC -- -- (23)
- --------------------------------------------------------------------
Total Included in
Other Income and
Deductions 13,042 14,105 12,119
- --------------------------------------------------------------------
Total Income
Tax Expense $ 31,425 $ 41,581 $ 100,365
====================================================================
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,
----------------------------------
2001 2000 1999
- -------------------------------------------------------------------
Federal taxes at
statutory rate (35%) $ 29,696 $ 41,535 $ 87,985
Increase (decrease) in
taxes resulting from:
State income taxes 2,379 105 12,945
Investment tax benefits (732) -- (270)
Amortization of
deferred ITC -- -- (2,867)
Other 82 (59) 2,572
- -------------------------------------------------------------------
Total Income Tax
Expense (Benefit) $ 31,425 $ 41,581 $ 100,365
===================================================================
24
J. L E A S E S
We lease office buildings, computer equipment, and other property and
equipment.
Capital Leases at December 31,
- ----------------------------------------------------------------
(Thousands of Dollars)
-----------------------
2001 2000
- ----------------------------------------------------------------
Electric plant $ 10,231 $ 17,842
Less: Accumulated amortization (7,058) (6,486)
- ----------------------------------------------------------------
Capital Leases - Net $ 3,173 $ 11,356
================================================================
Summary of Rental Expense
- -------------------------------------------------------------------
(Thousands of Dollars)
----------------------------
Year Ended December 31,
----------------------------
2001 2000 1999
- -------------------------------------------------------------------
Operating leases $ 8,603 $ 18,143 $ 51,723
Amortization of capital leases 305 444 18,889
Interest on capital leases 1,173 1,042 1,512
- -------------------------------------------------------------------
Total Rental Payments $ 10,081 $ 19,629 $ 72,124
===================================================================
Future Minimum Lease Payments
- -------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------
Operating Capital
Year Ended December 31, Leases (a) Leases
- -------------------------------------------------------------------
2002 $ 3,340 $ 739
2003 3,323 739
2004 3,485 739
2005 3,804 739
2006 and thereafter 24,118 1,479
- -------------------------------------------------------------------
Total $ 38,070 $ 4,435
- -------------------------------------------------------------------
Less: Amount representing interest (1,262)
- -------------------------------------------------------------------
Present value $ 3,173
===================================================================
(a) Includes $1.5 million of projected rent payments expensed as part of the
2001 restructuring charge ($0.3 million in each of the years 2002 through
2006). These future cash payments will decrease the restructuring liability.
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.
In December 2001, we amended the existing lease at our downtown Pittsburgh
facility and extended the lease term to December 2011. The lease agreement
contains one five-year renewal option.
K. C O M M I T M E N T S A N D C O N T I N G E N C I E S
Construction, Investments and Acquisitions
We estimate that we will spend, excluding AFC, approximately $70.0 million
for each of 2002, 2003 and 2004 for electric utility construction.
Employees
We are renegotiating our labor contract with the International Brotherhood of
Electrical Workers (IBEW), which represents the majority of our 1,302 employees.
The contract currently expires in September 2002.
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 $1.1 million in
2001 to comply with these DEP regulations. We expect the costs of compliance to
be approximately $1.4 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.
We own, but do not operate, the Warwick Mine, including approximately 1,200
acres of unmined coal lands and mining rights, located along the Monongahela
River in Greene County, Pennsylvania. This property had been used in the
electricity supply business segment. Our current estimated liability for closing
Warwick Mine, including final site reclamation, mine water treatment and certain
labor liabilities, is approximately $35.0 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.
L. E M P L O Y E E B E N E F I T S
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 plan 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
25
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. Pension costs charged (credited) to
expense or construction were ($21.0) million for 2001, ($13.5) million for 2000
and $11.2 million for 1999.
In 2001, we approved an amendment to the pension plan for a cost of living
adjustment for benefits for certain retirees. This caused an increase in the
Projected Benefit Obligation of $11.9 million.
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, while the remaining $12.0 million was reflected in the
unrecognized actuarial gain/loss account. In our 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.
