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, 1999
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From ____________ to ____________
Commission File Number
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1-956
Duquesne Light Company
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-0451600
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Seventh Avenue
Pittsburgh, Pennsylvania 15219
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 393-6000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements for
the past 90 days. Yes X No
--- ---
DQE, Inc., is the holder of all shares of Duquesne Light Company common stock,
$1 par value, consisting of 10 shares as of February 29, 2000.
[ ] 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
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Duquesne Light Company Preferred Stock New York Stock Exchange
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Involuntary
Series Liquidation Value
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3.75% $50 per share
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4.00% $50 per share
- ---------------------------------------------------------
4.10% $50 per share
- ---------------------------------------------------------
4.15% $50 per share
- ---------------------------------------------------------
4.20% $50 per share
- ---------------------------------------------------------
$2.10 $50 per share
- ---------------------------------------------------------
8.375% $25 per share (1)
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Sinking Fund Debentures, due March 1, 2010 (5%) New York Stock Exchange
7-3/8% Quarterly Interest Bonds, due 2038 New York Stock Exchange
(1) Issued by Duquesne Capital, L.P., and the payments of dividends and payments
on liquidation or redemption are guaranteed by Duquesne Light Company.
TABLE OF CONTENTS
Page
GLOSSARY
PART I
ITEM 1. BUSINESS
Corporate Structure 1
Employees 1
Property, Plant and Equipment (PP&E) 2
Electric Utility Operations 2
Environmental Matters 2
Outlook 3
Other 4
Executive Officers of the Registrant 5
ITEM 2. PROPERTIES 6
ITEM 3. LEGAL PROCEEDINGS 7
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS 7
PART II
ITEM 5. MARKET FOR REGISTRANT'S
COMMON EQUITY AND RELATED
SHAREHOLDER MATTERS 7
ITEM 6. SELECTED FINANCIAL DATA 7
ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Results of Operations 7
Liquidity and Capital Resources 11
Rate Matters 12
Year 2000 14
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK 14
ITEM 8. REPORT OF INDEPENDENT AUDITORS;
CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA 14
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 34
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT 34
ITEM 11. EXECUTIVE COMPENSATION 34
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT 34
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 34
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K 34
SCHEDULE II
SIGNATURES
GLOSSARY OF TERMS
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 a per kilowatt-hour charge.
Customer Choice -- The Pennsylvania Electricity Generation Customer Choice and
Competition Act (see "Rate Matters" on page 12) gives consumers the right to
contract for electricity at market prices from PUC-approved electric generation
suppliers.
Decommissioning Costs -- Decommissioning costs are expenses to be incurred in
connection with the entombment, decontamination, dismantling, removal and
disposal of structures, systems and components of a power plant that has
permanently ceased the production of electric energy.
Deferred Energy Costs -- In conjunction with the Energy Cost Rate Adjustment
Clause, we historically recorded our deferred energy costs to offset differences
between actual energy costs and the level of energy costs recovered from our
rate-regulated electric utility customers.
Divestiture -- The selling of major assets. We anticipate completing the
divestiture of our generation assets through the sale to Orion Power Holdings,
Inc.
Energy Cost Rate Adjustment Clause (ECR) -- Until May 29, 1998, we had
historically recovered, through the ECR, our cost of nuclear fuel, fossil fuel
and purchased power costs, when such amounts were not included in base rates.
Federal Energy Regulatory Commission (FERC) -- The FERC is an independent five-
member commission within the United States Department of Energy. Among its many
responsibilities, the FERC sets rates and charges for the wholesale
transportation and sale of electricity.
Pennsylvania Public Utility Commission (PUC) -- The governmental body that
regulates all utilities (electric, gas, telephone, water, etc.) that do business
in Pennsylvania.
Price to Compare -- The PUC-determined market price of electric generation for
each utility during the CTC collection period. Customers will experience savings
if they can purchase power from an alternative electric generation supplier at a
lower price than the amount determined by the PUC.
Provider of Last Resort -- Under Pennsylvania's Customer Choice Act, the local
distribution utility is required to provide electricity for customers who cannot
or do not choose an alternative generation supplier, or whose supplier fails to
deliver. (See "Rate Matters" on page 12.)
Regulatory Assets -- Pennsylvania rate making practices grant regulated
utilities exclusive geographic franchises in exchange for the obligation to
serve all customers. Under this system, certain prudently-incurred costs are
approved by the PUC for deferral and future recovery with a return from
customers. These deferred costs are capitalized as regulatory assets by the
regulated utility.
Restructuring Plan -- Our plan, approved by the PUC, for restructuring and
recovery of our transition costs under Pennsylvania's Customer Choice Act.
Transition Costs -- Transition costs are the net present value of a utility's
known or measurable costs related to electric generation that are recoverable
through the CTC.
Transmission and Distribution -- These terms have a special meaning in the
electric utility industry. 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).
Watt -- A watt is the rate at which electricity is generated or consumed. A
kilowatt is equal to 1,000 watts. A kilowatt-hour (KWH) is a measure of the
quantity of electricity generated or consumed in one hour by one kilowatt of
power. A megawatt (MW) is 1,000 kilowatts or one million watts.
PART I
ITEM 1. BUSINESS.
CORPORATE STRUCTURE
Part I of this Annual Report on Form 10-K should be read in conjunction with
our audited consolidated financial statements, which are set forth on pages 15
through 32 of this Report. Explanations of certain financial and operating terms
used in this Report are set forth in a GLOSSARY at the front of this Report.
Duquesne Light Company is a wholly owned subsidiary of DQE, Inc., a multi-
utility delivery and services company. Our one wholly owned subsidiary is
Monongahela Light and Power Company, which makes long-term investments.
We are engaged in the supply, transmission, distribution and sale of electric
energy. On December 3, 1999, we completed a power station asset exchange with
FirstEnergy Corp. This was the first phase of our Pennsylvania Public Utility
Commission (PUC)-approved plan to divest our generation assets. We expect to
complete this divestiture through the pending sale of our remaining generation
assets to Orion Power Holdings, Inc. Final sale agreements must be approved by
various regulatory agencies, including the PUC. We expect the sale to close in
the second quarter of 2000. After that time, we expect to meet our energy supply
obligations through a provider of last resort service agreement with Orion. (See
"Restructuring Plan" discussion on page 13.)
Service Area
We provide service to approximately 580,000 direct customers in southwestern
Pennsylvania (including in the City of Pittsburgh), a territory of approximately
800 square miles. We have also historically sold electricity to other utilities,
and will continue to do so until the generation asset sale is complete. (See
"Restructuring Plan" discussion on page 13.)
Regulation
We are subject to the accounting and reporting requirements of the Securities
and Exchange Commission (SEC). In addition, our electric utility operations are
subject to regulation by the PUC, including regulation under the Pennsylvania
Electricity Generation Customer Choice and Competition Act (Customer Choice
Act), and the Federal Energy Regulatory Commission (FERC) under the Federal
Power Act with respect to rates for interstate sales, transmission of electric
power, accounting and other matters.
As a result of the PUC's May 29, 1998, final order regarding our restructuring
plan under the Customer Choice Act (see "Rate Matters" on page 12), the
electricity supply segment of our business does not meet the criteria of
Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the
Effects of Certain Types of Regulation (SFAS No. 71). Pursuant to the PUC's
final restructuring order, our generation-related regulatory assets are being
recovered through a competitive transition charge (CTC) collected in connection
with providing transmission and distribution services, and these assets have
been reclassified accordingly. The balance of transition costs will be adjusted
by receipt of the proceeds from the pending generation asset sale. The
electricity delivery business segment continues to meet SFAS No. 71 criteria,
and accordingly reflects regulatory assets and liabilities consistent with
cost-based rate making regulations. The regulatory assets represent probable
future revenue, because provisions for these costs are currently included, or
are expected to be included, in charges to electric utility customers through
the ratemaking process. (See "Rate Matters" on page 12.)
On December 15, 1999, the FERC issued its Order No. 2000, which calls on
transmission-owning utilities such as Duquesne Light to voluntarily join
regional transmission organizations. The goal of the order is to put
transmission facilities in a region under common control in an effort to reduce
costs. The order requires utilities to file a proposal for a regional
transmission organization, a description of efforts to join one, or reasons for
not joining one, by October 15, 2000. We are currently studying Order No. 2000,
and have not yet determined our response.
Business Segments
For the purposes of complying with SFAS No. 131, Disclosures about Segments of
an Enterprise and Related Information (SFAS No. 131), we are required to
disclose information about our business segments separately. This information
is set forth in "Results of Operations" on page 7 and in "Business Segments and
Related Information," Note N to our consolidated financial statements on
page 31.
EMPLOYEES
At December 31, 1999, we had 2,142 employees. This reflects a reduction by
approximately 1,100 employees through transfers to FirstEnergy following the
power station exchange and early retirement under the divestiture-related
program discussed below. In connection with the pending generation asset sale to
Orion, we anticipate a further reduction by approximately 400 employees. We are
a party to a labor contract expiring in September 2001 with the International
Brotherhood of Electrical Workers (IBEW), which represents the majority of our
employees. The contract provides, among other things, employment security,
income protection and, in September 2000, a 3 percent wage increase. We have
agreed with the IBEW on a package of
1
additional benefits and protections for union employees affected by the
divestiture of generation assets.
In connection with the power station exchange with FirstEnergy and the pending
generation asset sale to Orion, we developed early retirement programs and
enhanced available separation packages for eligible IBEW and management
employees. We expect to recover related costs through the sale proceeds.
PROPERTY, PLANT AND EQUIPMENT (PP&E)
Investment in PP&E and Accumulated Depreciation
Our total investment in PP&E and the related accumulated depreciation balances
for major classes of property at December 31, 1999 and 1998 are as follows:
PP&E and Related Accumulated Depreciation at December 31,
- ------------------------------------------------------------------------------
(Millions of Dollars)
1999
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Accumulated Net
Investment Depreciation Investment
- ------------------------------------------------------------------------------
Electric delivery $1,913.1 $ 726.8 $1,186.3
Electric production 2,013.0 1,764.2 248.8
Capital leases 26.0 7.6 18.4
Other 7.1 2.1 5.0
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Total $3,959.2 $2,500.7 $1,458.5
====================================================
1998
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Accumulated Net
Investment Depreciation Investment
- ------------------------------------------------------------------------------
Electric delivery $1,858.4 $ 684.6 $1,173.8
Electric production 2,600.9 2,393.7 207.2
Capital leases 123.4 63.5 59.9
Other 6.4 __ 6.4
----------------------------------------------------
Total $4,589.1 $3,141.8 $1,447.3
====================================================
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. Electric production
PP&E includes fossil and, in 1998, nuclear generating stations. Electric
production accumulated depreciation reflects the write-down of production plant
values to the PUC-determined market value. (See "Restructuring Plan" discussion
on page 13.) Our capital leases are primarily associated with leased nuclear
fuel in 1998 and other electric plant. The Other PP&E is comprised mostly of
coalbed methane gas recovery equipment.
ELECTRIC UTILITY OPERATIONS
We anticipate completing the divestiture of generation assets through the sale
to Orion in the second quarter of 2000. Certain obligations related to the
divested assets have been transferred to FirstEnergy, and others will be
transferred to Orion.
Our fossil plants operated at an availability factor of 86 percent in 1999 and
80 percent in 1998. Our nuclear plants (which all were acquired by FirstEnergy
in December 1999) operated at an availability factor of 84 percent in 1999 and
52 percent in 1998. The timing and duration of scheduled maintenance and
refueling outages, as well as the duration of forced outages, affect the
availability of power stations. We normally experience our peak demand in the
summer. The 1999 customer system peak demand of 2,756 megawatts (MW) occurred
on July 6, 1999.
Fossil Fuel
We believe that sufficient coal for our coal-fired generating units will be
available from various sources to satisfy our requirements through the closing
of the pending generation asset sale. During 1999, approximately 2.0 million
tons of coal were consumed at our two wholly owned coal-fired stations, Cheswick
Power Station (Cheswick) and Elrama Power Station (Elrama).
We own Warwick Mine, an underground mine located in southwestern Pennsylvania.
The current estimated liability for mine closing, including final site
reclamation, mine water treatment and certain labor liabilities, is
$49.3 million. We have recorded a liability for this amount on the consolidated
balance sheet.
During 1999, 52 percent of our coal supplies were provided by contracts,
including Warwick Mine, with the remainder satisfied through purchases on the
spot market.
ENVIRONMENTAL MATTERS
Various federal and state authorities regulate us with respect to air and
water quality and other environmental matters. Environmental compliance
obligations with respect to the plants transferred to FirstEnergy in the power
station exchange have been assumed by FirstEnergy. In addition, FirstEnergy has
contractually retained responsibility for operating the plants we acquired in
the exchange, including the day-to-day environmental compliance. Upon completion
of the generation asset sale, Orion will assume the environmental obligations
related to all of the plants sold, both those we originally owned and those we
acquired in the power station exchange. The following discussion of air quality
and acid rain compliance primarily addresses environmental matters at the plants
we both own and operate: Cheswick, Elrama, Brunot Island and Phillips.
2
As required by Title V of the Clean Air Act Amendments (Clean Air Act), we
filed comprehensive air operating permit applications for Cheswick, Elrama,
Brunot Island and Phillips in 1995. Approval is still pending for these
applications. We filed our Title IV Phase II Clean Air Act compliance plan with
the PUC on December 27, 1995. We also filed Title IV Phase II permit
applications for oxides of nitrogen (NO\x\) emissions from Cheswick, Elrama and
Phillips with the Allegheny County Health Department and the Pennsylvania
Department of Environmental Protection (DEP) on December 23, 1997. On December
30, 1999, we amended the Cheswick and Elrama applications, and filed a Phase II
NO\x\ Averaging Plan. Approval also is pending for these applications.
Acid Rain Program Requirements. We believe we have satisfied all of the Phase
I Acid Rain Program requirements of the Clean Air Act. However, the Phase II
Acid Rain Program requires significant additional reductions of sulfur dioxide
(SO\2\) through the end of 2000. We currently own and operate 611 MW of coal
capacity equipped with SO\2\ emission-reducing equipment.
In 1999 we installed gas reburn NO\x\ reduction technology at Elrama Units 1,2
and 3, and installed new, improved low NO\x\ burner technology at Elrama Unit
4. In 1998, we installed low-cost burner modifications to existing low NO\x\
burner technology, and a new flue gas conditioning system, to maximize the
effects of combustion-related controls at Cheswick.
Ozone Reduction Requirements. In addition to the Phase II Acid Rain Program
requirements, we are responsible for No\x\ reduction requirements to meet the
current Ozone Ambient Air Quality Standards under Title I of the Clean Air Act.
Compliance with the current ozone standard is based on pre-1997 ozone data,
using a one-hour average value approach. During the 1998 summer ozone season,
the western Pennsylvania "area" achieved compliance with the one-hour ozone
standard. We believe we will continue our current low NO\x\ emission levels
under the maintenance plan being established by the DEP. We further believe we
will be able to meet any additional NO\x\ reduction levels specified under the
maintenance plan, through reductions required in 1999 under the Ozone Transport
Commission control program described below.
In September 1998, the Environmental Protection Agency (EPA) issued additional
ozone-related NO\x\ reduction requirements under Section 110 of the Clean Air
Act, which may affect our power plants and supersede reduction levels specified
for 2003 by the Ozone Transport Commission control program. Under this program,
the EPA requires states in the northeast and midwest to amend their
implementation plans to impose more stringent No\x\ allowance caps on emissions
during the May to September control period. In response to a Federal court stay
of this program, the DEP has not finalized proposed implementation regulations,
but has indicated it will proceed with a similar control program under Section
126 of the Clean Air Act. Until the Federal stay is resolved and regulations
are implemented, the costs of compliance cannot be determined. However, we
anticipate that compliance would require additional capital and operational
costs beyond those already estimated through 2000. Such compliance costs will be
the responsibility of Orion following the generation asset sale.
