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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1998
[ ] 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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1-10290
DQE, Inc.
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-1598483
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Cherrington Corporate Center, Suite 100
500 Cherrington Parkway, Coraopolis, Pennsylvania 15108-3184
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(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (412) 262-4700
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
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Aggregate market value of DQE Common Stock held by non-affiliates as of February
28, 1999 was $2,953,420,555. There were 77,309,182 shares of DQE Common Stock
outstanding as of February 28, 1999.
[X] 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.
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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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DQE Common Stock (no par value) New York Stock Exchange
Philadelphia Stock Exchange
Chicago Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of each class
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DQE Preferred Stock, Series A (Convertible)
DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K
Into Which Document
Description Is Incorporated
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DQE Annual Report to Shareholders Parts I and II
for the year ended December 31, 1998
Proxy Statement for DQE Annual Meeting Part III
of Shareholders to be held April 27, 1999
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Table of Contents
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Page
GLOSSARY ----
<S> <C> <C>
PART I
ITEM 1. BUSINESS
Corporate Structure 1
Property, Plant and Equipment (PP&E) 2
Employees 3
Electric Utility Operations 3
Environmental Matters 6
Other 7
Executive Officers of the Registrant 8
ITEM 2. PROPERTIES 9
ITEM 3. LEGAL PROCEEDINGS 10
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS 11
PART II
ITEM 5. MARKET FOR REGISTRANT'S
COMMON EQUITY AND RELATED
SHAREHOLDER MATTERS 11
ITEM 6. SELECTED FINANCIAL DATA 11
ITEM 7. MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF
OPERATIONS
Results of Operations 12
Liquidity and Capital Resources 17
Rate Matters 19
Year 2000 21
ITEM 7A. QUANTITATIVE AND
QUALITATIVE DISCLOSURES
ABOUT MARKET RISK 23
ITEM 8. REPORT OF INDEPENDENT
CERTIFIED PUBLIC
ACCOUNTANTS; CONSOLIDATED
FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA 24
ITEM 9. CHANGES IN AND
DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 52
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT 52
ITEM 11. EXECUTIVE COMPENSATION 52
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT 52
ITEM 13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS 52
PART IV
ITEM 14. EXHIBITS, FINANCIAL
STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K 53
SCHEDULE II
SIGNATURES
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Glossary of Terms
Competitive Transition Charge (CTC) -- During the electric utility restructuring
from the traditional regulatory framework to customer choice, electric utilities
will 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 19) 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, the Company historically recorded deferred energy costs to offset
differences between actual energy costs and the level of energy costs currently
recovered from its rate-regulated electric utility customers.
Distribution/Transmission -- The Company's "electricity delivery" business
segment. 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).
Divestiture -- The selling of major assets. The Company currently anticipates
divestiture of its generation assets through an auction and the power station
exchange.
Energy Cost Rate Adjustment Clause (ECR) -- Until May 29, 1998, the Company
historically recovered through the ECR, to the extent that such amounts were not
included in base rates, the cost of nuclear fuel, fossil fuel and purchased
power costs.
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.
Market Power -- When one company owns a sufficiently large percentage of
generation, transmission, or distribution capabilities in a region allowing it
to set the market price of electricity.
Obligation to Serve -- Under traditional regulation, the duty of a regulated
utility to provide service to all customers in its service territory on a non-
discriminatory basis.
Pennsylvania Public Utility Commission (PUC) -- The governmental body that
regulates all utilities (electric, gas, telephone, water, etc.) that do business
in Pennsylvania.
Power Station Exchange -- Duquesne and FirstEnergy Corporation have an agreement
to exchange ownership interests in certain power plants. (See "Rate Matters" on
page 19.)
Price to Compare -- The Company will provide a credit to a customer for the PUC-
determined market price of electric generation. Customers will experience
savings to the extent that they can purchase power at a lower price from an
alternative electric generation supplier than the amount of the credit.
Provider of Last Resort -- 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 19.)
Rate Base -- The amount representing the value of assets approved by a
regulatory agency for recognition in the rates charged to rate-regulated
customers.
Regulatory Assets -- Historical ratemaking practices granted exclusive
geographic franchises in exchange for the obligation to serve all customers.
Under this system, certain prudently incurred costs were approved by the PUC and
the FERC for deferral and future recovery with a return from customers. These
deferred costs were capitalized as regulatory assets by the regulated utility.
Restructuring Plan -- The Company's plan, approved by the PUC, for restructuring
and recovery of transition costs under Pennsylvania's Customer Choice Act.