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, 2001, a statement of
the funded status as of December 31, 2001 and 2000, 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
---------------------------------------------------------
2001 2000 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of year $ 546,473 $ 578,726 $ 31,859 $ 57,558
Service cost 5,125 6,230 865 979
Interest cost 39,332 39,574 2,543 2,837
Actuarial (gain) loss 3,776 (24,142) 11,707 (7,547)
Benefits paid (35,000) (36,810) (3,700) (3,749)
Plan amendments 11,922 -- -- (1,613)
Curtailment gains (70) (17,546) -- (21,948)
Settlements (252) (291) -- --
Special termination benefits -- 732 -- 5,342
- ------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year 571,306 546,473 43,274 31,859
- ------------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of year 732,225 744,155 -- --
Actual return (loss) on plan assets (34,090) 24,464 -- --
Employer contributions -- -- -- --
Benefits paid (34,465) (36,394) -- --
- ------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 663,670 732,225 -- --
- ------------------------------------------------------------------------------------------------------------------------
Funded status 92,364 185,752 (43,274) (31,859)
Unrecognized net actuarial (gain) loss (165,689) (272,242) 4,642 (7,188)
Unrecognized prior service cost 24,046 14,561 -- --
Unrecognized net transition obligation 2,975 4,053 7,107 7,889
- ------------------------------------------------------------------------------------------------------------------------
Accrued benefit cost $ (46,304) $ (67,876) $ (31,525) $ (31,158)
========================================================================================================================
26
Weighted-Average Assumptions as of December 31,
- ------------------------------------------------------------------------------------------------------------------------
Pension Postretirement
--------------------------------------------------
2001 2000 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
Discount rate used to determine projected
benefits obligation 7.25% 7.50% 7.25% 7.50%
Assumed rate of return on plan assets 7.50% 7.50% -- --
Assumed change in compensation levels 4.00% 4.25% -- --
Ultimate health care cost trend rate -- -- 5.75% 6.00%
All of our plans for postretirement benefits, other than pensions, have no plan
assets. The aggregate benefit obligation for those plans was $43.3 million as of
December 31, 2001 and $31.9 million as of December 31, 2000. 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 was 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)
------------------------------------
2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------------
Components of net pension cost:
Service cost $ 5,125 $ 6,230 $ 14,374
Interest cost 39,332 39,574 39,929
Expected return on plan assets (53,394) (50,441) (45,562)
Amortization of unrecognized net transition obligation 1,136 1,148 1,759
Amortization of prior service cost 1,864 2,027 3,458
Recognized net actuarial gain (15,082) (12,052) (2,717)
- --------------------------------------------------------------------------------------------------------------------------
Net pension (gain) cost (21,019) (13,514) 11,241
Curtailment cost (gain) 120 943 (14)
Settlement cost 461 287 78
Special termination benefits -- 732 17,376
- --------------------------------------------------------------------------------------------------------------------------
Net Pension (Gain) Cost After Curtailments,
Settlements and Special Termination Benefits $ (20,438) $ (11,552) $ 28,681
==========================================================================================================================
Components of Postretirement Cost as of December 31,
- ----------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------------
2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------
Components of postretirement cost:
Service cost $ 865 $ 979 $ 1,799
Interest cost 2,543 2,837 3,099
Amortization of unrecognized net transition obligation 659 925 1,642
Amortization of prior service costs -- (7) --
Recognized net actuarial gain -- (16) --
- ----------------------------------------------------------------------------------------------------------------------------
Net postretirement cost 4,067 4,718 6,540
Curtailment (gain) cost -- (6,377) 2,443
Special termination benefits -- 5,343 --
- ----------------------------------------------------------------------------------------------------------------------------
Net Postretirement Cost After Curtailments $ 4,067 $ 3,684 $ 8,983
============================================================================================================================
27
Effect of a One Percent Change in Health Care Cost Trend Rates as of December
31, 2001
- --------------------------------------------------------------------------------------------------
(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 $ 309 $ (273)
Effect on the health care component of the accumulated
postretirement benefit obligation $3,147 $(2,816)
Retirement Savings Plan and Other Benefit Options
DQE sponsors separate 401(k) retirement plans for management and IBEW-
represented employees of its affiliates, including Duquesne Light.