Other. On November 3, 1999, the EPA and the Department of Justice filed suit
against seven electric utility companies, including FirstEnergy. The suit
alleges that the companies made illegal modifications to certain power plants,
including Sammis Unit 7. FirstEnergy acquired our interest in Sammis in the
power station exchange. The ultimate outcome of this suit, and any potential
impact it may have on us, cannot be determined at this time.
In 1992, the DEP issued Residual Waste Management Regulations governing the
generation and management of non-hazardous residual waste, such as coal ash. We
have assessed our residual waste management sites, and the DEP has approved our
compliance strategies. We incurred capital costs of $0.5 million in 1999 to
comply with these DEP regulations. We expect the capital cost of compliance to
be approximately $5.0 million over the next two years with respect to sites we
will continue to own after the generation asset sale.
Under the Emergency Planning and Community Right-to-Know Act of 1986,certain
manufacturing and industrial companies are required to file annual toxic release
inventory reports. The first submission by coal- and oil-fired electric utility
generating stations was made on July 1, 1999, to report on emissions and
discharges for 1998. Toxic release inventory reporting does not involve emission
reductions. We do not anticipate any material impact resulting from this
requirement.
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.
OUTLOOK
As discussed previously, we expect to close on the sale of our generation
assets to Orion during the second quarter of 2000. However, if the closing is
delayed we will experience electricity market price risks during the volatile
summer months. In that event, we would evaluate entering into advance purchase
power contracts to mitigate the risk of price spikes similar to those seen
during the summer of 1999. If the closing is delayed beyond September 24, 2000,
3
Orion could, under certain circumstances, terminate the transaction. In that
event, while exploring other divestiture options, we would continue to operate
the generating plants and would continue to collect CTC revenues at current
levels.
Prospectively, assuming that the sale to Orion closes as expected, we will be
much smaller than we have been historically. Among the challenges we will face
is changing the role of our administrative infrastructure. While the number of
electricity customers that we serve will not change, our margins from these
customers will decline to reflect the fact that we are providing only the
delivery service and not the electricity itself. Our reduced electricity margins
will necessitate a lower level of support costs at the electricity business. We
expect to retrain and redeploy some of our administrative employees, but we must
also reduce our overall administrative costs to maintain profitability.
Also related to the generation divestiture, we will be changing our capital
structure. With the proceeds from the sale, we expect to retire higher-cost
series of outstanding debt and to reduce the level of equity accordingly to
create a capital structure appropriate for an electricity delivery company.
OTHER
Retirement Plan Measurement Assumptions
The discount rate used to determine the projected benefit obligation on our
retirement plans at December 31, 1999, increased to 7.5 percent. The effect of
this change on our retirement plan obligations is reflected in the amounts
shown in "Employee Benefits," Note M to the consolidated financial statements,
on page 28. The resulting change in related expenses for subsequent years is
not expected to be material.
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities. This statement
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts,
(collectively referred to as derivatives) and for hedging activities. We are
evaluating the impact on our financial statements and disclosures.
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 30 percent of long-term
borrowings. This variable rate debt is low-cost, tax-exempt debt. We also manage
our interest rate risk by retiring and issuing debt from time to time and by
maintaining a balance of short-term, medium-term and long-term debt. A 10
percent increase in interest rates would have affected our variable rate debt
obligations by increasing interest expense by approximately $1.6 million for the
years ended December 31, 1999, 1998 and 1997. A 10 percent reduction in interest
rates would have increased the market value of our fixed rate debt by
approximately $20.3 million and $40.1 million as of December 31, 1999 and
1998. Such changes would not have had a significant near-term effect on our
future earnings or cash flows.
--------------------
Except for historical information contained herein, the matters discussed in
this report are forward-looking statements that involve risks and uncertainties
including, but not limited to: the timing of the anticipated transfer of
generation assets to Orion and receipt of sale proceeds; the nature of final
regulatory approvals regarding the generation asset sale; the final outcome of
AYE's merger-related litigation; economic, competitive, governmental and
technological factors affecting operations, markets, products, services and
prices; and other factors discussed in our filings with the Securities and
Exchange Commission.
4
EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below are the names, ages as of March 10, 2000, positions, and brief
accounts of the business experience during the past five years of our executive
officers.
Name Age Office
David D. Marshall 47 Chairman and Chief Executive Officer since August 1999.
Chairman, President and Chief Executive Officer from
June 1999 to August 1999. President and Chief Executive
Officer from August 1996 to June 1999. President and
Chief Operating Officer from February 1995 to August 1996.
John R. Marshall 50 President since August 1999. Previously,Vice President -
Consumer and Small Business Market Unit of Entergy
Corporation from 1996 to August 1999. Vice President -
Information Systems of Entergy Corporation from
1995 to 1996.
Victor A. Roque 53 Senior Vice President and General Counsel since November
1998. Vice President and General Counsel from April
1995 to November 1998.
Gary L. Schwass 54 Senior Vice President since February 1995 and Chief
Financial Officer since July 1989.
William J. DeLeo 49 Vice President - Corporate Services since November 1998.
Vice President - Marketing and Corporate Performance
from April 1995 to November 1998.
Edward N. Neal 53 Vice President - Customer Operations since January 1999.
Assistant General Manager - System Reliability from
September 1996 to January 1999. Assistant General
Manager - Customer Operations from May 1995 to
September 1996. Manager - Construction, Maintenance &
Engineering from May 1994 to May 1995.
Morgan K. O'Brien 40 Vice President - Finance since November 24, 1998. Vice
President - Finance, Treasurer and Controller from November
1 to November 24, 1998. Vice President and Controller from
October 1997 to November 1, 1998. Controller from October 1995
to April 1996 and September 24, 1996 to October 1997. Assistant
Controller from December 1993 to October 1995.
Stevan R. Schott 37 Vice President and Controller since August 1999. Previously,
Controller of Montauk, Inc. from October 1998 to August
1999. Deloitte & Touche LLP - Senior Manager and Public
Utilities Specialist from September 1993 to September 1998.
Maureen L. Hogel 39 Vice President - Legal since September 1999. Assistant
General Counsel from February 1996 to September 1999.
Previously, Associate with Drinker, Biddle &Reath from
September 1988 to February 1996.
5
ITEM 2. PROPERTIES.
Our principal properties consist of electric generating stations, transmission
and distribution facilities and supplemental properties and
appurtenances, comprising as a whole an integrated electric utility
system, 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. Certain pollution control facilities are subject to an additional
mortgage lien.
On December 3, 1999, we completed a power station exchange with FirstEnergy
Corporation, acquiring ownership of three fossil-powered plants (located in Avon
Lake and Niles, Ohio, and in New Castle, Pennsylvania) in exchange for our
ownership interests in two nuclear-powered plants (located in Beaver Valley,
Pennsylvania and Perry, Ohio) and three fossil-powered plants (located in Bruce
Mansfield, Pennsylvania and Sammis and Eastlake, Ohio). We plan to complete the
divestiture of our generation assets (including the three newly-acquired plants)
through the pending sale of generation assets to Orion Power Holdings Inc. These
properties have been used in the electricity supply business segment.
Share of Net Net Plant Output
Demonstrated Capability Year Ended
(Megawatts) December 31, 1999
Name and Location Type Summer Winter (Megawatt-hours)
- ----------------- ---- ------ ------ -----------------
Cheswick Coal 562 570 3,031,366
Springdale, PA
Elrama Coal 474 487 1,752,001
Elrama, PA
Sammis Unit 7 (1) Coal 187 187 1,071,148
Stratton, OH
Eastlake Unit 5 (1) Coal 186 186 833,510
Eastlake, OH
Beaver Valley Unit 1 (1) Nuclear 385 385 2,657,210
Shippingport, PA
Beaver Valley Unit 2 (1) Nuclear 113 113 755,862
Shippingport, PA
Perry Unit 1 (1) Nuclear 161 164 1,141,338
North Perry, OH
Bruce Mansfield Unit 1 (1) Coal 228 228 1,004,164
Shippingport, PA
Bruce Mansfield Unit 2 (1) Coal 62 62 315,458
Shippingport, PA
Bruce Mansfield Unit 3 (1) Coal 110 110 522,458
Shippingport, PA
Brunot Island Oil 189 234 18,817
Brunot Island, PA
Avon Lake (2) Coal 731 739 301,109
Avon Lake, OH
New Castle (2) Coal 339 338 122,400
New Castle, PA
Niles (2) Coal 246 246 115,069
Niles, OH ----- ----- ----------
Total 13,641,910
==========
Share of Capacity 1/1/99 - 12/3/99 2,657 2,726
===== =====
Share of Capacity 12/4/99 - 12/31/99 2,541 2,614
===== =====
(1) Amounts represent our share of the unit which we owned in common with one
or more other electric utilities (or, in the case of Beaver Valley Unit 2,
we leased). Plant output shown is from January 1, 1999 through December 3,
1999, the date of the power station exchange. These plants were transferred
to FirstEnergy in the power station exchange.
(2) Plant output shown is from December 4, 1999 through December 31, 1999.
These plants were acquired from FirstEnergy in the power station exchange.
6
We own 17 transmission substations (including two acquired in the power
station exchange) and 557 distribution substations. We have 671 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 50,000 miles of lines and cable. These properties are used in the
electricity delivery business segment.
We own, but do not operate, the Warwick Mine, including 4,849 acres owned in
fee of unmined coal lands and mining rights, located on the Monongahela River in
Greene County, Pennsylvania. This property has been used in the electricity
supply business segment.
Additional information relating to properties is set forth in "Property, Plant
and Equipment," Note C to the consolidated financial statements on page 22 of
this Report. The information is incorporated here by reference.
ITEM 3. LEGAL PROCEEDINGS.
Eastlake Unit 5
From September 1995 until December 1999, we and a FirstEnergy subsidiary, the
Cleveland Electric Illuminating Company, had been involved in litigation
regarding the then jointly owned Eastlake facility. Upon closing the power
station exchange, we entered into a settlement agreement (approved by the United
States District Court for the Northern District of Ohio, Eastern Division)
dismissing the litigation. (See "Power Station Exchange" discussion on
page 13.)
Termination of the AYE Merger
On October 5, 1998, DQE announced the unilateral termination of the merger
agreement with Allegheny Energy, Inc. (AYE). DQE believes that AYE suffered a
material adverse effect as a result of the PUC's final restructuring order
regarding AYE's utility subsidiary, West Penn Power Company. AYE filed suit in
the United States District Court for the Western District of Pennsylvania,
seeking to compel DQE to proceed with the merger, or in the alternative seeking
an unspecified amount of money damages. On October 28, 1998, the judge ruled in
DQE's favor regarding termination of the merger agreement. AYE appealed to the
United States Court of Appeals for the Third Circuit, who on March 11, 1999,
remanded the case to the District Court for further proceedings. Trial was held
from October 20 through 28, 1999. On December 3, 1999, the District Court ruled
that DQE had properly terminated the merger agreement without breach, and
granted judgment in its favor on all claims and all requests for injunctive
relief. On December 14, 1999, AYE appealed this decision to the United States
Court of Appeals for the Third Circuit. Argument was heard by the Third Circuit
on March 9, 2000, and a decision is pending. DQE will continue to defend itself
vigorously against AYE's claims. The ultimate outcome of the appeal cannot be
determined at this time.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS.
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S
COMMON EQUITY AND RELATED
SHAREHOLDER MATTERS.
All of our common stock is held solely by DQE; none is publicly traded.
During 1999 and 1998, we declared quarterly dividends on our common stock
totaling $203 million and $207 million, respectively.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data for each year of the six-year period ended December
31, 1999, are set forth on page 33. The information is incorporated here by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF
OPERATIONS.
RESULTS OF OPERATIONS
Overall Performance
In the second quarter of 1998, the PUC issued an order related to our plan to
recover our transition costs from electric utility customers. As a result of the
order, we recorded an extraordinary charge against earnings of $82.5 million, or
$1.06 per share of DQE common stock. The following discussion of results of
operations excludes the impact of that charge.
1999 Compared to 1998
Our earnings available for common stock were $147.0 million in 1999 compared
to $144.5 million in 1998, an increase of $2.5 million or 1.7 percent. This
increase was due to decreased purchased power costs as a result of improved
generating station availability. This increase was partially offset by decreased
revenues due to customer choice.
1998 Compared to 1997
Our earnings available for common stock were $144.5 million in 1998 compared
to $137.8 million in 1997, an increase of $6.7 million or 4.9 percent. This
increase was due
7
in part to reduced depreciation in accordance with the PUC's restructuring order
as well as a decrease in financing costs. Partially offsetting this increase in
earnings were higher energy costs from purchasing additional power at higher
prices due to increased nuclear station outages during the year.
Results of Operations by Business Segment
Historically, Duquesne Light was treated as a single integrated business
segment, due to its regulated operating environment. The PUC authorized a
combined rate for supplying and delivering electricity to customers, that was
(1) cost-based,(2) designed to recover operating expenses and investment in
electric utility assets, and (3) designed to provide a return on the investment.
As a result of the Customer Choice Act, supply of electricity is deregulated and
charged at a separate rate from the delivery of electricity. For the purposes of
complying with SFAS No. 131, Disclosures about Segments of an Enterprise and
Related Information, we are required to disclose information about our business
segments separately. Accordingly, we have used the PUC-approved separate rates
for 1999 to develop the financial information of the business segments for the
periods ended December 31, 1999, 1998 and 1997.
We report our results by the following three principal business segments,
determined by products, services and regulatory environment: (1) the
transmission and distribution of electricity (electricity delivery business
segment),(2) the supply of electricity (electricity supply business segment) and
(3) the collection of transition costs (CTC business segment). Upon the
anticipated completion of the sale of our generation assets, the electricity
supply business segment will be comprised solely of provider of last resort
service. We also report an "all other" category, comprised of our investments in
leasing and gas reserve transactions.
Note N, "Business Segments and Related Information," in the Notes to the
Consolidated Financial Statements on page 31 shows the financial results of each
principal business segment in tabular form. These results are discussed below.
1999 Compared to 1998
Electricity Delivery Business Segment. The electricity delivery business
segment contributed $56.5 million to earnings available for common stock in 1999
compared to $57.2 million in 1998, a decrease of $0.7 million or 1.2 percent.
Operating revenues for this business segment are primarily derived from the
delivery of electricity. Sales to residential and commercial customers are
influenced by weather conditions. Warmer summer and colder winter seasons lead
to increased customer use of electricity for cooling and heating. Commercial
sales also are affected by regional development. Sales to industrial customers
are influenced primarily by national and global economic conditions.
Operating revenues increased by $17.1 million or 5.3 percent compared to 1998
due to an increase in sales to electric utility customers of 2.7 percent in
1999. Residential and commercial sales increased as a result of warmer summer
temperatures during 1999 compared to 1998. Industrial sales increased primarily
due to an increase in electricity consumption by steel manufacturers. The
following table sets forth kilowatt-hours (KWH) delivered to electric utility
customers.
- -----------------------------------------------------------------------
KWH Delivered
-----------------------------------
(In Millions)
-----------------------------------
1999 1998 Change
- -----------------------------------------------------------------------
Residential 3,526 3,382 4.3%
Commercial 6,024 5,896 2.2%
Industrial 3,481 3,412 2.0%
- ---------------------------------------------------------
Sales to Electric
Utility Customers 13,031 12,690 2.7%
======================================================================
Operating expenses for the electricity delivery business segment primarily are
made up of costs to operate and maintain the transmission and distribution
system; meter reading and billing costs; customer service; collection;
administrative expenses; income taxes; and non-income taxes, such as gross
receipts, property and payroll taxes. Operating expenses increased by $8.4
million or 4.6 percent compared to 1998, due to higher meter reading costs,
higher gross receipts taxes, and increased costs related to customer assistance
programs. We have completed installation of our Customer Advanced Reliability
System, which replaced the traditional meter-reading process by providing
information on customer electricity consumption on a real-time basis. This
direct link with customers will serve as a platform for offering additional
services and products, and is expected to reduce future costs.