Stranded Costs -- Stranded costs are the net present value of a utility's known
or measurable costs related to electric generation that are not recoverable
through the CTC.
Tariff -- Public schedules that detail a utility's rates, rules, service
territory and terms of service; tariffs are filed for official approval with a
regulatory agency.
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.
Watt -- A watt is the rate at which electricity is generated or consumed. A
kilowatt (KW) 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.
<PAGE>
Part I
Item 1. Business.
Corporate Structure
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Part I of this Annual Report on Form 10-K (Report) should be read in
conjunction with DQE's audited consolidated financial statements, which are set
forth on pages 25 through 51 in Part IV 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.
DQE, Inc. (DQE) is a multi-utility delivery and services company. Its
subsidiaries are Duquesne Light Company (Duquesne); AquaSource, Inc.
(AquaSource); DQE Energy Services, Inc. (DES); DQEnergy Partners, Inc.
(DQEnergy); Duquesne Enterprises, Inc. (DE); and Montauk, Inc. (Montauk). DQE
and its subsidiaries are collectively referred to as "the Company."
The Company's utility operations include an electric utility engaged in the
generation, transmission, distribution and sale of electric energy and a water
resource management company that acquires, develops and manages water and
wastewater utilities. The Company's expanded business lines offer a wide range
of energy-related technologies, industrial and commercial energy services,
telecommunications, and other complementary services. The expanded business
lines' initiatives include energy facility development and operation, domestic
and international independent power production, the production and supply of
innovative fuels, investments in communications systems (including long-distance
telephone service) and electronic commerce. In addition, one of the Company's
subsidiaries is a financial services company that makes long-term investments
and provides financing for the other expanded business lines and related
customers.
On December 18, 1998, the Pennsylvania Public Utility Commission (PUC)
approved the Company's plan to divest itself of its generation assets through an
auction (including an auction of its provider of last resort service), and an
agreement in principle to exchange certain power stations with FirstEnergy
Corporation (FirstEnergy). Final agreements governing these transactions must be
approved by various regulatory agencies. The Company currently expects these
transactions to close in late 1999 or early 2000. (See "Rate Matters" on page
19.)
The Company's Service Areas
The Company's electric utility operations provide service to customers in the
City of Pittsburgh and surrounding areas. (See "Rate Matters" on page 19.) This
territory represents approximately 800 square miles in southwestern
Pennsylvania. The population of the area served by the Company's electric
utility operations, based on 1990 census data, is approximately 1,510,000, of
whom 370,000 reside in the City of Pittsburgh. In addition to serving
approximately 580,000 direct customers, the Company's utility operations also
sell electricity to other utilities.
The Company's water utility operations provide service throughout the United
States. The Company's water utility and related service operations have grown
rapidly and are currently approaching 300,000 customer connections.
Regulation
The Company is subject to the accounting and reporting requirements of the
Securities and Exchange Commission (SEC). In addition, the Company's 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. (See "Rate
Matters" on page 19.)
The Company's electric utility operations are also subject to regulation by
the Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954, as
amended, with respect to the operation of its jointly owned/leased nuclear power
plants, Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and
Perry Unit 1.
The Company's water utility operations are subject to regulation by the
utility regulatory bodies in their respective states.
As a result of the PUC's May 29, 1998, final order regarding the Company's
restructuring plan under the Customer Choice Act (see "Rate Matters" on page
19), the electricity generation portion of the Company's business no longer
meets the criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, application of SFAS No.71 to this portion of the Company's business
has been discontinued and the Company now applies SFAS No. 101, Regulated
Enterprises Accounting for the Discontinuation of Application of FASB Statement
No. 71 (SFAS No. 101), as interpreted by Emerging Issues Task Force 97-4,
Deregulation of the Pricing of Electricity Issues Related to the Application of
FASB Statements No. 71 and 101. Under SFAS No. 101, the regulatory assets and
liabilities of the generation portion of the Company are determined on the basis
of the source from which the regulated cash flows to realize such regulatory
assets and settle such liabilities will be derived. Pursuant to the PUC's final
restructuring order, certain of the Company's generation-related regulatory
assets will be recovered through a competitive transition charge (CTC) collected
in connection with providing transmission and distribution services (the
1
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electricity delivery business segment). The Company will continue to apply SFAS
No. 71 with respect to such assets. Fixed assets related to the generation
portion of the Company's business have been evaluated in accordance with SFAS
No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of
(SFAS No. 121). Applying SFAS No. 121 to the non-regulated generation assets, it
has been determined that the Company's generation assets are impaired. However,
pursuant to the PUC's final restructuring order, the Company will recover its
above-market investment in generation assets through the CTC. Under the
Company's plan to auction its generation assets (currently expected to close in
late 1999 or early 2000), the market value utilized by the PUC in determining
the value of the generation assets will be the net after-tax proceeds received
from the auction. Accordingly, the amount of book value authorized by the PUC to
be recovered has been reclassified on the consolidated balance sheet from
property, plant and equipment to transition costs, until the auction has been
completed and all approvals for the final CTC accounting have been granted. 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 to the Company, 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 19.)