The 401(k) Retirement Savings Plan for Management Employees provides for
employer contributions which may include a participant base match and a
participant incentive match and automatic contributions. In 2001 and 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 O.)
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 2001 and 2000, all
IBEW-represented employees achieved their incentive targets.
DQE's shareholders have approved a long-term incentive plan through which DQE
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.
The following tables summarize the transactions of DQE's stock option plans
for the three-year period ended December 31, 2001:
- ---------------------------------------------------------------------------------------------------------------------------
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------
Number of Options Weighted Average Price
-------------------------------------------------------------
2001 2000 1999 2001 2000 1999
-------------------------------------------------------------
Options outstanding, beginning of year 1,292 1,031 1,231 $ 39.32 $ 30.28 $ 32.57
Options granted 1,120 697 258 $ 20.92 $ 42.65 $ 39.35
Options exercised (58) (409) (300) $ 37.72 $ 31.81 $ 29.69
Options canceled/forfeited (155) (27) (158) $ 38.07 $ 37.63 $ 39.81
-------------------------------------------------------------
Options outstanding, end of year 2,199 1,292 1,031 $ 29.90 $ 39.32 $ 30.28
-------------------------------------------------------------
Options exercisable, end of year 873 770 651 $ 38.18 $ 37.91 $ 33.80
-------------------------------------------------------------
Shares available for future grants, end of year 2,690 3,091 3,678
---------------------------
As of December 31, 2001, 2000 and 1999, stock appreciation rights (SARs) had
been granted in connection with 1,036,373; 975,292 and 933,014 of the options
outstanding. During 2001, 2000 and 1999, 58,061; 208,236 and 45,265 SARs were
exercised. During December 2001, 787,300 stock options were granted to employees
with an exercise price of $16.90 per share.
One half of these options become exercisable only if the closing price on the
New York Stock Exchange of DQE's common stock averages $19.56 for 30 consecutive
trading days, with the remainder becoming exercisable under the same terms at a
target price of $22.49 per share. The options vest over an 18 month period from
the date of grant.
28
- ---------------------------------------------------------------------------------------------------------------------------
Outstanding Exercisable
- ---------------------------------------------------------------------------------------------------------------------------
Number Remaining Weighted Number Weighted
of Options Life Average of Options Average
Exercise Price Range (In Thousands) (In Years) Exercise Price (In Thousands) Exercise Price
- ---------------------------------------------------------------------------------------------------------------------------
Under $20 813 9.9 $16.97 -- --
$20 - $30 66 2.8 $25.54 66 $ 25.54
$30 - $40 673 4.9 $33.36 379 $ 34.98
Over $40 647 5.5 $42.93 428 $ 42.68
- ---------------------------------------------------------------------------------------------------------------------------
Options, End of Year 2,199 873
===========================================================================================================================
M. L O N G-T E R M D E B T
Long-Term Debt at December 31,
- ------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
----------------------------
Interest Principal Outstanding
Rate Maturity 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
First mortgage bonds (a) 6.450%-8.375% 2003-2038 $ 643,000 $ 643,000
Pollution control notes Adjustable (b) 2009-2030 417,985 417,985
Sinking fund debentures 5.00% 2010 2,791 2,791
Less: Unamortized debt discount and premium - net (2,698) (2,942)
- ------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt $1,061,078 $1,060,834
========================================================================================================================
(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 1.7 percent in 2001 and 4.7 percent in 2000.
At December 31, 2001, there were no sinking fund requirements or maturities
of long term debt outstanding for 2002. Sinking fund requirement and maturities
of long-term debt for 2003 through 2006 were $100.0 million in 2003, $100.4
million in 2004, $0.4 million in 2005 and $0.4 million in 2006.
Total interest and other charges were $62.4 million in 2001, $74.7 million in
2000 and $118.7 million in 1999. Interest costs attributable to debt were $62.3
million, $73.5 million and $79.5 million in 2001, 2000 and 1999, respectively.
Of the interest costs attributable to debt, $0.6 million in 2001, $2.0 million
in 2000 and $0.8 million in 1999 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.