A decrease in other income of $2.6 million or 81.3 percent was the result of
lower interest income from a smaller amount of cash available for investing.
Interest and other charges include interest on long-term debt, other interest
and our preferred stock dividends. In 1999, there was $6.9 million or 18.3
percent more interest and other charges allocated to the electricity delivery
business segment compared to 1998. The increase was the result of additional
short-term borrowings during the fourth quarter of 1999. Given the pending
generation asset sale to Orion, all remaining financing costs after
recapitalization will be borne by the electricity delivery business segment.
Electricity Supply and CTC Business Segments. In 1999, the electricity supply
and CTC business segments reported earnings available for common stock of $86.6
million compared to $71.9 million in 1998, an increase of $14.7 million or 20.4
percent.
8
For the electricity supply and CTC business segments, operating revenues are
derived primarily from the supply of electricity for delivery to retail
customers, the supply of electricity to wholesale customers and, beginning in
1999, the collection of generation-related transition costs from electricity
delivery customers. Under fuel cost recovery provisions effective through May
29, 1998, fuel revenues generally equaled fuel expense, as costs were
recoverable from customers through the Energy Cost Rate Adjustment Clause (ECR),
including the fuel component of purchased power, and thus did not affect net
income. In 1999, due to the PUC's final restructuring order, fuel costs were
expensed as incurred, which impacted net income by the amount that fuel costs
exceeded amounts included in our authorized supply rates. (See "Rate Matters" on
page 12.)
Energy requirements for our retail electric utility customers are
reduced as more customers participate in customer choice. Energy requirements
for residential and commercial customers are also influenced by weather
conditions. Warmer summer and colder winter seasons lead to increased customer
use of electricity for cooling and heating. Commercial energy requirements are
also affected by regional development. Energy requirements for industrial
customers are primarily influenced by national and global economic conditions.
Short-term sales to other utilities are made at market rates. Fluctuations in
electricity sales to other utilities are related to customer energy
requirements, the energy market and transmission conditions, and the
availability of generating stations. We no longer will make short-term sales to
other utilities after the generation asset sale. (See "Rate Matters" on page
12.)
Operating revenues decreased by $39.7 million or 4.6 percent compared to
1998. The decrease in revenues resulted primarily from two factors: (1) 26.4
percent less energy supplied to electric utility customers due to greater
participation in customer choice, and (2) the 1998 inclusion in revenues of
$23.3 million related to deferred energy costs. Partially offsetting this
decrease was a 75.3 percent increase in energy supplied to other utilities in
1999, due to our decision to make 600 MW available during the first six months
of 1999 to licensed generation suppliers to stimulate competition, and increased
capacity available to sell as a result of participation in customer choice. The
following table sets forth KWH supplied for customers who have not chosen an
alternative generation supplier.
- ------------------------------------------------------------------------
KWH Supplied
-----------------------------------
(In Millions)
-----------------------------------
1999 1998 Change
- ------------------------------------------------------------------------
Residential 2,533 3,190 (20.6)%
Commercial 3,811 5,580 (31.7)%
Industrial 2,581 3,358 (23.1)%
- --------------------------------------------------------
Sales to Electric
Utility Customers 8,925 12,128 (26.4)%
- --------------------------------------------------------
Sales to Other Utilities 3,347 1,909 75.3 %
- --------------------------------------------------------
Total Sales 12,272 14,037 (12.6)%
=======================================================================
Operating expenses for the electricity supply business segment are primarily
made up of energy costs; costs to operate and maintain the power
stations; administrative expenses; income taxes; and non-income taxes, such as
gross receipts, property and payroll taxes.
Fluctuations in energy costs generally result from changes in the cost of
fuel; the mix between coal, nuclear generation and purchased power; total KWH
supplied; and generating station availability.
Operating expenses decreased $55.7 million or 9.6 percent from 1998, as a
result of lower energy costs and the reclassification of Beaver Valley Unit 2
lease costs to financing charges in 1999. (See "Power Station Exchange"
discussion on page 13.)
In 1999,fuel and purchased power expense decreased by $37.4 million or 14.2
percent compared to 1998. This decrease was the result of reduced energy supply
requirements, due to customer choice, and a favorable energy supply mix.
Generating station availability was improved in 1999.
Depreciation and amortization expense includes the depreciation of the power
stations' plant and equipment and accrued nuclear decommissioning costs and
amortization of transition costs. There was a decrease of $36.2 million or
22.9 percent compared to 1998. During 1998, prior to the PUC's May 29 final
restructuring order, we accelerated depreciation of generation assets to
minimize potential transition costs. Depreciation for the remainder of 1998 and
CTC amortization for 1999 were in accordance with PUC-approved rates.
A decrease in other income of $6.8 million or 52.7 percent was due to lower
interest income from a smaller amount of cash available for investing, compared
to the prior year.
9
Interest and other charges include interest on long-term debt, other interest
and preferred stock dividends. In 1999 there was a $30.7 million or 52.4 percent
increase in interest and other charges compared to 1998. The increase reflects
$35.2 million of Beaver Valley Unit 2 lease-related costs reclassified as
financing costs in 1999, partially offset by a reduced allocation of total
financing cost to the electricity supply business segment.
All Other. The all other category contributed $3.9 million to earnings
available for common stock in 1999 compared to $15.4 million in 1998, a decrease
of $11.5 million or 74.7 percent. Operating margin on our gas reserve
investments declined by $0.9 million and related depreciation increased by $4.5
million. Our leasing investments, made in 1995, provided a lower level of income
as the underlying leases have expired at various points during the 60-month
investment term, ending in 2000.
1998 Compared to 1997
Electricity Delivery Business Segment. The electricity delivery business
segment contributed $57.2 million to earnings available for common stock in 1998
compared to $61.9 million in 1997, a decrease of $4.7 million or 7.6 percent.
Operating revenues for this business segment are primarily derived from the
delivery of electricity.
Operating revenues increased by $4.6 million or 1.5 percent compared to 1997,
due to an increase in sales to electric utility customers of 1.0 percent in
1998. Residential and commercial sales increased as a result of warmer summer
temperatures during 1998 compared to 1997. Industrial sales decreased primarily
due to a reduction in electricity consumption by steel manufacturers, which
experienced a decline in demand. The following table sets forth KWH delivered to
electric utility customers.
- -----------------------------------------------------------------------
KWH Delivered
--------------------------------
(In Millions)
--------------------------------
1998 1997 Change
- -----------------------------------------------------------------------
Residential 3,382 3,273 3.3 %
Commercial 5,896 5,786 1.9 %
Industrial 3,412 3,501 (2.5)%
- --------------------------------------------------------
Sales to Electric
Utility Customers 12,690 12,560 1.0 %
=======================================================================
Operating expenses increased $6.3 million or 3.6 percent from 1997,primarily
as a result of higher costs of maintenance of the transmission and distribution
system, and costs related to start-up and installation of the Customer Advanced
Reliability System. The increase in system maintenance was primarily due to the
increase in frequency and severity of storms during 1998.
Depreciation and amortization expense increased $1.9 million or 4.3 percent in
1998, due to additions to the plant and equipment balance throughout the year,
which was partially offset by retirements.
A decrease in other income of $2.0 million or 38.5 percent was the result of
lower interest income from a smaller amount of cash available for investing,
compared to the prior year.
In 1998, there was $0.9 million or 2.3 percent less in interest and other
charges compared to 1997. The decrease was the result of the refinancing of
long-term debt at lower interest rates and the maturity of approximately $75
million of long-term debt during 1998.
Electricity Supply Business Segment. In 1998, the electricity supply business
segment reported earnings available for common stock of $71.9 million compared
to $60.5 million in 1997, an increase of $11.4 million or 18.8 percent.
Operating revenues decreased by $3.7 million or 0.4 percent compared to 1997.
The decrease in revenues can be attributed to a decrease in energy supplied to
electric utility customers due to initial participation in customer choice, and
a decrease in energy costs that were recovered through the ECR. Partially
offsetting these decreases were increased energy supplied to other utilities of
32.2 percent in 1998, due to higher demand from other utilities and increased
capacity available to sell as a result of participation in customer choice. The
following table sets forth KWH supplied for customers who had not chosen an
alternative generation supplier.
- -----------------------------------------------------------------------
KWH Supplied
--------------------------------
(In Millions)
--------------------------------
1998 1997 Change
- -----------------------------------------------------------------------
Residential 3,190 3,268 (2.4)%
Commercial 5,580 5,778 (3.4)%
Industrial 3,358 3,500 (4.1)%
- -------------------------------------------------------
Sales to Electric
Utility Customers 12,128 12,546 (3.3)%
- -------------------------------------------------------
Sales to Other
Utilities 1,909 1,444 32.2 %
- -------------------------------------------------------
Total Sales 14,037 13,990 0.3 %
=======================================================================
Operating expenses increased $24.4 million or 4.4 percent from 1997 as a
result of increased energy costs, partially offset by decreased maintenance
costs and reduced Beaver Valley Unit 2 lease costs.
10
In 1998,fuel and purchased power expense increased by $39.1 million or 17.5
percent compared to 1997. This increase was the result of increased energy costs
due to an unfavorable power supply mix and higher purchased power prices.
Reduced availability of nuclear generating stations due to an increase in outage
hours required us to purchase power and generate power from higher fuel cost
fossil stations.
Maintenance expense decreased in 1998, primarily related to the reversal of
fossil station maintenance outage accruals for outages scheduled after the
planned divestiture of generation. (See "Rate Matters" on page 12.) A reduction
in nuclear station outage cost amortization in 1998 also contributed to the
decrease in maintenance expense.
A decrease in depreciation and amortization expense of $32.4 million, or 17.0
percent compared to 1997, was the result of reduced depreciation of generation
assets in accordance with the PUC's final restructuring order.
Interest and other charges decreased $5.2 million or 8.2 percent compared to
1997. The decrease reflected the refinancing of long-term debt at lower interest
rates and the maturity of approximately $75 million of long-term debt during
1998.
All Other. The all other category contributed $15.4 million to earnings
available for common stock in each of 1998 and 1997.
LIQUIDITY AND CAPITAL RESOURCES
Capital Expenditures
We spent approximately $100.3 million in 1999, $118.4 million in 1998 and
$93.7 million in 1997 for capital expenditures. We estimate that we will spend,
excluding allowance for funds used during construction (AFC), approximately $85
million (including $5 million relating to generation), $75 million and
$75 million for electric utility construction in 2000, 2001 and 2002.
Acquisitions and Dispositions
In the power station exchange with FirstEnergy, we acquired three power plants
and disposed of our partial interests in five power plants. (See "Power Station
Exchange" discussion on page 13.) During 1999, we also disposed of non-strategic
investments. Proceeds from these dispositions totaled $7.6 million. In early
2000 we signed a non-binding memorandum of understanding with Itron, Inc., for
the potential purchase of the Itron-designed Customer Advanced Reliability
System, which we currently lease.
Long-Term Investments
Our investing activities during 1999, 1998 and 1997 included approximately $62
million, $35 million and $24 million in affordable housing, landfill and coal-
bed methane gas reserves, and deposits in nuclear decommissioning funds. The
decommissioning trust held funding for nuclear decommissioning costs related to
our nuclear-powered plants. During 1999, we invested approximately $60 million
in the decommissioning trust funds, in order to fully fund the decommissioning
liability, prior to transferring both the trust funds and the liability to
FirstEnergy in the power station exchange. (See "Power Station Exchange"
discussion on page 13.) Cash related to this funding was collected during the
year through the CTC component of customer bills.
Financing
During 1999, in addition to capital provided from operations, we raised
capital to effect the termination of the Beaver Valley Unit 2 lease and to begin
our recapitalization program in anticipation of the generation divestiture. As
previously discussed, we invested $100 million in capital expenditures, and $62
million in nuclear decommissioning and other long-term investments during 1999.
Additionally, in connection with the power station exchange, we paid
approximately $234 million in termination costs and $43 million in related taxes
to cancel the Beaver Valley Unit 2 lease. Of this total amount, $107 million
represents costs previously approved for recovery through the CTC. The remaining
$170 million is included on the consolidated balance sheet as divestiture costs.
As part of this transaction, the lease liability recorded on the consolidated
balance sheet was eliminated; however the underlying collateralized lease bonds
($359 million upon lease termination) became our obligations and are now
recorded on the consolidated balance sheet as debt, $9 million of which will
mature in 2000. (See "Power Station Exchange" discussion on page 13.) Prior to
cancelling the Beaver Valley Unit 2 lease, we paid approximately $42 million to
terminate our nuclear fuel lease (the nuclear fuel was transferred to
FirstEnergy in the power station exchange). Additional capital was required for
the maturity of $75 million of mortgage bonds and the payment of $207 million of
dividends.
To meet these capital requirements, and to serve as a bridge until the
anticipated receipt of our generation divestiture proceeds, we undertook several
financing initiatives during 1999. At year-end, we had $137 million of
commercial paper borrowings outstanding, and $400 million
11
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. In the fourth quarter of 1999, we issued $290
million of first mortgage bonds with a one-year term, callable in May 2000.
The interest rate on the bonds is 6.53 percent. This debt was used to fund the
Beaver Valley Unit 2 lease termination costs.
Future Capital Requirements and Availability
We have entered into an agreement to sell our generation assets to Orion for
$1.71 billion. (See "Auction Plan" discussion on page 13.) We anticipate using
the proceeds from this sale (currently estimated to be $1.1 billion, net of tax
and transaction costs) to recapitalize. This process will include the retirement
of short-term debt and the redemption of long-term debt. In conjunction with the
generation asset sale to Orion, we expect to acquire the $359 million of 8.7
percent collateralized lease bonds, previously assumed as part of the Beaver
Valley Unit 2 lease termination. Additionally, maturing during 2000 will be $390
million of first mortgage bonds ($290 million of which were issued in November
1999) and $9 million of collateralized lease bonds.
We expect to meet our current obligations and debt maturities through 2004
with funds generated from operations, through new financings and short-term
borrowings, and through the proceeds from the sale of generation assets to
Orion.
We maintain a $225 million revolving credit agreement expiring in September
2000. We have the option to convert the revolver into a term loan facility for a
period of two years for any amounts then outstanding upon expiration of the
revolving credit period. Interest rates can, in accordance with the option
selected at the time of the borrowing, be based on one of several indicators,
including prime, Eurodollar, or certificate of deposit rates. Facility fees are
based on the unborrowed amount of the commitment. At December 31, 1999 and
1998, no borrowings were outstanding.
We have an agreement with an unaffiliated corporation that entitles us to
sell, and the corporation to purchase, on an ongoing basis, up to $50 million of
accounts receivable. At various times during 1999 and in the first quarter of
2000, we had sold receivables under the facility. No amounts were outstanding at
December 31, 1999 and 1998. The accounts receivable sales agreement, which
expires in February 2001, is one of many sources of funds available to us. We
may elect to extend the agreement upon expiration, replace it with a similar
facility, or terminate it.
In connection with customer choice, customer revenues from our operations are
reduced by an amount equal to the generation rate applicable to those customers
choosing alternative generation suppliers. This reduction is expected to be
offset by lower generation and purchased power costs. An additional impact is
anticipated when the provider of last resort service agreement with Orion takes
effect, and all customers will be buying generation either directly from
alternative suppliers or indirectly from Orion. A further impact on customer
revenues is expected to occur when the CTC has been fully collected, which is
currently expected to occur in 2001 for most major rate classes; elimination of
the CTC will reduce customer rates, on average, by 25 percent for those rate
classes. The foregoing statements are forward-looking regarding the impact on
cash flows of customer choice and our divestiture. Actual results could
materially differ from those implied by such statements due to known and unknown
risks and uncertainties, including, but not limited to, the timing of the
generation asset sale closing and the receipt of sale proceeds. (See
"Restructuring Plan" on page 13.)