Business Segments
Historically, Duquesne has been 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. This rate
was based on the Company's cost of service, which was designed to recover the
Company's operating expenses and investment in electric utility assets and to
provide a return on the investment. As a result of the Customer Choice Act,
generation of electricity will be deregulated and charged at a separate rate
from the delivery of electricity beginning in 1999 (five percent of customers
chose alternative generation suppliers in 1998). For the purposes of complying
with SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information" (SFAS No. 131), the Company is required to disclose information
about its business segments separately. Accordingly, the Company has used the
PUC-approved separate rates for 1999 to develop the financial information of the
business segments for the periods ended December 31, 1998, 1997 and 1996.
(Additional information regarding the Company's business segments is set forth
in "Results of Operations" on page 12 and "Business Segments and Related
Information," Note O to the consolidated financial statements on page 49.)
Property, Plant and Equipment (PP&E)
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Investment in PP&E and Accumulated Depreciation
The Company's total investment in PP&E and the related accumulated
depreciation balances for major classes of property at December 31, 1998 and
1997 are as follows:
PP&E and Related Accumulated Depreciation as of December 31,
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<TABLE>
<CAPTION>
(Thousands of Dollars)
1998 1997
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Accumulated Net Accumulated Net
Investment Depreciation Investment Investment Depreciation Investment
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<S> <C> <C> <C> <C> <C> <C>
Electric delivery $1,531,116 $ 522,531 $1,008,585 $1,528,128 $ 517,654 $1,010,474
Electric production 2,797,800 2,491,162(a) 306,638 2,528,927 1,187,001 1,341,926
Electric general 130,431 64,544 65,887 334,565 192,439 142,126
Capital leases 123,374 63,604 59,770 113,662 50,725 62,937
Other 301,417 25,487 275,930 119,846 14,975 104,871
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Total $4,884,138 $3,167,328 $1,716,810 $4,625,128 $1,962,794 $2,662,334
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(a) See "Restructuring Plan" discussion on page 19.
Electric delivery PP&E includes: (1) high voltage transmission wires used in
delivering electricity from the generating stations to substations; (2)
substations and transformers; (3) lower voltage distribution wires used in
delivering electricity to customers; and (4) related poles and equipment.
Electric production PP&E includes fossil and nuclear generating stations and, in
1998, an allocated portion of electric general PP&E. This allocation was done in
conjunction with the PUC restructuring order. Electric production accumulated
depreciation in 1998 reflects the write-down of production plant values to the
PUC-determined market value. (See "Restructuring Plan" discussion on page 19.)
Electric general PP&E includes internal telecommunication equipment, vehicles
and office equipment. The Company's capital leases are primarily associated with
leased nuclear fuel and, to a lesser extent, other electric plant. Other PP&E is
comprised of water systems, water treatment facilities, various buildings and
land, E-Fuel(R) facilities, landfill gas recovery equipment and other property
related to the Company's expanded business lines.
2
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Joint Interests in Generating Units
The Company has various contracts with subsidiaries of FirstEnergy (Ohio
Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating
Company (CEI) and The Toledo Edison Company), with respect to several jointly
owned/leased generating units, which include provisions for coordinated
maintenance responsibilities, limited and qualified mutual back-up in the event
of outages, and certain capacity and energy transactions.
In September 1995, the Company commenced arbitration against CEI, seeking
damages, termination of the operating agreement for Eastlake Unit 5 (Eastlake)
and partition of the parties' interests in Eastlake through a sale and division
of the proceeds. The arbitration demand alleged, among other things, the
improper allocation by CEI of fuel and related costs; the mismanagement of the
administration of the Saginaw coal contract in connection with the closing of
the Saginaw mine, which historically supplied coal to Eastlake; and the
concealment by CEI of material information. CEI also seeks monetary damages from
the Company for alleged unpaid joint costs in connection with the operation of
Eastlake. The Company removed the action to the United States District Court for
the Northern District of Ohio, Eastern Division, where it is now pending.