At December 31, 2001, 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 $1,101.5 million. The principal amount
included in the consolidated balance sheet, excluding unamortized discounts and
premiums, is $1,063.8 million.
At December 31, 2001 and 2000, we were in compliance with all of our debt
covenants.
N. C O M P A N Y O B L I G A T E D M A N D A T O R I L Y
R E D E E M A B L E P R E F E R R E D T R U S T S E C U R I T I E S
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, Series A (MIPS), each with a
stated liquidation value of $25.00. At December 31, 2001, there were six million
shares authorized and outstanding. The holders of MIPS are entitled to
distributions at the annual rate of 8 3/8 percent, payable monthly. MIPS
dividends included in interest and other charges were $12.6 million in 2001,
2000 and 1999. Duquesne Capital, at our direction, has the option to redeem the
MIPS at any time, in whole or in part. The MIPS are also subject to mandatory
redemption at the maturity of the Debentures referred to below.
Duquesne Capital applied the proceeds of the sale of the MIPS, together with
certain other funds, to the
29
purchase from us of $151.5 million principal amount of our 8 3/8 percent
Subordinated Deferrable Interest Debentures, Series A, due May 31, 2044
(Debentures). The Debentures are Duquesne Capital's sole assets, and Duquesne
Capital has no business activity other than holding the Debentures. We have
guaranteed the payment of distributions on, and redemption price and liquidation
amount in respect of the MIPS, to the extent that Duquesne Capital has funds
available for such payment from the Debentures. Upon any redemption of the MIPS,
the Debentures will be mandatorily redeemed.
O . P R E F E R R E D A N D P R E F E R E N C E S T O C K
Preferred and Preference Stock at December 31,
- ---------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-------------------------------------------------------
2001 2000
Call Price -------------------------------------------------------
Per Share Shares Amount Shares Amount
- ---------------------------------------------------------------------------------------------------------------------
Preferred Stock Series (a):
3.75% $ 51.00 148,000 $ 7,407 148,000 $ 7,407
4.00% 51.50 549,709 27,486 549,709 27,486
4.10% 51.75 119,860 6,012 119,860 6,012
4.15% 51.73 132,450 6,643 132,450 6,643
4.20% 51.71 100,000 5,021 100,000 5,021
$2.10 51.84 159,400 8,039 159,400 8,039
- ---------------------------------------------------------------------------------------------------------------------
Total Preferred Stock 60,608 60,608
- ---------------------------------------------------------------------------------------------------------------------
Preference Stock Series (b):
Plan Series A 35.50 558,673 17,239 579,276 18,028
- ---------------------------------------------------------------------------------------------------------------------
Deferred ESOP benefit (3,363) (6,583)
- ---------------------------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock $ 74,484 $ 72,053
=====================================================================================================================
(a) 4,000,000 authorized shares; $50 par value; cumulative; $50 per share
involuntary liquidation value.
(b) 8,000,000 authorized shares; $1 par value; cumulative; $35.50 per share
involuntary liquidation value in 2001; $35.78 per share involuntary liquidation
value in 2000.
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. 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, 2001, we had made all dividend payments. Preferred and preference dividends
were $3.5 million, $3.4 million and $4.0 million in 2001, 2000 and 1999. Total
preferred and preference stock had involuntary liquidation values of $80.3
million and $81.0 million, which exceeded par by $19.3 million and $20.0
million, at December 31, 2001 and 2000.
Outstanding preferred stock is generally callable on notice of not less than
30 days, at stated prices plus accrued dividends. The outstanding preference
stock is callable at the liquidation price plus accrued dividends. 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 Note L.) 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. 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,
2001, $17.2 million of preference stock issued in connection with the
establishment of the ESOP had been offset, for financial statement purposes, by
a $3.4 million 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 $1.5 million, $1.0 million and $0.2 million
for 2001, 2000 and 1999. These cash contributions were the difference between
the ESOP debt service and the amount of dividends on ESOP shares ($1.6 million
in 2001, $1.7 million in 2000 and $2.1 million in 1999). 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.
30
We recognized compensation expense related to the 401(k) plans of $1.7 million,
$2.1 million and $3.6 million in 2001, 2000 and 1999.