RATE MATTERS
Competition and the Customer Choice Act
Under Pennsylvania ratemaking practice, regulated electric utilities were
granted exclusive geographic franchises to sell electricity, in exchange for
making investments and incurring obligations to serve customers under the then-
existing regulatory framework. Through the ratemaking process, those prudently
incurred costs were recovered from customers, along with a return on the
investment. Additionally, certain operating costs were approved for deferral for
future recovery from customers (regulatory assets). As a result of this
process, utilities had assets recorded on their balance sheets at above-market
costs, thus creating transition costs.
The Customer Choice Act (effective January 1, 1997) enables Pennsylvania's
electric utility customers to purchase electricity at market prices from a
variety of electric generation suppliers (customer choice). As of January 2000,
all customers have customer choice. As of February 29, 2000, approximately 23
percent of our customers had chosen alternative generation suppliers,
representing approximately 30 percent of our non-coincident peak load. Customers
who have chosen an electricity generation supplier other than us pay that
supplier for generation charges, and pay us the CTC (discussed below) and
charges for transmission and distribution. Customers who continue to buy their
generation from us pay for their service at current regulated tariff rates
divided into generation, transmission and distribution charges, and the
CTC. Electricity delivery (including transmission, distribution and customer
service) remains regulated in substantially the same manner as under historical
regulation.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, was
originally imposed on the transmission and distribution charges of Pennsylvania
electric utility companies under the Customer Choice Act. As part of a
settlement regarding recovery of deferred fuel costs (discussed below), we have
agreed to extend this rate cap for an additional six months through the end of
2001.
12
Provider of Last Resort
We are required not only to deliver electricity, but also to serve as the
provider of last resort for all customers in our service territory. As the
provider of last resort, we must provide electricity for any customer who cannot
or does not choose an alternative electric generation supplier, or whose
supplier fails to deliver. While collecting the CTC, we may charge only
PUC-approved rates for the supply of electricity as the provider of last resort.
As part of the pending generation asset sale, Orion has agreed to supply
us, under a provider of last resort service agreement, with all of the electric
energy necessary to satisfy our provider of last resort obligations during the
CTC collection period. Under the Customer Choice Act, after the CTC collection
period we anticipate that we will supply electricity at market prices to fulfill
our provider of last resort obligations.
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that we
should recover most of the above-market costs of our generation assets,
including plant and regulatory assets, through the collection of the CTC from
electric utility customers. The $1.49 billion of transition costs, net of tax,
was originally to be recovered over a seven-year period ending in
2005. However,by applying expected net proceeds of the pending generation asset
sale to Orion to reduce transition costs, we currently anticipate early
termination of the CTC collection period in 2001 for most major rate classes. In
addition, the transition costs as reflected on the consolidated balance sheet
are being amortized over the same period that the CTC revenues are being
recognized. We are allowed to earn an 11 percent pre-tax return on the
unrecovered, net of tax balance of transition costs, as adjusted following the
generation asset sale.
As part of our restructuring plan filing, we requested recovery of $11.5
million ($6.7 million, net of tax) through the CTC for energy costs previously
deferred under the ECR. Recovery of this amount was approved in the PUC's final
restructuring order. We also requested recovery of an additional $31.2 million
($18.2 million, net of tax) in deferred fuel costs. Although the PUC initially
denied recovery of this additional amount, on October 26, 1999, we reached a
settlement on this issue with the Pennsylvania Office of the Consumer Advocate
which would permit recovery of the entire $42.7 million ($24.9 million, net of
tax) in deferred fuel costs. The PUC approved this settlement on February
11, 2000.
On December 18, 1998, the PUC approved our auction plan, which included an
auction of our provider of last resort service obligations, as well as an
agreement to carry out the power station exchange with FirstEnergy.
Power Station Exchange. On December 3, 1999, we completed the exchange of our
partial interests in five power plants for three wholly owned power plants of
subsidiaries of FirstEnergy. We received three fossil-powered plants (located in
Avon Lake and Niles, Ohio, and in New Castle, Pennsylvania) having an aggregate
net demonstrated capacity of 1,323 MW. The ownership interests we transferred
included our interests in the nuclear-powered Beaver Valley, Pennsylvania and
Perry, Ohio plants, and the fossil-powered Bruce Mansfield, Pennsylvania and
Sammis and Eastlake, Ohio plants having an aggregate net demonstrated capacity
of 1,435 MW. Along with ownership of the nuclear-powered plants, FirstEnergy
assumed the decommissioning liability for Beaver Valley and Perry, in exchange
for the fully funded balance in decommissioning trust funds we previously
maintained. During 1999, we funded approximately $60 million into the
decommissioning trusts. These amounts, which were collected through the CTC
during the year, brought the fund balances to approximately $122 million. In
connection with the power station exchange, we terminated the Beaver Valley Unit
2 lease in the fourth quarter of 1999. (See "Financing" discussion on page 11.)
Auction Plan. On September 24, 1999, we entered into definitive agreements
with the winning auction bidder, Orion, pursuant to which Orion will purchase
our wholly owned Cheswick, Elrama, Phillips and Brunot Island power stations,
and the stations received from FirstEnergy in the power station exchange, for
approximately $1.71 billion (estimated to be $1.1 billion, net of tax and
transaction expenses). Under a provider of last resort service agreement, Orion
will supply us with all of the electric energy necessary to satisfy our
obligations to our customers who have not chosen an alternative electric
generation supplier. This agreement, which expires upon our final collection of
the CTC, in general effectively transfers to Orion the financial risks and
rewards associated with our provider of last resort obligations. While we retain
the collection risk for the electricity sales, a component of our regulated
delivery rates is designed to cover the cost of a normal level of uncollectible
accounts. We and Orion are currently discussing an extension of this provider of
last resort arrangement beyond the final CTC collection.
The Orion transactions must be approved by various regulatory agencies,
including the PUC, the FERC, and the Federal Trade Commission. We currently
expect the sale to close in the second quarter of 2000. The final accounting for
the sale proceeds remains subject to PUC approval. Through December 31, 1999, we
have deferred approximately $219 million of costs related to the power station
exchange and the asset sale. Additional divestiture-related costs will be
deferred as incurred. We expect to fully recover these costs
13
through the divestiture process; however, any disallowed costs will be written
off.
Until the divestiture is complete, we are required to use an interim CTC and
price to compare for each rate class (approximately 2.9 cents per KWH on average
for the CTC, and approximately 3.8 cents per KWH on average for the price to
compare).
Termination of the AYE Merger
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement with Allegheny Energy, Inc. (AYE). AYE filed suit in the United States
District Court for the Western District of Pennsylvania, seeking to compel DQE
to proceed with the merger, or in the alternative seeking an unspecified amount
of money damages. After holding a trial from October 20 through 28, 1999, the
District Court ruled on December 3, 1999, that DQE had properly terminated the
merger agreement without breach, and granted judgment in DQE's favor on all
claims and all requests for injunctive relief. On December 14, 1999, AYE
appealed this ruling to the Third Circuit. Argument was heard on March 9, 2000,
and a decision is pending. We cannot determine the ultimate outcome of AYE's
appeal at this time.
YEAR 2000
We took comprehensive steps to ensure a smooth transition into the Year
2000. Since 1994, we planned for the Year 2000 with an aggressive strategy to
identify information needs, replace or upgrade equipment and coordinate
resources to anticipate the new millennium. We experienced normal operations
during the transition, and continue to do so.
The total cost of implementing our Year 2000 plan was approximately $48
million, which includes costs related to total system replacements (i.e., the
Year 2000 solution comprised only a portion of the benefit resulting from such
replacements). These costs were primarily incurred as a result of software and
system changes and upgrades. Approximately $35 million was capital costs
attributable to the licensing and installation of new software for total
system replacements. The remaining $13 million was expensed as it was incurred.
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.
REPORT OF INDEPENDENT AUDITORS
To the Directors and Shareholder of
Duquesne Light Company:
We have audited the accompanying consolidated balance sheets of Duquesne Light
Company (a wholly owned subsidiary of DQE, Inc.) and its subsidiaries as of
December 31, 1999 and 1998, 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, 1999. 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 generally accepted auditing
standards. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999 in conformity with generally accepted accounting
principles. 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.
/s/ Deloitte & Touche LLP
Pittsburgh, Pennsylvania
January 28, 2000
14
Statement of Consolidated Income
- --------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------------------
Year Ended December 31,
-----------------------------------------
1999 1998 1997
- --------------------------------------------------------------------------------------------------------
Operating Revenues:
Sales of Electricity:
Residential $ 401,409 $ 410,960 $ 405,915
Commercial 437,904 495,194 500,070
Industrial 183,112 189,617 198,708
- --------------------------------------------------------------------------------------------------------
Customer revenues 1,022,425 1,095,771 1,104,693
Utilities 76,303 36,203 24,861
- --------------------------------------------------------------------------------------------------------
Total Sales of Electricity 1,098,728 1,131,974 1,129,554
Other 60,072 46,772 46,387
- --------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,158,800 1,178,746 1,175,941
- --------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 167,080 176,913 184,676
Purchased power 58,102 85,647 38,735
Other operating 253,252 270,458 269,725
Maintenance 75,400 74,908 82,869
Depreciation and amortization 172,424 204,204 234,719
Taxes other than income taxes 84,532 80,035 81,049
Income taxes 88,246 82,495 76,783
- --------------------------------------------------------------------------------------------------------
Total Operating Expenses 899,036 974,660 968,556
- --------------------------------------------------------------------------------------------------------
Operating Income 259,764 204,086 207,385
- --------------------------------------------------------------------------------------------------------
Other Income and (Deductions):
Interest and dividend income 5,923 13,242 16,014
Income taxes (12,119) (7,582) (2,945)
Other 28,686 31,551 19,761
- --------------------------------------------------------------------------------------------------------
Total Other Income 22,490 37,211 32,830
- --------------------------------------------------------------------------------------------------------
Income Before Interest and Other Charges 282,254 241,297 240,215
- --------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 79,454 81,076 87,420
Other interest 40,054 1,290 752
Allowance for borrowed funds used during construction (836) (2,179) (2,339)
- --------------------------------------------------------------------------------------------------------
Total Interest Charges 118,672 80,187 85,833
- --------------------------------------------------------------------------------------------------------
Monthly Income Preferred Securities Dividend Requirements 12,562 12,562 12,562
- --------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 151,020 148,548 141,820
Extraordinary Item, Net of Tax -- (82,548) --
- --------------------------------------------------------------------------------------------------------
Net Income, After Extraordinary Item 151,020 66,000 141,820
========================================================================================================
Dividends on Preferred and Preference Stock 3,998 4,036 4,022
Earnings for Common Stock, Before Extraordinary Item $ 147,022 $ 144,512 $ 137,798
========================================================================================================
Earnings for Common Stock, After Extraordinary Item $ 147,022 $ 61,964 $ 137,798
========================================================================================================
See notes to consolidated financial statements.
15
Consolidated Balance Sheet
- -------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------
As of December 31,
--------------------------
ASSETS 1999 1998
- -------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment:
Electric plant in service $ 3,855,390 $ 4,379,703
Construction work in progress 69,343 79,644
Property held under capital leases 25,998 123,374
Other 8,505 6,419
- -------------------------------------------------------------------------------------------------------------
Gross property, plant and equipment 3,959,236 4,589,140
Less: Accumulated depreciation and amortization (2,500,719) (3,141,841)
- -------------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment - Net 1,458,517 1,447,299
- -------------------------------------------------------------------------------------------------------------
Long-Term Investments:
Investment in DQE common stock 52,536 69,067
Nuclear decommissioning trust fund -- 62,697
Other investments 28,355 70,492
- -------------------------------------------------------------------------------------------------------------
Total Long-Term Investments 80,891 202,256
- -------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments 16,068 53,151
- -------------------------------------------------------------------------------------------------------------
Receivables:
Electric customer accounts receivable 82,314 87,262
Other utility receivables 32,582 25,412
Other receivables 25,481 22,419
Less: Allowance for uncollectible accounts (8,730) (9,137)
- -------------------------------------------------------------------------------------------------------------
Total Receivables - Net 131,647 125,956
- -------------------------------------------------------------------------------------------------------------
Materials and supplies (at average cost):
Operating and construction 37,536 58,747
Coal 17,705 25,702
- -------------------------------------------------------------------------------------------------------------
Total Materials and Supplies 55,241 84,449
- -------------------------------------------------------------------------------------------------------------
Other current assets 55,893 7,670
- -------------------------------------------------------------------------------------------------------------
Total Current Assets 258,849 271,226
- -------------------------------------------------------------------------------------------------------------
Other Non-Current Assets:
Transition costs 2,008,171 2,132,980
Regulatory assets 224,002 199,066
Divestiture costs 218,653 1,338
Other 32,329 55,461
- -------------------------------------------------------------------------------------------------------------
Total Other Non-Current Assets 2,483,155 2,388,845
- -------------------------------------------------------------------------------------------------------------
Total Assets $ 4,281,412 $ 4,309,626
=============================================================================================================
See notes to consolidated financial statements.
16
Consolidated Balance Sheet
- -------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------
As of December 31,
--------------------------
CAPITALIZATION AND LIABILITIES 1999 1998
- -------------------------------------------------------------------------------------------------------------
Capitalization:
Common stock (authorized - 90,000,000 shares, issued
and outstanding - 10 shares) $ -- $ --
Capital surplus 746,051 819,157
Retained earnings 39,931 27,646
Accumulated other comprehensive income 12,692 21,697
- -------------------------------------------------------------------------------------------------------------
Total Common Stockholder's Equity 798,674 868,500
- -------------------------------------------------------------------------------------------------------------
Non-redeemable Monthly Income Preferred Securities 150,000 150,000
Non-redeemable preferred stock 65,108 65,108
Non-redeemable preference stock 25,279 26,914
- -------------------------------------------------------------------------------------------------------------
Total preferred and preference stock before deferred ESOP benefit 240,387 242,022
Deferred employee stock ownership plan (ESOP) benefit (10,875) (14,240)
- -------------------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock 229,512 227,782
- -------------------------------------------------------------------------------------------------------------
Long-term debt 1,410,754 1,160,348
- -------------------------------------------------------------------------------------------------------------
Total Capitalization 2,438,940 2,256,630
- -------------------------------------------------------------------------------------------------------------
Obligations Under Capital Leases 16,534 36,596
- -------------------------------------------------------------------------------------------------------------
Current Liabilities:
Current debt maturities 399,759 96,137
Notes payable 136,594 --
Accrued liabilities 102,694 116,056
Accounts payable 92,266 105,624
Dividends declared 29,343 39,597
Other 1,030 6,864
- -------------------------------------------------------------------------------------------------------------
Total Current Liabilities 761,686 364,278
- -------------------------------------------------------------------------------------------------------------
Non-Current Liabilities:
Deferred income taxes - net 760,677 744,770
Beaver Valley lease liability -- 475,570
Deferred income 93,246 117,508
Nuclear decommissioning liability -- 62,697
Deferred investment tax credits 22,208 24,076
Other 188,121 227,501
- -------------------------------------------------------------------------------------------------------------
Total Non-Current Liabilities 1,064,252 1,652,122
- -------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes B through M)
- -------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 4,281,412 $4,309,626
=============================================================================================================
See notes to consolidated financial statements.
17
Statement of Consolidated Cash Flows
- -------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------
Year Ended December 31,
------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income $ 151,020 $ 66,000 $ 141,820
Principal non-cash charges (credits) to net income:
Depreciation and amortization 172,424 204,204 234,719
Capital lease, nuclear fuel and other amortization 35,216 49,547 39,179
Deferred income taxes and investment tax credits - net 12,578 34,151 (7,612)
Gain on dispositions (7,573) (1,322) (5,856)
Changes in working capital other than cash (27,536) 36,300 (19,432)
Investment income (34,753) (66,552) (19,353)
Extraordinary item, net of tax -- 82,548 --
Increase in ECR -- (19,219) (25,318)
Other 13,816 (62,508) (21,985)
- -------------------------------------------------------------------------------------------------------------
Net Cash Provided By Operating Activities 315,192 323,149 316,162
- -------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Construction expenditures (100,280) (118,447) (93,743)
Funding of nuclear decommissioning trust (59,861) (8,878) (8,762)
Capitalized divestiture costs (47,449) -- --
Long-term investments (2,289) (26,172) (15,422)
Proceeds from disposition of investments 20,149 1,322 5,856
Other 5,168 11,836 (4,930)
- -------------------------------------------------------------------------------------------------------------
Net Cash Used In Investing Activities (184,562) (140,339) (117,001)
- -------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Issuance of debt 290,000 140,000 --
Issuance of notes payable 136,594 -- --
Reductions of long-term obligations:
Capital leases (42,423) (12,897) (13,551)
Long-term debt (75,000) (198,172) (52,100)
Dividends on capital stock (206,997) (211,954) (133,970)
BV Unit 2 lease cancellation (277,226) -- --
Other 7,339 (11,805) 11,215
- -------------------------------------------------------------------------------------------------------------
Net Cash Used In Financing Activities (167,713) (294,828) (188,406)
- -------------------------------------------------------------------------------------------------------------
Net (decrease) increase in cash and temporary cash investments (37,083) (112,018) 10,755
Cash and temporary cash investments at beginning of year 53,151 165,169 154,414
- -------------------------------------------------------------------------------------------------------------
Cash and Temporary Cash Investments at End of Year $ 16,068 $ 53,151 $ 165,169
=============================================================================================================
Supplemental Cash Flow Information
- -------------------------------------------------------------------------------------------------------------
Cash paid during the year for:
Interest (net of amount capitalized) $ 76,950 $ 78,046 $ 82,343
- -------------------------------------------------------------------------------------------------------------
Income taxes $ 83,962 $ 117,094 $ 120,548
- -------------------------------------------------------------------------------------------------------------
Non-cash investing and financing activities:
Assumption of debt in conjunction with
Beaver Valley Unit 2 lease termination $ 359,236 $ -- $ --
Capital lease obligations recorded $ -- $ 7,855 $ 27,514
Preferred stock issued in conjunction with long-term investments $ -- $ -- $ 1,500
- -------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
18
Statement of Consolidated Comprehensive Income
- -------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------
Year Ended December 31,
------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
Net income $ 151,020 $ 66,000 $ 141,820
- -------------------------------------------------------------------------------------------------------------
Other comprehensive income:
Unrealized holding gains (losses) arising during the year,
net of tax of $(6,387),$5,426 and $2,088 (9,005) 7,651 2,944
- -------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 142,015 $ 73,651 $ 144,764
=============================================================================================================
See notes to consolidated financial statements.
Statement of Consolidated Retained Earnings
- -------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------
As of December 31,
------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
Balance at beginning of year $ 27,646 $ 172,682 $ 163,884
Net income 151,020 66,000 141,820
Dividends declared 138,735 211,036 133,022
- -------------------------------------------------------------------------------------------------------------
Balance at End of Year $ 39,931 $ 27,646 $ 172,682
=============================================================================================================
See notes to consolidated financial statements.
Notes to Consolidated Financial Statements
A. SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
Consolidation
Duquesne Light Company is a wholly owned subsidiary of DQE, Inc., a multi-
utility delivery and services company. Our one wholly owned subsidiary is
Monongahela Light and Power Company, which makes long-term investments.
We are engaged in the supply, transmission, distribution and sale of electric
energy. On December 3, 1999, we completed a power station asset exchange with
FirstEnergy Corp. This was the first phase of our Pennsylvania Public Utility
Commission (PUC)-approved plan to divest our generation assets. We expect to
complete this divestiture through the pending sale of our remaining generation
assets to Orion Power Holdings, Inc. Final sale agreements must be approved by
various regulatory agencies, including the PUC. We expect the sale to close in
the second quarter of 2000. After that time, we expect to meet our energy supply
obligations through a provider of last resort service agreement with Orion. (See
"Restructuring Plan" discussion, Note E, on page 22.)
All material intercompany balances and transactions have been eliminated in
the preparation of the consolidated financial statements.
Basis of Accounting
We are subject to the accounting and reporting requirements of the Securities
and Exchange Commission (SEC). In addition, our electric utility operations are
subject to regulation by the PUC, including regulation under the
Pennsylvania Electricity Generation Customer Choice and Competition Act
(Customer Choice Act), and the Federal Energy Regulatory Commission (FERC) under
the Federal Power Act with respect to rates for interstate sales, transmission
of electric power, accounting and other matters.
As a result of the PUC's May 29, 1998, final order regarding our restructuring
plan under the Customer Choice Act (see "Rate Matters," Note E, on page 22),
the electricity supply segment of our business does not meet the criteria of
Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the
Effects of Certain Types of Regulation (SFAS No. 71). Pursuant to the PUC's
final restructuring order, our generation-related regulatory assets are being
recovered through a competitive transition charge (CTC) collected in connection
with providing transmission and distribution services, and these assets have
been reclassified
19
accordingly. The balance of transition costs will be adjusted by receipt of the
proceeds from the pending generation asset sale. The electricity delivery
business segment continues to meet SFAS No. 71 criteria, and accordingly
reflects regulatory assets and liabilities consistent with cost-based ratemaking
regulations. The regulatory assets represent probable future revenue, because
provisions for these costs are currently included, or are expected to be
included, in charges to electric utility customers through the ratemaking
process. (See "Rate Matters," Note E, on page 22.) These regulatory assets
consist of a regulatory tax receivable, unamortized debt costs and deferred
employee costs.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, and disclosure of
contingent assets and liabilities, at the date of the financial statements. The
reported amounts of revenues and expenses during the reporting period also may
be affected by the estimates and assumptions management is required to make.
Actual results could differ from those estimates.
Energy Cost Rate Adjustment Clause
Through the Energy Cost Rate Adjustment Clause (ECR), we previously recovered
(by the amount that such expenses were not included in base rates) nuclear
fuel, fossil fuel and purchased power expenses. Also through the ECR, we passed
to our customers the profits from short-term power sales to other utilities. As
a consequence of the PUC's final order regarding our restructuring plan, such
costs are no longer recoverable through the ECR. Instead, effective May 29, 1998
(the date of the PUC's final restructuring order), such costs are expensed as
incurred and thus impact net income. (See "Restructuring Plan" discussion, Note
E, on page 22.)
Revenues from Utility Sales
We provide service to approximately 580,000 direct customers in southwestern
Pennsylvania (including in the City of Pittsburgh), a territory of approximately
800 square miles. We have also historically sold electricity to other utilities,
and will continue to do so until the generation asset sale is complete. (See
"Restructuring Plan" discussion, Note E, on page 22.) Our meters are read
monthly and electric utility customers are billed on the same basis. Revenues
are recorded in the accounting periods for which they are billed, with the
exception of energy cost recovery revenues. (See "Energy Cost Rate Adjustment
Clause" discussion above.)
Maintenance
Effective January 1, 1999, as a result of the PUC's final restructuring order,
all electric utility maintenance costs are expensed as incurred. Historically,
incremental maintenance costs incurred for refueling outages at our nuclear
units (which all were acquired by FirstEnergy in December 1999) were deferred
for amortization over the period between refueling outages (generally 18
months). We would accrue, over the periods between outages, anticipated costs
for scheduled major fossil generating station outages. Maintenance costs
incurred for non-major scheduled outages and for forced outages were charged to
expense as such costs were incurred.
Depreciation and Amortization
Depreciation of property, plant and equipment is recorded on a straight-line
basis over the estimated remaining useful lives of properties. Amortization of
gas reserve investments and depreciation of related property are calculated on a
units of production method over the total estimated gas reserves. Amortization
of interests in affordable housing partnerships is based upon a method that
approximates the equity method; amortization of certain other leases is on the
basis of benefits recorded over the lives of the investments. Depreciation and
amortization of other properties are calculated on various bases. Amortization
of transition costs represents the difference between CTC revenues billed to
customers and the allowed return on our unrecovered net transition cost balance
(11 percent pre-tax).
In 1998 and 1997, we recorded nuclear decommissioning costs under the category
of depreciation and amortization expense, and accrued a liability, equal to that
amount, for nuclear decommissioning expense. In 1999, these costs are included
in transition cost amortization. On the consolidated balance sheet, in 1998 the
decommissioning trusts have been reflected in other long-term investments, and
the related liability has been recorded as other non-current liabilities.
Historically, trust fund earnings increased the fund balance and the recorded
liability. Fully funded trust funds and decommissioning liability were
transferred to FirstEnergy in the power station exchange. (See "Power Station
Exchange" discussion, Note E, on page 23.)
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
20
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 the deferred tax liabilities that are expected to be recovered from
customers through rates. (See "Rate Matters," Note E, and "Income Taxes," Note
G, on pages 22 and 24.) Reversals of accumulated deferred income taxes are
included in income tax expense.
Investment tax credits (ITC) related to the electricity delivery business
segment generally were deferred. These prior credits are subsequently
reflected, over the lives of the related assets, as reductions to income tax
expense.
Other Operating Revenues and Other Income
Other operating revenues include non-kilowatt-hour (KWH) electric utility
revenues from the joint owners of Beaver Valley Units 1 and 2 for their share of
the administrative and general costs of operating those units (both of which are
now wholly owned by FirstEnergy following the power station exchange). Other
income primarily is made up of income from long-term investments entered into by
our subsidiary, and from short-term investments. The income is separated from
other revenues as the investment income does not result from operating
activities.
Property, Plant and Equipment
The asset values of our utility properties are stated at original construction
cost, which includes related payroll taxes, pensions and other fringe benefits,
as well as administrative costs. Also included in original construction cost is
an allowance for funds used during construction (AFC), which represents the
estimated cost of debt and equity funds used to finance construction.
Additions to, and replacements of, property units are charged to plant
accounts. Maintenance, repairs and replacement of minor items of property are
recorded as expenses when they are incurred. The costs of electricity delivery
business segment properties that are retired (plus removal costs and less any
salvage value) are charged to accumulated depreciation and amortization.
The asset values of the electricity supply business segment properties were
written down to market value in accordance with SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, in
conjunction with the PUC's final restructuring order.
Substantially all of the electric utility properties are subject to a first
mortgage lien.
Temporary Cash Investments
Temporary cash investments are short-term, highly liquid investments with
original maturities of three or fewer months. They are stated at market, which
approximates cost. We consider temporary cash investments to be cash
equivalents.
Stock-Based Compensation
We account for stock-based compensation using the intrinsic value method
prescribed in APB Opinion No. 25, Accounting for Stock Issued to Employees, and
related interpretations. Accordingly, compensation cost for stock options is
measured as the excess, if any, of the quoted market price of DQE common stock
at the date of the grant over the amount any employee must pay to acquire the
stock. Compensation cost for stock appreciation rights is recorded based on the
quoted market price of the stock at the end of the year.
Reclassification
The 1998 and 1997 consolidated financial statements have been reclassified to
conform with 1999 presentation.
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities. This statement
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts,
(collectively referred to as derivatives) and for hedging activities. We are
evaluating the impact on our financial statements and disclosures.
B. CHANGES IN WORKING CAPITAL
OTHER THAN CASH
Changes in Working Capital Other than Cash
(Net of Dispositions and Acquisitions)
for the Year Ended December 31,
- -----------------------------------------------------------------------------------
(Thousands of Dollars)
---------------------------------------
1999 1998 1997
- -----------------------------------------------------------------------------------
Receivables $ (1,695) $ (3,981) $(16,330)
Materials and supplies 37,128 (10,943) (1,740)
Other current assets (26,567) (192) 1,350
Accounts payable (13,132) 29,400 (8,048)
Other current liabilities (23,270) 22,016 5,336
- -----------------------------------------------------------------------------------
Total $(27,536) $ 36,300 $(19,432)
===================================================================================
21
C. PROPERTY, PLANT AND EQUIPMENT
Following the power station exchange with FirstEnergy, we own the operating
generating units listed in the following table. We anticipate selling all of
these units to Orion in the second quarter of 2000. (See "Rate Matters," Note
E, below.)
Generating Units
- -----------------------------------------------------------------------------------
Generating Fuel
Unit Capability Source
(Megawatts)
- -----------------------------------------------------------------------------------
Cheswick 570 Coal
Elrama Units 1,2,3 and 4 487 Coal
Brunot Island Units 1a,1b,1c,2a,2b and 3 234 Fuel Oil
Avon Lake Units 6,7,9 and 10 (a) 739 Coal
New Castle Units 3,4,5, A and B (a) 338 Coal
Niles Units 1,2 and A (a) 246 Coal
- -----------------------------------------------------------------------------------
Total Generating Units 2,614
===================================================================================
(a) Acquired from FirstEnergy in the December 3, 1999 power station exchange.
Orion also will acquire our ownership interest in cold-reserved generating
units at Brunot Island Unit 4 and Phillips Power Station, with a combined
capacity of approximately 450 MW.
D. LONG-TERM INVESTMENTS
At December 31, 1999 and 1998, the fair market value of our investment in DQE
common stock was $52.5 million and $69.1 million, respectively. At December
31, 1999 and 1998, the cost of our investment in DQE common stock was $30.8
million and $32.0 million, respectively.
We make equity investments in affordable housing. At December 31, 1999, we had
investments in three affordable housing developments.
Deferred income primarily relates to our lease investments and certain gas
reserve investments. Deferred amounts will be recognized as income over the
lives of the underlying lease investments over periods generally not exceeding
15 years.
E. RATE MATTERS
Competition and the Customer Choice Act
Under Pennsylvania ratemaking practice, regulated electric utilities were
granted exclusive geographic franchises to sell electricity, in exchange for
making investments and incurring obligations to serve customers under the then-
existing regulatory framework. Through the ratemaking process, those prudently
incurred costs were recovered from customers, along with a return on the
investment. Additionally, certain operating costs were approved for deferral for
future recovery from customers (regulatory assets). As a result of this process,
utilities had assets recorded on their balance sheets at above-market costs,
thus creating transition costs.
The Customer Choice Act (effective January 1, 1997) enables Pennsylvania's
electric utility customers to purchase electricity at market prices from a
variety of electric generation suppliers (customer choice). As of January 2000,
all customers have customer choice. As of February 29, 2000, approximately 23
percent of our customers had chosen alternative generation suppliers,
representing approximately 30 percent of our non-coincident peak load. Customers
who have chosen an electricity generation supplier other than us pay that
supplier for generation charges, and pay us the CTC (discussed below) and
charges for transmission and distribution. Customers who continue to buy their
generation from us pay for their service at current regulated tariff rates
divided into generation, transmission and distribution charges, and the
CTC. Electricity delivery (including transmission, distribution and customer
service) remains regulated in substantially the same manner as under historical
regulation.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, was
originally imposed on the transmission and distribution charges of Pennsylvania
electric utility companies under the Customer Choice Act. As part of a
settlement regarding recovery of deferred fuel costs (discussed below), we have
agreed to extend this rate cap for an additional six months through the end of
2001.