P. E Q U I T Y
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, 2001.
Following is a table describing our accumulated other comprehensive income
(loss).
Accumulated Other Comprehensive Income (Loss) Balances as of December 31,
- ----------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------
2001 2000
- ----------------------------------------------------------------------------
January 1 $ 9,178 $ 12,692
Unrealized losses, net of tax
of $(7,227) and $(2,492) (10,190) (3,514)
- ----------------------------------------------------------------------------
December 31 $ (1,012) $ 9,178
============================================================================
Q. S U P P L E M E N T A L C A S H F L O W D I S C L O S U R E S
Changes in Working Capital Other than Cash
(Net of Dispositions, Acquisitions and Restructuring Charges) for the Year Ended
December 31,
- ------------------------------------------------------------------------------
(Thousands of Dollars)
----------------------------------
2001 2000 1999
- ------------------------------------------------------------------------------
Investment in DQE
Capital Cash Pool $(141,280) $(173,524) $ --
Receivables 7,249 (2,976) (1,695)
Materials and supplies 1,911 (8,878) 37,128
Other current assets 9,646 27,115 (26,567)
Accounts payable (21,299) (761) (13,132)
Other current liabilities (34,397) (19,991) (23,270)
- ------------------------------------------------------------------------------
Total $(178,170) $(179,015) $(27,536)
==============================================================================
R. B U S I N E S S S E G M E N T S A N D R E L A T E D I N F O R M A T I O N
We report the results of our business segments, determined by products,
services and regulatory environment as follows: (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.
31
Business Segments as of December 31,
- ---------------------------------------------------------------------------------------------------------------------------------
(Millions of Dollars)
-----------------------------------------------------------------------------
Electricity Electricity Consoli-
Delivery Supply CTC dated
-----------------------------------------------------------------------------
2001
- ---------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 319.6 $ 430.3 $ 303.7 $ 1,053.6
Operating expenses 161.2 430.3 20.1 611.6
Depreciation and amortization expense 59.7 -- 271.3 331.0
- ---------------------------------------------------------------------------------------------------------------------------------
Operating income 98.7 -- 12.3 111.0
Other income 24.1 -- -- 24.1
Interest and other charges 78.4 -- -- 78.4
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock
before restructuring charges 44.4 -- 12.3 56.7
Restructuring charge, net of tax (6.7) -- -- (6.7)
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 37.7 $ -- $ 12.3 $ 50.0
=================================================================================================================================
Assets $2,425.9 $ $ 134.3 $ 2,560.2
=================================================================================================================================
Capital expenditures $ 59.1 $ -- $ -- $ 59.1
=================================================================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
(Millions of Dollars)
--------------------------------------------------------------------
Electricity Electricity Consoli-
Delivery) Supply CTC dated
--------------------------------------------------------------------
2000
- ------------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 316.1 $ 425.4 $ 334.4 $1,075.9
Operating expenses 172.4 412.8 39.2 624.4
Depreciation and amortization expense 56.4 2.2 249.6 308.2
- ------------------------------------------------------------------------------------------------------------------------------------
Operating income 87.3 10.4 45.6 143.3
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 36.1 (8.0) 45.6 73.7
Cumulative effect of change in
accounting principle 7.3 8.2 -- 15.5
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 43.4 $ 0.2 $ 45.6 $ 89.2
====================================================================================================================================
Assets $2,332.0 $ -- $ 396.4 $2,728.4
====================================================================================================================================
Capital expenditures $ 85.1 $ 4.7 $ -- $ 89.8
====================================================================================================================================
32
(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
===============================================================================================
5. Q U A R T E R L Y F I N A N C I A L I N F O R M A T I O N
( U N A U D I T E D )
Summary of Selected Quarterly Financial Data (Thousands of Dollars)
- ------------------------------------------------------------------------------
[The quarterly data reflect seasonal weather variations in the electric
utility's service territory.]