Provider of Last Resort
We are required not only to deliver electricity, but also to serve as the
provider of last resort for all customers in our service territory. As the
provider of last resort, we must provide electricity for any customer who cannot
or does not choose an alternative electric generation supplier, or whose
supplier fails to deliver. While collecting the CTC, we may charge only
PUC-approved rates for the supply of electricity as the provider of last resort.
As part of the pending generation asset sale, Orion has agreed to supply
us, under a provider of last resort service agreement, with all of the electric
energy necessary to satisfy our provider of last resort obligations during the
CTC collection period. Under the Customer Choice Act, after the CTC collection
period we anticipate that we will supply electricity at market prices to fulfill
our provider of last resort obligations.
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that we
should recover most of the above-market costs of our generation assets,
including plant and regulatory assets, through the collection of the CTC from
electric utility customers. The $1.49 billion of transition costs, net of tax,
was originally to be recovered over a
22
seven-year period ending in 2005. However, by applying expected net proceeds of
the pending generation asset sale to Orion to reduce transition costs, we
currently anticipate early termination of the CTC collection period in 2001 for
most major rate classes. In addition, the transition costs as reflected on the
consolidated balance sheet are being amortized over the same period that the CTC
revenues are being recognized. We are allowed to earn an 11 percent pre-tax
return on the unrecovered, net of tax balance of transition costs, as adjusted
following the generation asset sale.
As part of our restructuring plan filing, we requested recovery of $11.5
million ($6.7 million, net of tax) through the CTC for energy costs previously
deferred under the ECR. Recovery of this amount was approved in the PUC's final
restructuring order. We also requested recovery of an additional $31.2 million
($18.2 million, net of tax) in deferred fuel costs. Although the PUC initially
denied recovery of this additional amount, on October 26, 1999, we reached a
settlement on this issue with the Pennsylvania Office of the Consumer Advocate
which would permit recovery of the entire $42.7 million ($24.9 million, net of
tax) in deferred fuel costs. The PUC approved this settlement on February
11, 2000.
On December 18, 1998, the PUC approved our auction plan, which included an
auction of our provider of last resort service obligations, as well as an
agreement to carry out the power station exchange with FirstEnergy.
Power Station Exchange. On December 3, 1999, we completed the exchange of our
partial interests in five power plants for three wholly owned power plants of
subsidiaries of FirstEnergy. We received three fossil-powered plants (located in
Avon Lake and Niles, Ohio, and in New Castle, Pennsylvania) having an aggregate
net demonstrated capacity of 1,323 MW. The ownership interests transferred by us
included our interests in the nuclear-powered Beaver Valley, Pennsylvania and
Perry, Ohio plants, and the fossil-powered Bruce Mansfield, Pennsylvania and
Sammis and Eastlake, Ohio plants, having an aggregate net demonstrated capacity
of 1,435 MW. Along with ownership of the nuclear-powered plants, FirstEnergy
assumed the decommissioning liability for Beaver Valley and Perry, in exchange
for the fully funded balance in decommissioning trust funds we previously
maintained. During 1999, we funded approximately $60 million into the
decommissioning trusts. These amounts, which were collected through the CTC
during the year, brought the fund balances to approximately $122 million. In
connection with the power station exchange, we terminated the Beaver Valley Unit
2 lease in the fourth quarter of 1999. (See "Leases," Note H, on page 24.)
Auction Plan. On September 24, 1999, we entered into definitive agreements
with the winning auction bidder, Orion, pursuant to which Orion will purchase
our wholly owned Cheswick, Elrama, Phillips and Brunot Island power stations,
and the stations received from FirstEnergy in the power station exchange, for
approximately $1.71 billion (estimated to be $1.1 billion, net of tax and
transaction expenses). Under a provider of last resort service agreement, Orion
will supply us with all of the electric energy necessary to satisfy our
obligations to our customers who have not chosen an alternative electric
generation supplier. This agreement, which expires upon our final collection of
the CTC, in general effectively transfers to Orion the financial risks and
rewards associated with our provider of last resort obligations. While we retain
the collection risk for the electricity sales, a component of our regulated
delivery rates is designed to cover the cost of a normal level of uncollectible
accounts. We and Orion are currently discussing an extension of this provider of
last resort arrangement beyond the final CTC collection.
The Orion transactions must be approved by various regulatory agencies,
including the PUC, the FERC, and the Federal Trade Commission. We currently
expect the sale to close in the second quarter of 2000. The final accounting for
the sale proceeds remains subject to PUC approval. Through December 31, 1999, we
have deferred approximately $219 million of costs related to the power station
exchange and the asset sale. Additional divestiture-related costs will be
deferred as incurred. We expect to fully recover these costs through the
divestiture process; however, any disallowed costs will be written off.
Until the divestiture is complete, we are required to use an interim CTC and
price to compare for each rate class (approximately 2.9 cents per KWH on average
for the CTC, and approximately 3.8 cents per KWH on average for the price to
compare).
Termination of the AYE Merger
On October 5, 1998, DQE announced its unilateral termination of the merger
agreement with Allegheny Energy, Inc. (AYE). AYE filed suit in the United States
District Court for the Western District of Pennsylvania, seeking to compel DQE
to proceed with the merger, or in the alternative seeking an unspecified amount
of money damages. After holding a trial from October 20 through 28, 1999, the
District Court ruled on December 3, 1999, that DQE had properly terminated the
merger agreement without breach, and granted judgment in DQE's favor on all
claims and all requests for injunctive relief. On December 14, 1999, AYE
appealed this ruling to the Third Circuit. Argument was heard on March 9, 2000,
and a decision is pending. We cannot determine the ultimate outcome of AYE's
appeal at this time.
23
F. SHORT-TERM BORROWING AND
REVOLVING CREDIT ARRANGEMENTS
We maintain a $225 million revolving credit agreement expiring in September
2000. We have the option to convert the revolver into a term loan facility for a
period of two years for any amounts then outstanding upon expiration of the
revolving credit period. Interest rates can, in accordance with the option
selected at the time of the borrowing, be based on one of several indicators,
including prime, Eurodollar, or certificate of deposit rates. Facility fees are
based on the unborrowed amount of the commitment. At December 31, 1999 and
1998, no borrowings were outstanding. At year-end, we had $136.6 million of
commercial paper borrowings outstanding. 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. In the fourth quarter of 1999, we issued $290
million of first mortgage bonds with a one-year term, callable in May 2000. The
interest rate on the bonds is 6.53 percent.
G. INCOME TAXES
We file consolidated tax returns with DQE and other companies in the
affiliated group. The annual federal corporate income tax returns have been
audited by the Internal Revenue Service (IRS) and are closed for the tax years
through 1992. The IRS is auditing our 1993 through 1997 returns, and the tax
years 1998 and 1999 remain subject to IRS review. We do not believe that final
settlement of the federal income tax returns for the years 1993 through 1999
will have a materially adverse effect on our financial position, results of
operations or cash flows.
Deferred Tax Assets (Liabilities) at December 31,
- -----------------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------------
1999 1998
- -----------------------------------------------------------------------------------
Long-term investments $ 75,275 $ 196,184
Mine closing costs 20,460 16,546
Unbilled revenue 12,475 16,589
Unamortized ITC 9,215 9,990
Beaver Valley lease liability -- 167,440
Other 74,237 67,611
- -----------------------------------------------------------------------------------
Deferred tax assets 191,662 474,360
- -----------------------------------------------------------------------------------
Transition costs (600,997) (837,567)
Depreciation (244,628) (285,783)
Regulatory assets (76,091) (65,425)
Deferred energy costs (17,379) (17,379)
Reacquired debt costs (13,244) (12,976)
- -----------------------------------------------------------------------------------
Deferred tax liabilities (952,339) (1,219,130)
- -----------------------------------------------------------------------------------
Net $ (760,677) $ (744,770)
===================================================================================
Income Taxes
- -----------------------------------------------------------------------------------
(Thousands of Dollars)
----------------------------------------
Year Ended December 31,
----------------------------------------
1999 1998 1997
- -----------------------------------------------------------------------------------
Currently payable:
Federal $ 95,815 $ 93,493 $ 98,843
State 28,453 25,599 28,608
Deferred - net:
Federal (25,130) (31,642) (42,712)
State (8,048) 2,211 (152)
ITC deferred - net (2,844) (7,166) (7,804)
- -----------------------------------------------------------------------------------
Total Included in
Operating Expenses $ 88,246 $ 82,495 $ 76,783
- -----------------------------------------------------------------------------------
Included in other
income and deductions:
Federal $(35,991) $(62,409) $(39,536)
State (490) (757) (575)
Deferred - net:
Federal 48,623 73,968 43,672
State -- -- --
ITC (23) (3,220) (616)
- -----------------------------------------------------------------------------------
Total Included in
Other Income and
Deductions 12,119 7,582 2,945
- -----------------------------------------------------------------------------------
Total Income Tax Expense $100,365 $ 90,077 $ 79,728
===================================================================================
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,
----------------------------------------
1999 1998 1997
- -----------------------------------------------------------------------------------
Federal taxes at
statutory rate (35%) $ 87,985 $ 83,519 $ 77,542
Increase (decrease) in
taxes resulting from:
State income taxes 12,945 16,639 18,595
Investment tax benefits (270) (641) (7,734)
Amortization of
deferred ITC (2,867) (10,385) (8,420)
Other 2,572 945 (255)
- -----------------------------------------------------------------------------------
Total Income
Tax Expense $ 100,365 $ 90,077 $ 79,728
===================================================================================
H. LEASES
We lease office buildings, computer equipment, and other property and
equipment. For most of 1999, we also leased nuclear fuel and a portion of Beaver
Valley Unit 2.
24
Capital Leases at December 31,
- -----------------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------
1999 1998
- -----------------------------------------------------------------------------------
Nuclear fuel $ -- $100,756
Electric plant 19,632 19,923
Other 6,366 2,695
- -----------------------------------------------------------------------------------
Total 25,998 123,374
Less: Accumulated amortization (7,649) (63,604)
- -----------------------------------------------------------------------------------
Capital Leases - Net (a) $18,349 $ 59,770
===================================================================================
(a) Includes $1,746 in 1999 and $2,037 in 1998 of capital leases with associated
obligations retired.
In 1987, we sold and leased back our 13.74 percent interest in Beaver Valley
Unit 2; the sale was exclusive of transmission and common facilities. In
conjunction with the PUC restructuring order, it was determined that costs
related to the lease were transition costs to be recovered through the CTC. We
terminated the lease in connection with the power station exchange with
FirstEnergy. The lease liability recorded on the consolidated balance sheet was
eliminated; however, the underlying collateralized lease bonds ($359.2 million
upon lease termination) became our obligation, and are now recorded as debt on
the consolidated balance sheet. (See "Power Station Exchange" discussion, Note
E, on page 23.)
Summary of Rental Expense
- -----------------------------------------------------------------------------------
(Thousands of Dollars)
----------------------------------------
Year Ended December 31,
----------------------------------------
1999 1998 1997
- -----------------------------------------------------------------------------------
Operating leases $51,723 $57,324 $ 60,684
Amortization of capital leases 18,889 12,943 16,847
Interest on capital leases 2,942 4,386 3,435
- -----------------------------------------------------------------------------------
Total Rental Payments $73,554 $74,653 $ 80,966
===================================================================================
Future Minimum Lease Payments
- -----------------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------
Operating Capital
Year Ended December 31, Leases Leases
- -----------------------------------------------------------------------------------
2000 $11,160 $ 4,535
2001 11,102 4,036
2002 10,991 4,014
2003 2,551 3,446
2004 1,916 2,914
2005 and thereafter -- 14,168
- -----------------------------------------------------------------------------------
Total $37,720 $ 33,113
- -----------------------------------------------------------------------------------
Less: Amount representing interest (16,510)
- -----------------------------------------------------------------------------------
Present value (a) $ 16,603
===================================================================================
(a) Includes current obligations of $.07 million at December 31, 1999.
Future minimum lease payments for operating leases are related principally to
certain corporate offices. Future minimum lease payments for capital leases are
related principally to building leases.
Future payments due to us as of December 31, 1999, under subleases of certain
corporate office space, are approximately $6.1 million in 2000, $6.1 million in
2001 and $6.6 million thereafter.
I. COMMITMENTS AND CONTINGENCIES
We anticipate completing the divestiture of our generation assets through the
pending generation asset sale to Orion in the second quarter of 2000. Certain
obligations related to the divested assets will be transferred to Orion upon
completion of that sale. (See "Restructuring Plan" discussion, Note E, on
page 22.)
Construction
We estimate that we will spend, excluding AFC, approximately $85 million
(including $5 million relating to generation), $75 million and $75 million in
2000, 2001 and 2002 for electric utility construction.
Employees
We are a party to a labor contract expiring in September 2001 with the
International Brotherhood of Electrical Workers (IBEW), which represents the
majority of our employees. The contract provides, among other things, employment
security, income protection and, in September 2000, a 3 percent wage increase.
We have agreed with the IBEW on a package of additional benefits and protections
for union employees affected by the divestiture of generation assets.
In connection with the power station exchange with FirstEnergy and the pending
generation asset sale to Orion, we developed early retirement programs and
enhanced available separation packages for eligible IBEW and management
employees. We expect to recover related costs through the sale proceeds.
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. We have assessed our residual
waste management sites, and the DEP has approved our compliance strategies. We
incurred capital costs of $0.5 million in 1999 to comply with these DEP
regulations. We expect the capital cost of compliance to be approximately
$5.0 million over the next two years with respect to sites we will continue to
own after the generation
25
asset sale. We are seeking to recover these costs through the generation asset
sale proceeds.
Our current estimated liability for closing Warwick Mine, including final site
reclamation, mine water treatment and certain labor liabilities, is $49.3
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.
J. LONG-TERM DEBT
Long-Term Debt at December 31,
- --------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------------
Interest Principal Outstanding
Rate Maturity 1999 1998
- --------------------------------------------------------------------------------------------------------------
First mortgage bonds (a) 6.450%-8.375% 2003-2038 $ 643,000 (b) $ 743,000 (c)
Pollution control notes Adjustable (d) 2009-2030 417,985 417,985
Collateralized lease bonds 8.70% 2001-2016 350,162 (e) --
Sinking fund debentures 5.00% 2010 2,791 2,791
Less: Unamortized debt discount and
premium - net (3,184) (3,428)
- --------------------------------------------------------------------------------------------------------------
Total Long-Term Debt $1,410,754 $1,160,348
==============================================================================================================
(a) Includes $100 million of first mortgage bonds not callable until 2003.
Redemption prices for 2000 range from par to a premium of 4.92%.
(b) Excludes $390 million related to current maturities during 2000, of
which $290 million were first mortgage bonds issued in November 1999.
(c) Excludes $75.0 million related to current maturities during 1999.
(d) The pollution control notes have adjustable interest rates. The
interest rates at year-end averaged 3.8 percent in 1999 and 3.9
percent in 1998.
(e) Excludes $9.1 million related to current maturities during 2000.
At December 31, 1999, sinking fund requirements and maturities of long-term
debt outstanding for the next five years were $109.1 million in 2000, $9.1
million in 2001, $10.6 million in 2002, $115.2 million in 2003, and $117.1
million in 2004.
Total interest and other charges were $118.7 million in 1999, $80.2 million in
1998 and $85.8 million in 1997. Interest costs attributable to debt were
$84.3 million, $82.4 million and $88.2 million in 1999, 1998 and 1997,
respectively. Of these amounts, $0.8 million in 1999, $2.2 million in 1998 and
$2.3 million in 1997 were capitalized as AFC. Debt discount or premium and
related issuance expenses are amortized over the lives of the applicable issues.
Other interest in 1999 also includes $35.2 million related to the Beaver Valley
Unit 2 lease expense, previously classified as other operating expenses.
At December 31, 1999, 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 $1,796.7 million. The principal amount
included in the consolidated balance sheet is $1,813.0 million.
At December 31, 1999 and 1998, we were in compliance with all of our debt
covenants.
26
K. PREFERRED AND PREFERENCE STOCK
Preferred and Preference Stock at December 31,
- -----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------------------
1999 1998
Call Price ------------------------------------------------
Per Share Shares Amount Shares Amount
Preferred Stock Series:
3.75% (a) $51.00 148,000 $ 7,407 148,000 $ 7,407
4.00% (a) 51.50 549,709 27,486 549,709 27,486
4.10% (a) 51.75 119,860 6,012 119,860 6,012
4.15% (a) 51.73 132,450 6,643 132,450 6,643
4.20% (a) 51.71 100,000 5,021 100,000 5,021
$2.10 (a) 51.84 159,000 8,039 159,000 8,039
9.00% (b) -- 10 3,000 10 3,000
8.375% (c) -- 6,000,000 150,000 6,000,000 150,000
6.5% (d) -- 15 1,500 15 1,500
- -----------------------------------------------------------------------------------------------------------
Total Preferred Stock 215,108 215,108
- -----------------------------------------------------------------------------------------------------------
Preference Stock Series:
Plan Series A (e) 36.06 752,018 25,279 779,394 26,914
- -----------------------------------------------------------------------------------------------------------
Deferred ESOP benefit (10,875) (14,240)
- -----------------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock $229,512 $227,782
===========================================================================================================
(a) 4,000,000 authorized shares; $50 par value; cumulative; $50 per share
involuntary liquidation value
(b) 500 authorized shares; $300,000 par value; these shares were redeemed
at par value on March 2, 2000
(c) Cumulative Monthly Income Preferred Securities, Series A (MIPS); 6,000,000
authorized shares; $25 involuntary liquidation value
(d) 1,500 authorized shares; $100,000 par value; $100,000 involuntary
liquidation value; holders entitled to 6.5 percent annual dividend each
September
(e) Preference stock: 8,000,000 authorized shares; $1 par value; cumulative
$35.50 per share involuntary liquidation value; non-redeemable
In May 1996, Duquesne Capital L.P. (Duquesne Capital), a special-purpose
limited partnership of which we are the sole general partner, issued $150.0
million principal amount of 8-3/8 percent Monthly Income Preferred Securities
(MIPS) Series A, with a stated liquidation value of $25.00. The holders of MIPS
are entitled to annual dividends of 8-3/8 percent, payable monthly. The sole
assets of Duquesne Capital are our 8-3/8 percent debentures. These debt
securities may be redeemed at our option on or after May 31, 2001. We have
guaranteed the payment of distributions on, and redemption price and
liquidation amount in respect of the MIPS, if Duquesne Capital has funds
available for such payment from the debt securities. Upon maturity or prior
redemption of such debt securities, the MIPS will be mandatorily redeemed.
Holders of our preferred stock are entitled to cumulative quarterly dividends.
If four quarterly dividends on any series of preferred stock are in arrears,
holders of the preferred stock are entitled to elect a majority of our board of
directors until all dividends have been paid. 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, 1999, we had made all dividend payments. Preferred and preference dividends
included in interest and other charges were $16.5 million, $16.6 million and
$16.6 million in 1999, 1998 and 1997. Total preferred and preference stock had
involuntary liquidation values of $285.3 million and $278.4 million, which
exceeded par by $26.9 million at December 31, 1999 and 1998.
In December 1991, we established an Employee Stock Ownership Plan (ESOP) to
provide matching contributions for a 401(k) Retirement Savings Plan for
Management Employees. (See "Employee Benefits," Note M, on page 28.) 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, 1999, $10.9 million of
preference stock issued in connection with the establishment of the ESOP had
been offset, for financial statement purposes, by the recognition of a deferred
ESOP benefit. Dividends on the preference stock and cash contributions from DQE
are used to fund the repayment of the ESOP note. We were not
27
required to make a cash contribution for 1998. We made cash contributions of
approximately $0.2 million for 1999 and $1.1 million for 1997. These cash
contributions were the difference between the ESOP debt service and the amount
of dividends on ESOP shares ($2.1 million in 1999, $2.2 million in 1998 and $2.3
million in 1997). As shares of preference stock are allocated to the accounts of
participants in the ESOP, we recognize compensation expense, and the amount of
the deferred compensation benefit is amortized. We recognized compensation
expense related to the 401(k) plans of $3.6 million in 1999, $1.6 million in
1998 and $3.2 million in 1997. Although outstanding preferred stock is generally
callable on notice of not less than 30 days, at stated prices plus accrued
dividends, the outstanding MIPS and preference stock are not currently callable.
None of the remaining preferred or preference stock issues has mandatory
purchase requirements.
L. EQUITY
In July 1989, we became a wholly owned subsidiary of DQE, formed as a holding
company. DQE common stock replaced outstanding shares of our common stock,
except for 10 shares held by DQE.
Payments of dividends on our common stock may be restricted by our obligations
to holders of preferred and preference stock, pursuant to our Restated Articles
of Incorporation, and by obligations of our subsidiaries to holders of their
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
stock or DQE Preferred Stock. No part of our retained earnings was restricted at
December 31, 1999.
Effective December 31, 1998, we adopted SFAS No. 130, Reporting Comprehensive
Income. This statement establishes standards for reporting and display of
comprehensive income and its components (revenues, expenses, gains and losses)
in a full set of general purpose financial statements. The objective of the
statement is to report a measure of all changes in equity of a business
enterprise that result from recognized transactions and other economic events of
the period, other than transactions with owners in their capacity as owners
(comprehensive income).
Accumulated Other Comprehensive Income
Balances as of December 31,
- --------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------
1999 1998
- --------------------------------------------------------------------------------
January 1 $21,697 $14,046
Unrealized gains (losses), net (9,005) 7,651
- --------------------------------------------------------------------------------
December 31 $12,692 $21,697
================================================================================
M. EMPLOYEE BENEFITS
Pension and Postretirement Benefits
We maintain retirement plans to provide pensions for all eligible employees.
Upon retirement, an eligible employee receives a monthly pension based on his
or her length of service and compensation. The cost of funding the pension 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 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 to expense or
construction were $11.2 million for 1999, $12.0 million for 1998 and $12.7
million for 1997.
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 is recognized as special termination benefits in the table
on page 29. The remaining $12.0 million is reflected in the unrecognized
actuarial gain/loss account in the table.
In addition to pension benefits, we provide certain health care benefits and
life insurance for some retired employees. Participating retirees make
contributions, which may be adjusted annually, to the health care plan. The life
insurance plan is non-contributory. Health care benefits terminate when covered
individuals become eligible for Medicare benefits or reach age 65, whichever
comes first. 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
28
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, 1999, a statement of the funded status as of December
31, 1999 and 1998, and 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
-------------------------------------------------
1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of year $ 605,597 $ 554,302 $ 46,358 $ 46,330
Service cost 14,374 14,042 1,800 1,832
Interest cost 39,929 37,723 3,100 3,078
Actuarial (gain) loss (77,348) 26,231 4,206 (3,003)
Benefits paid (29,533) (26,592) (2,306) (1,879)
Plan amendments -- -- -- --
Curtailments 8,372 -- 4,400 --
Settlements (41) (109) -- --
Special termination benefits 17,376 -- -- --
- -------------------------------------------------------------------------------------------------------
Benefit obligation at end of year 578,726 605,597 57,558 46,358
- -------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of year 681,244 605,457 -- --
Actual return on plan assets 92,331 91,561 -- --
Employer contributions -- 10,706 -- --
Benefits paid (29,420) (26,480) -- --
- -------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 744,155 681,244 -- --
- -------------------------------------------------------------------------------------------------------
Funded status 165,429 75,647 (57,558) (46,358)
Unrecognized net actuarial (gain) loss (285,795) (173,974) 5,108 (1,795)
Unrecognized prior service cost 32,022 36,285 -- --
Unrecognized net transition obligation 8,109 10,227 21,227 23,607
- -------------------------------------------------------------------------------------------------------
Accrued benefit cost $ (80,235) $ (51,815) $ (31,223) $ (24,546)
=======================================================================================================
Weighted-Average Assumptions as of December 31,
- -------------------------------------------------------------------------------------------------------
Pension Postretirement
-------------------------------------------------
1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------
Discount rate used to determine projected
benefits obligation 7.50% 6.50% 7.50% 6.50%
Assumed rate of return on plan assets 7.50% 7.50% -- --
Assumed change in compensation levels 4.25% 4.25% -- --
Ultimate health care cost trend rate -- -- 6.00% 5.00%
All of our plans for postretirement benefits, other than pensions, have no
plan assets. The aggregate benefit obligation for those plans was $57.6
million as of December 31, 1999, and $46.4 million as of December 31, 1998. 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.
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 of the postretirement benefits is estimated to be $4 million. This
increase is reflected in the unrecognized actuarial gain/loss account in the
above table.
Pension assets consist primarily of common stocks exclusive of DQE common
stock, United States obligations and corporate debt securities.
29
Components of Net Pension Cost as of December 31,
- -----------------------------------------------------------------------------------------------
(Thousands of Dollars)
----------------------------------
1999 1998 1997
- -----------------------------------------------------------------------------------------------
Components of net pension cost:
Service cost $ 14,374 $ 14,043 $ 12,340
Interest cost 39,929 37,723 36,571
Expected return on plan assets (45,562) (41,067) (38,265)
Amortization of unrecognized net transition obligation 1,759 1,812 1,812
Amortization of prior service cost 3,458 3,515 3,515
Recognized net actuarial gain (2,717) (4,014) (3,243)
- -----------------------------------------------------------------------------------------------
Net pension cost 11,241 12,012 12,730
Curtailment cost (14) -- 477
Settlement cost 78 224 652
Special termination benefits 17,376 -- 5,409
- -----------------------------------------------------------------------------------------------
Net Pension Cost After Curtailments,
Settlements and Special Termination Benefits $ 28,681 $12,236 $ 19,268
===============================================================================================
Components of Postretirement Cost as of December 31,
- -----------------------------------------------------------------------------------------------
(Thousands of Dollars)
----------------------------------
1999 1998 1997
- -----------------------------------------------------------------------------------------------
Components of postretirement cost:
Service cost $ 1,799 $ 1,832 $ 1,603
Interest cost 3,099 3,078 3,048
Amortization of unrecognized net transition obligation 1,642 1,687 1,686
- -----------------------------------------------------------------------------------------------
Net postretirement cost 6,540 6,597 6,337
Curtailment cost 2,443 -- 218
- -----------------------------------------------------------------------------------------------
Net Postretirement Cost After Curtailments $ 8,983 $ 6,597 $ 6,555
===============================================================================================
Effect of a One Percent Change in Health Care Cost Trend Rates as of December 31,1999
- -----------------------------------------------------------------------------------------------
(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 $ 560 $ (485)
Effect on the health care component of the accumulated
postretirement benefit obligation $5,787 $ (5,069)
Retirement Savings Plan and Other Benefit Options
We sponsor separate 401(k) retirement plans for our management and IBEW-
represented employees.
The 401(k) Retirement Savings Plan for Management Employees provides that
we match employee contributions to a 401(k) account up to a maximum of six
percent of an employee's eligible salary. Our match consists of a $0.25 base
match per eligible contribution dollar, and an additional $0.25 incentive match
per eligible contribution dollar, if board-approved targets are achieved. In
1999, all management employees achieved their incentive targets. We are funding
our 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 K, on page 27.)
The 401(k) Retirement Savings Plan for IBEW Represented Employees provides
that we will match employee contributions to a 401(k) account up to a maximum of
four percent of an employee's eligible salary. Our match consists of a $0.25
base match per eligible contribution dollar and an additional $0.25 incentive
match per eligible contribution dollar, if certain targets are met. In 1999, all
bargaining unit employees achieved their incentive targets.
DQE's shareholders have approved a long-term incentive
30
plan through which we may grant management employees options to purchase, during
the years 1987 through 2006, up to a total of 9.9 million shares of DQE common
stock at prices equal to the fair market value of such stock on the dates the
options were granted. At December 31, 1999, approximately 3.7 million of these
shares were available for future grants. The following paragraph sets forth
option information for all DQE affiliates under the plan, including Duquesne
Light.
As of December 31, 1999, 1998 and 1997, active grants totaled 1,031,434;
1,230,946 and 1,084,041 shares. Exercise prices of these options ranged from
$17.5834 to $43.4375 at December 31, 1999; from $15.8334 to $43.4375 at December
31, 1998; and from $15.8334 to $33.7813 at December 31, 1997. Expiration dates
of these grants ranged from 2001 to 2009 at December 31, 1999; from 2000 to 2008
at December 31, 1998; and from 2000 to 2007 at December 31, 1997. As of December
31, 1999, 1998 and 1997, stock appreciation rights (SARs) had been granted in
connection with 933,014; 867,104 and 635,995 of the options outstanding. During
1999, 45,265 SARs were exercised; 254,225 options were exercised at prices
ranging from $17.5834 to $35.0625; and 33,000 options were cancelled. During
1998, 233,532 SARs were exercised; 170,476 options were exercised at prices
ranging from $15.8334 to $31.5625; and no options were cancelled. During
1997, 694,984 SARs were exercised; 638,494 options were exercised at prices
ranging from $8.2084 to $30.75; and no options were cancelled. Of the active
grants at December 31, 1999, 1998 and 1997, 132,105; 750,463; and 402,816 were
not exercisable.
N. BUSINESS SEGMENTS AND RELATED INFORMATION
We report our results by the following three principal business segments,
determined by products, services and regulatory environment: (1) the
transmission and distribution of electricity (electricity delivery business
segment), (2) the supply of electricity (electricity supply business segment)
and (3) the collection of transition costs (CTC business segment). We also
report an "all other" category, which includes investments below the
quantitative threshold for separate disclosure.
Business Segments as of December 31,
- -------------------------------------------------------------------------------------------------------
(Millions of Dollars)
------------------------------------------------------------
Electricity Electricity All Consoli-
Delivery Supply CTC Other dated
------------------------------------------------------------
1999
- -------------------------------------------------------------------------------------------------------
Operating revenues $ 338.6 $437.7 $ 377.9 $ 4.6 $1,158.8
Operating expenses 192.1 416.4 107.5 10.7 726.7
Depreciation and amortization expense 46.0 26.3 95.6 4.5 172.4
- -------------------------------------------------------------------------------------------------------
Operating income (loss) 100.5 (5.0) 174.8 (10.6) 259.7
Other income 0.6 7.4 (1.3) 15.8 22.5
Interest and other charges 44.6 43.9 45.4 1.3 135.2
- -------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ 56.5 $(41.5) $ 128.1 $ 3.9 $ 147.0
=======================================================================================================
Assets $1,535.4 $425.7 $2,226.8 $ 93.5 $4,281.4
=======================================================================================================
Capital expenditures $ 69.9 $ 30.4 $ -- $ -- $ 100.3
=======================================================================================================
31
(Millions of Dollars)
-------------------------------------------------------
Electricity Electricity All Consoli-
Delivery Supply Other dated
-------------------------------------------------------
1998
- ---------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 321.5 $ 855.3 $ 1.9 $ 1,178.7
Operating expenses 183.7 579.6 7.1 770.4
Depreciation and amortization expense 46.1 158.1 -- 204.2
- ---------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 91.7 117.6 (5.2) 204.1
Other income 3.2 12.9 21.1 37.2
Interest and other charges 37.7 58.6 0.5 96.8
- ---------------------------------------------------------------------------------------------------------------------------
Earnings for common stock before extraordinary item 57.2 71.9 15.4 144.5
Extraordinary item, net of tax -- (82.6) -- (82.6)
- ---------------------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock after extraordinary item $ 57.2 $ (10.7) $ 15.4 $ 61.9
===========================================================================================================================
Assets $ 1,448.8 $ 2,711.5 $ 149.3 $ 4,309.6
===========================================================================================================================
Capital expenditures $ 71.7 $ 41.6 $ 5.1 $ 118.4
===========================================================================================================================
(Millions of Dollars)
-------------------------------------------------------
Electricity Electricity All Consoli-
Delivery Supply Other dated
-------------------------------------------------------
1997
- ---------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 316.9 $ 859.0 $ -- $ 1,175.9
Operating expenses 177.4 555.2 1.2 733.8
Depreciation and amortization expense 44.2 190.5 -- 234.7
- ---------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 95.3 113.3 (1.2) 207.4
Other income 5.2 11.0 16.6 32.8
Interest and other charges 38.6 63.8 -- 102.4
- ---------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 61.9 $ 60.5 $ 15.4 $ 137.8
===========================================================================================================================
Assets $ 1,476.1 $ 2,201.2 $ 162.9 $ 3,840.2
===========================================================================================================================
Capital expenditures $ 57.6 $ 32.8 $ 3.3 $ 93.7
===========================================================================================================================
O. QUARTERLY FINANCIAL
INFORMATION (UNAUDITED)
The earnings in the following table include $.20 per share related to
accounting for transition cost recovery. This increase primarily relates to
synchronizing the beginning of the transition cost recovery period with the
functional unbundling of customer bills and the application of specific customer
rates to the collection of transition cost. The final PUC approval of our
transition cost accounting is anticipated during the third quarter of 2000.