- ------------------------------------------------------------------------------
2001 First Quarter Second Quarter Third Quarter Fourth Quarter
- --------------------------------------------------------------------------------------------------------
Operating revenues $ 245,410 $ 263,322 $ 296,225 $ 248,632
Operating income 23,147 27,589 30,436 23,095
Net income 9,911 15,430 17,598 10,483 (a)
==========================================================================================================
2000 (b) 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
==========================================================================================================
(a) Restructuring charges of $6.7 million after tax are included in fourth
quarter results. (See Note C.) This charge is related to the consolidation
and reclassification associated with DQE's Back-to-Basics strategy.
(b) Restated to reflect the cumulative effect of a change in accounting
principle related to unbilled revenues.
_____________________________
33
SELECTED FINANCIAL DATA
- ------------------------------------------------------------------------------------------------------------------------------------
(Amounts in Millions of Dollars) 2001 2000 1999 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT ITEMS
Total operating revenues $ 1,053.6 $ 1,075.9 $ 1,158.8 $ 1,178.7 $ 1,175.9 $ 1,187.4
Operating income $ 104.3 $ 143.2 $ 259.8 $ 204.1 $ 207.4 $ 222.1
Income before extraordinary item
and cumulative effect $ 53.4 $ 77.1 $ 151.0 $ 148.5 $ 141.8 $ 149.9
Extraordinary item $ -- $ -- $ -- $ (82.5) $ -- $ --
Cumulative effect of change
in accounting principle $ -- $ 15.5 $ -- $ -- $ -- $ --
Net income after extraordinary item
and cumulative effect $ 53.4 $ 92.6 $ 151.0 $ 66.0 $ 141.8 $ 149.9
Earnings for common stock
before extraordinary item
and cumulative effect $ 50.0 $ 73.7 $ 147.0 $ 144.5 $ 137.8 $ 145.8
Earnings for common stock
after extraordinary item
and cumulative effect $ 50.0 $ 89.2 $ 147.0 $ 62.0 $ 137.8 $ 145.8
- --------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET ITEMS
Property, plant and equipment - net $ 1,344.9 $ 1,344.3 $ 1,458.5 $ 1,447.3 $ 2,562.9 $ 2,717.5
Total assets $ 2,560.2 $ 2,728.4 $ 4,281.4 $ 4,309.6 $ 3,840.2 $ 3,897.1
- ------------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Common stockholder's equity $ 526.6 $ 539.5 $ 798.6 $ 868.5 $ 1,003.8 $ 989.4
Non-redeemable preferred and
preference stock 74.5 72.1 79.5 77.8 76.5 73.1
Company obligated mandatorily
redeemable preferred trust securities 150.0 150.0 150.0 150.0 150.0 150.0
Long-term debt 1,061.1 1,060.8 $ 1,410.8 $ 1,160.3 1,218.3 1,272.0
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 1,812.2 $ 1,822.4 $ 2,438.9 $ 2,256.6 $ 2,448.6 $ 2,484.5
- ------------------------------------------------------------------------------------------------------------------------------------
34
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 Directors is set forth on Exhibit 99.1 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."
ITEM 11. EXECUTIVE COMPENSATION.
Information relating to executive compensation is set forth on Exhibit 99.1
hereto. The information is incorporated here by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information relating to the ownership of equity securities of DQE by our
directors, officers and certain beneficial owners is set forth on Exhibit 99.1
hereto. 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 in Item 8 (Consolidated
Financial Statements and Supplementary Data) of this Report. The following
financial statements and Independent Auditors' Report are incorporated here by
reference:
Independent Auditors' Report.
Consolidated Statements of Income for the Three Years Ended December 31,
2001.
Consolidated Balance Sheets, December 31, 2001 and 2000.
Consolidated Statements of Cash Flows for the Three Years Ended December 31,
2001.
Consolidated Statements of Comprehensive Income for the Three Years Ended
December 31, 2001.
Consolidated Statements of Retained Earnings for the Three Years Ended
December 31, 2001.
Notes to Consolidated Financial Statements.
(a)(2) The following financial statement schedule and the related Independent
Auditors' Report are filed here as a part of this Report:
Schedule for the Three Years Ended December 31, 2001:
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
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. 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. 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 filed a report on Form 8-K on December 20, 2001 to report on a DQE
presentation made to the financial community.