Summary of Selected Quarterly Financial Data (Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------------------
[The quarterly data reflect seasonal weather variations in the electric utility's service territory.]
- ---------------------------------------------------------------------------------------------------------------------------
1999 (a) First Quarter Second Quarter Third Quarter Fourth Quarter
- ---------------------------------------------------------------------------------------------------------------------------
Operating revenues $281,976 $273,239 $336,165 $267,420
Operating income 49,397 54,478 65,236 90,653
Net income 35,868 28,576 37,040 49,536
===========================================================================================================================
1998 (a) First Quarter Second Quarter Third Quarter Fourth Quarter
- ---------------------------------------------------------------------------------------------------------------------------
Operating revenues $287,057 $287,333 $326,677 $277,679
Operating income 48,984 45,818 63,181 46,103
Income before extraordinary item 36,300 30,560 48,243 33,445
Extraordinary item -- (82,548) -- --
Net income after extraordinary item 36,300 (51,988) 48,243 33,445
===========================================================================================================================
(a) Restated to conform with 1999 presentation.
32
SELECTED FINANCIAL DATA
- ----------------------------------------------------------------------------------------------------------------------------------
Amounts in Thousands of Dollars 1999 1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT ITEMS
Total operating revenues $ 1,158,800 $ 1,178,746 $ 1,175,941 $ 1,187,407 $ 1,189,784 $ 1,180,624
Operating income $ 259,764 $ 204,086 $ 207,385 $ 222,079 $ 246,637 $ 236,556
Income before extraordinary item $ 151,020 $ 148,548 $ 141,820 $ 149,860 $ 151,070 $ 147,449
Extraordinary item $ -- $ (82,548) $ -- $ -- $ -- $ --
Net income after extraordinary item $ 151,020 $ 66,000 $ 141,820 $ 149,860 $ 151,070 $ 147,449
Earnings for common stock
before extraordinary item $ 147,022 $ 144,512 $ 137,798 $ 145,815 $ 145,750 $ 141,403
Earnings for common stock
after extraordinary item $ 147,022 $ 61,964 $ 137,798 $ 145,815 $ 145,750 $ 141,403
- ----------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET ITEMS
Property, plant and equipment - net $ 1,458,517 $ 1,447,299 $ 2,562,919 $ 2,717,473 $ 2,978,903 $ 3,068,519
Total assets $ 4,281,412 $ 4,309,626 $ 3,840,179 $ 3,897,086 $ 4,067,665 $ 4,149,867
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Common stockholder's equity $ 798,674 $ 868,500 $ 1,003,833 $ 989,424 $ 1,131,334 $ 1,115,512
Non-redeemable preferred and
preference stock 229,512 227,782 226,503 223,072 70,966 95,345
Redeemable preferred and
preference stock -- -- -- -- -- --
Long-term debt 1,410,754 1,160,348 1,218,276 1,271,961 1,322,531 1,368,930
- ----------------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 2,438,940 $ 2,256,630 $ 2,448,612 $ 2,484,457 $ 2,524,831 $ 2,579,787
- ----------------------------------------------------------------------------------------------------------------------------------
33
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT.
Information relating to our board of directors is set forth in Exhibit 99.2
hereto. The information is incorporated here by reference. Information relating
to our executive officers is set forth in Part I of this Report under the
caption "Executive Officers of the Registrant." Information relating to
compliance with section 16(a) of the Securities Exchange Act of 1934 is set
forth in Exhibit 99.1 hereto, and incorporated here by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The information relating to executive compensation is set forth in Exhibit
99.1, filed as part of this Report. The information is incorporated here by
reference.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT.
DQE is the beneficial owner and holder of all shares of our outstanding common
stock, $1 par value, consisting of 10 shares as of February 29, 2000.
Information relating to the ownership of equity securities of DQE and Duquesne
Light by our directors and executive officers is set forth in Exhibit 99.1,
filed as part of this Report. The information is incorporated here by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS.
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES AND REPORTS ON FORM 8-K.
(a)(1) The following information is set forth here in Item 8 (Consolidated
Financial Statements and Supplementary Data) on pages 14 through 32 of this
Report. The following financial statements and Report of Independent Auditors
are incorporated here by reference:
Report of Independent Auditors.
Statement of Consolidated Income for the Three Years Ended December 31, 1999.
Consolidated Balance Sheet, December 31, 1998 and 1999.
Statement of Consolidated Cash Flows for the Three Years Ended December
31, 1999.
Statement of Consolidated Comprehensive Income for the Three Years Ended
December 31, 1999.
Statement of Consolidated Retained Earnings for the Three Years Ended December
31, 1999.
Notes to Consolidated Financial Statements.
(a)(2) The following financial statement schedule and the related Report of
Independent Auditors are filed here as a part of this Report:
Schedule for the Three Years Ended December 31, 1999:
II - Valuation and Qualifying Accounts.
The remaining schedules are omitted because of the absence of the conditions
under which they are required or because the information called for is shown in
the financial statements or notes to the consolidated financial statements.
(a)(3) Exhibits are set forth in the Exhibit Index below, incorporated here by
reference. Documents other than those designated as being filed here are
incorporated here by reference. Documents incorporated by reference to a DQE
Annual Report on Form 10-K, a Quarterly Report on Form 10-Q or a Current Report
on Form 8-K are at Securities and Exchange Commission File No. 1-10290.
Documents incorporated by reference to a Duquesne Light Company Annual Report
on Form 10-K, a Quarterly Report on Form 10-Q or a Current Report on Form 8-K
are at Securities and Exchange Commission File No. 1-956. The Exhibits include
the management contracts and compensatory plans or arrangements required to be
filed as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.
(b) We filed three reports on Form 8-K during the fiscal quarter ended
December 31, 1999.
A report was filed December 8, 1999, to report the judge's decision in
favor of DQE in the AYE lawsuit regarding termination of the merger
agreement. No financial statements were filed with this report.
A report was filed December 20, 1999, to report the power station
exchange with FirstEnergy Corporation. No financial statements were
filed with this report.
A report was filed December 27, 1999, to report certain earnings
adjustments. No financial statements were filed with this report.
34
Exhibits Index
Exhibit Method of
No. Description Filing
2.1 Generation Exchange Agreement by and between Exhibit 2.1 to the Form 8-K
Duquesne Light Company, on the one hand, and Current Report of DQE
The Cleveland Electric Illuminating Company, dated March 26, 1999.
Ohio Edison Company and Pennsylvania Power
Company, on the other, dated as of March 25, 1999.
2.2 Nuclear Generation Conveyance Agreement by and Exhibit 2.2 to the Form 8-K
between Duquesne Light Company, on the one hand, Current Report of DQE
and Pennsylvania Power Company and the Cleveland dated March 26, 1999.
Electric Illuminating Company, on the other, dated
as of March 25, 1999.
2.3 Asset Purchase Agreement, dated as of September 24, Exhibit 2.1 to the Form 8-K
1999, by and between Duquesne Light Company, Current Report of Duquesne
Orion Power Holdings, Inc., and The Cleveland Electric Light dated September 24, 1999.
Illuminating Company, Ohio Edison and Pennsylvania
Power Company.
2.4 POLR Agreement, dated as of September 24, 1999 Exhibit 2.2 to the Form 8-K
by and between Duquesne Light Company and Orion Current Report of Duquesne
Power Holdings, Inc. Light dated September 24, 1999.
3.1 Restated Articles of Incorporation of Duquesne Light Exhibit 3.1 to the Form 10-Q
as currently in effect. Quarterly Report of Duquesne
Light for the quarter ended
June 30, 1999.
3.2 By-Laws of Duquesne Light, as amended through Exhibit 3.2 to the Form 10-Q
June 29, 1999 and as currently in effect. Quarterly Report of Duquesne
Light for the quarter ended
June 30, 1999.
4.1 Indenture dated March 1, 1960, relating to Duquesne Exhibit 4.3 to the Form 10-K
Light Company's 5% Sinking Fund Debentures. Annual Report of DQE for the
year ended December 31, 1989.
4.2 Indenture of Mortgage and Deed of Trust dated as of Exhibit 4.3 to Registration
April 1, 1992, securing Duquesne Light Company's Statement (Form S-3)
First Collateral Trust Bonds. No. 33-52782.
35
Exhibit Method of
No. Description Filing
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.
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. Filed here.
Supplemental Indenture No. 16. Filed here.
4.4 Amended and Restated Agreement of Limited Partnership Exhibit 4.4 to the Form 10-K
of Duquesne Capital L.P., dated as of May 14, 1996. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
4.5 Payment and Guarantee Agreement, dated as of May 14, Exhibit 4.5 to the Form 10-K
1996, by Duquesne Light Company with respect to MIPS. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
4.6 Indenture, dated as of May 1, 1996, by Duquesne Light Exhibit 4.6 to the Form 10-K
Company to the First National Bank of Chicago as Trustee. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
36
Exhibit Method of
No. Description Filing
10.1 Deferred Compensation Plan for the Directors of Exhibit 10.1 to the Form 10-K
Duquesne Light Company, as amended to date. Annual Report of DQE for the
year ended December 31, 1992.
10.2 Incentive Compensation Program for Certain Executive Exhibit 10.2 to the Form 10-K
Officers of Duquesne Light Company, as amended to date. Annual Report of DQE for the
year ended December 31, 1992.
10.3 Description of Duquesne Light Company Pension Exhibit 10.3 to the Form 10-K
Service Supplement Program. Annual Report of DQE for the
year ended December 31, 1992.
10.4 Duquesne Light Company Outside Directors' Exhibit 10.59 to the Form 10-K
Retirement Plan, as amended to date. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
10.5 Duquesne Light/DQE Charitable Giving Program, Exhibit 10.1 to the Form 10-Q
as amended. Quarterly Report of DQE for
the quarter ended March 31, 1998.
10.6 Performance Incentive Program for DQE, Inc. and Exhibit 10.7 to the Form 10-K
Subsidiaries. Formerly known as the Duquesne Light Annual Report of DQE for the
Company Performance Incentive Program. year ended December 31, 1996.
10.7 Employment Agreement dated as of January 1, 2000 Exhibit 10.8 to the Form 10-K.
between DQE and David D. Marshall. Annual Report of DQE for the
year ended December 31, 1999.
10.8 Employment Agreement dated as of August 30, 1994 Exhibit 10.10 to the Form 10-K
between DQE, Duquesne Light Company and Annual Report of DQE for the
Gary L. Schwass. year ended December 31, 1994.
10.9 Amended and Restated Employment Agreement between Exhibit 10.1 to the Form 10-Q
Duquesne Light Company and James E. Cross. Quarterly Report of Duquesne
Light Company for the quarter
ended March 31, 1999.
10.10 Non-Competition and Confidentiality Agreement dated Exhibit 10.14 to the Form 10-K
as of October 3, 1996 by and among DQE, Inc., Duquesne Annual Report of DQE for the
Light Company and David D. Marshall, together with a year ended December 31, 1996.
schedule listing substantially identical agreements with
Victor A. Roque and James E. Cross.
10.11 Schedule to Exhibit 10.14 to the Form 10-K Annual Report Exhibit 10.12 to the Form 10-K
of DQE for the year ended December 31, 1996, listing a Annual Report of DQE for the
Non-Competition and Confidentiality Agreement dated as year ended December 31, 1999.
of October 3, 1996, with William J. DeLeo, substantially
identical to the agreement filed as Exhibit 10.14 to the
1996 10-K.
37
Exhibit Method of
No. Description Filing
10.12 Severance Agreement dated April 4, 1997, between Exhibit 10.1 to the Form 10-Q
the Company and David D. Marshall, together with a Quarterly Report of DQE for
schedule describing substantially identical agreements the quarter ended March 31, 1997.
with Gary L. Schwass, Victor A. Roque and James E. Cross.
10.13 Schedule to Exhibit 10.1 to the Form 10-Q Quarterly Exhibit 10.14 to the Form 10-K
Report of DQE for the quarter ended March 31, 1997, Annual Report of DQE for the
listing a Severance Agreement dated as of April 4, 1997, year ended December 31, 1999.
with William J. DeLeo, substantially identical to the
agreement filed as Exhibit 10.1 to the March 31, 1997
10-Q.
12.1 Ratio of Earnings to Fixed Charges. Filed here.
21.1 Subsidiaries of the registrant:
Duquesne Light has no significant subsidiaries
23.1 Independent Auditors' Consent. Filed here.
27.1 Financial Data Schedule. Filed here.
99.1 Executive Compensation and Security Ownership of Filed here.
Directors and Officers for 1999.
99.2 Directors of Duquesne Light. Filed here.
Copies of the exhibits listed above will be furnished, upon request, to
holders or beneficial owners of any class of our stock as of February 29, 2000,
subject to payment in advance of the cost of reproducing the exhibits requested.
38
SCHEDULE II
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 1999, 1998 and 1997
(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, 1999
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $ 9,137 $ 9,000 $3,260 (A) $12,667 (B) $ 8,730
-------- ------- ---------- ----------- -------
Year Ended December 31, 1998
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $15,016 $11,000 $3,290 (A) $20,169 (B) $ 9,137
------- ------- ---------- ----------- -------
Year Ended December 31, 1997
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $18,294 $11,000 $3,934 (A) $18,212 (B) $15,016
-------- ------- ---------- ----------- -------
Notes: (A) Recovery of accounts previously written off.
(B) Accounts receivable written off.
39
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 29, 2000 By: /s/ David D. Marshall
--------------------------------
(Signature)
David D. Marshall
Chairman, Chief Executive Officer
and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ David D. Marshall Chairman, Chief Executive Officer and Director March 29, 2000
- -------------------------------
David D. Marshall
/s/ Gary L. Schwass Senior Vice President, Chief Financial Officer March 29, 2000
- ------------------------------- and Director
Gary L. Schwass
/s/ Stevan R. Schott Vice President and Controller March 29, 2000
- ------------------------------- (Principal Accounting Officer)
Stevan R. Schott
/s/ John R. Marshall Director March 29, 2000
- -------------------------------
John R. Marshall
/s/ Morgan K. O'Brien Director March 29, 2000
- -------------------------------
Morgan K. O'Brien
/s/Victor A. Roque Director March 29, 2000
- -------------------------------
Victor A. Roque
/s/ Jack E. Saxer, Jr. Director March 29, 2000
- -------------------------------
Jack E. Saxer, Jr.
40