We filed a report on Form 8-K on February 19, 2002 to report DQE's 2001
year-end earnings release.
35
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 DQE
Orion Power Holdings, Inc., and The Cleveland Electric 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 DQE
Power Holdings, Inc. 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.
36
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.
Supplemental Indenture No. 17 and Supplemental Exhibit 4.2 to the Duquesne
Indenture No. 18. Light Registration Statement
(Form S-3) No. 333-72408.
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.
37
Exhibit Method of
No. Description Filing
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 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.
10.2 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.
10.3 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.
10.4 Duquesne Light/DQE Charitable Giving Program, Exhibit 10.6 to the Form 10-K
as amended. Annual Report of DQE for the
year ended December 31, 1996.
10.5 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.
10.6 Non-Competition and Confidentiality Agreement dated as Exhibit 10.10 to the Form 10-K
of October 21, 1996 between DQE, Duquesne Light and Annual Report of DQE for the
Victor A. Roque. year ended December 31, 2001.
10.7 Non-Competition and Confidentiality Agreement dated as Filed here.
of August 1, 2000 between Duquesne Light and
Joseph G. Belechak.
10.8 Non-Competition and Confidentiality Agreement dated as Filed here.
of April 2, 1997 between Duquesne Light and
Maureen L. Hogel.
10.9 Non-Competition and Confidentiality Agreement dated as Exhibit 10.15 to the Form 10-K
of October 4, 1996 between Duquesne Light and Annual Report of DQE for the
William J. DeLeo. year ended December 31, 2001.
10.10 Non-Competition and Confidentiality Agreement dated as Filed here.
of November 1, 2000 between Duquesne Light and
David R. High.
10.11 Amended and Restated POLR II Agreement by and between Exhibit 10.12 to the Form 10-K
Duquesne Light Company and Orion Power MidWest, L.P., Annual Report of Duquesne
dated as of December 7, 2000. Light Company for the year
ended December 31, 2000.
38
Exhibit Method of
No. Description Filing
10.12 Capacity Agreement by and between Duquesne Light and Filed here.
FirstEnergy Solutions Corp. dated as of December 18, 2001.
10.13 Amendment No. 1 to the Capacity Agreement by and between Filed here.
Duquesne Light and FirstEnergy Solutions Corp. made as of
February 15, 2002.
10.14 Capacity Agreement by and between Duquesne Light and Filed here.
Orion Power Midwest, L.P. dated as of February 15, 2002.
12.1 Ratio of Earnings to Fixed Charges. Filed here.
21.1 Subsidiaries of the registrant. Filed here.
23.1 Independent Auditors' Consent. Filed here.
99.1 Information Regarding Directors; Executive Compensation;. Filed here.
and Security Ownership of Directors and Officers for 2001.
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, 2002,
subject to payment in advance of the cost of reproducing the exhibits requested.
39
SCHEDULE II
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2001, 2000 and 1999
(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, 2001
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $ 9,813 $ 7,932 $ 2,644(A) $ 14,082(B) $ 6,307
------------ ------------ ------------ -------------- ------------
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
------------ ------------ ------------ -------------- ------------
Notes: (A) Recovery of accounts previously written off.
(B) Accounts receivable written off.
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 28, 2002 By: /s/ Victor A. Roque
------------------------
(Signature)
Victor A. Roque
President
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/ Victor A. Roque President and Director March 28, 2002
- ------------------------------
Victor A. Roque (Principal Executive Officer)
/s/ Frosina C. Cordisco Vice President and Treasurer March 28, 2002
- ------------------------------
Frosina C. Cordisco (Principal Financial Officer)
/s/ Stevan R. Schott Vice President and Controller March 28, 2002
- ------------------------------
Stevan R. Schott (Principal Accounting Officer)
/s/ Morgan K. O'Brien Director March 28, 2002
- ------------------------------
Morgan K. O'Brien
/s/ Frank A. Hoffmann Director March 28, 2002
- ------------------------------
Frank A. Hoffmann
/s/ Alexis Tsaggaris Director March 28, 2002
- ------------------------------
Alexis Tsaggaris