Pursuant to the agreement in principle regarding the power station exchange
between Duquesne and FirstEnergy, the parties jointly sought and received, on
October 26, 1998, a court order staying all proceedings pending execution of
definitive exchange agreements. The parties will now seek a further stay of
proceedings pending the closing of the exchange. (See "Power Station Exchange"
discussion on page 20.)
Joint Interests in Power Stations
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<TABLE>
<CAPTION>
Nuclear Power Stations Beaver Valley
--------------------- Perry
Unit 1 Unit 2 Unit 1
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<S> <C> <C> <C>
Duquesne *47.50% *13.74% (a) 13.74%
FirstEnergy 52.50% 86.26% *86.26%
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<TABLE>
<CAPTION> Bruce Mansfield
Fossil Power Stations Sammis ------------------------------------------------ Eastlake
Unit 7 Unit 1 Unit 2 Unit 3 Unit 5
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<S> <C> <C> <C> <C> <C>
Duquesne 31.20% 29.30% 8.00% 13.74% 31.20%
FirstEnergy *68.80% *70.70% *92.00% *86.26% *68.80%
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</TABLE>
*Denotes Operator
(a) In 1987, the Company sold and leased back its 13.74 percent interest in BV
Unit 2. The Company leased back its interest in the unit for a term of
29.5 years.
Employees
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At December 31, 1998, the Company had 3,986 employees. Duquesne had 1,521
employees in the electricity generation business segment, 1,258 in the
electricity delivery business segment and 582 in administration. AquaSource had
539 employees in the water and water service companies, and the other expanded
business lines had 86 employees. Duquesne is party to a labor contract expiring
in September 2001 with the International Brotherhood of Electrical Workers
(IBEW), which represents approximately 2,000 of Duquesne's employees. The
contract provides, among other things, employment security, income protection
and 3 percent annual wage increases through September 2000. Duquesne and the
IBEW have agreed on a package of additional benefits and protections for union
employees affected by the divestiture of generation assets. Any buyer of
generation assets currently owned by Duquesne will be required to offer work to
current IBEW employees on a seniority basis, recognize the IBEW as the exclusive
bargaining representative, establish comparable employee benefit plans, and
assume the current labor contract.
In connection with the anticipated divestiture, Duquesne has developed early
retirement programs and enhanced separation packages available for eligible IBEW
and management employees. Duquesne expects to recover related costs through the
divestiture proceeds.
Electric Utility Operations
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The Company anticipates divesting itself of its generation assets through the
auction and the power station exchange by early 2000 and, depending on the
regulatory approvals of the final agreements regarding the divestiture, expects
certain obligations related to the divested assets will be transferred to the
future owners.
The Company's fossil plants operated at an availability factor of 80 percent
in 1998 and 84 percent in 1997. The Company's nuclear plants operated at an
availability factor of 52 percent in 1998 and 68 percent in 1997. The next
refueling outage for BV Unit 1 is currently scheduled to begin in the spring of
2000. BV Unit 2 began a scheduled refueling outage on February 26, 1999. The
next refueling outage for Perry Unit 1 is scheduled to begin on March 27, 1999.
The timing and duration of scheduled maintenance and refueling outages, as well
as the duration of forced outages, affect the availability of power stations.
The Company normally experiences its peak demand in the summer. The 1998
customer system peak demand of 2,484 megawatts (MW) occurred on August 7, 1998.
3
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Beaver Valley Power Station (BVPS)
BV Unit 1 went off-line on January 30, 1998, due to an issue identified in a
technical review completed by the Company. BV Unit 2 went off-line on December
16, 1997, to repair the emergency air supply system to the control room. BV Unit
2 remained off-line due to other issues identified by a technical review,
similar to that performed at BV Unit 1. These technical reviews, held in
response to a 1997 commitment made by the Company to the NRC, have been
completed. The Company was one of many utilities faced with similar issues, some
of which date back to the initial start-up of BVPS. BV Unit 1 returned to
service on August 15, 1998, and BV Unit 2 returned to service on September 28,
1998.
BVPS's two units are equipped with steam generators designed and built by
Westinghouse Electric Corporation (Westinghouse). Similar to other Westinghouse
nuclear plants, outside diameter stress corrosion cracking (ODSCC) has occurred
in the steam generator tubes of both units. The units still have the capability
to operate at 100 percent reactor power, although approximately 17 percent of BV
Unit 1 and 3 percent of BV Unit 2 steam generator tubes have been removed from
service. Material acceleration in the rate of ODSCC could lead to a loss in
plant efficiency and significant repairs or replacement of BV Unit 1 steam
generators. The total replacement cost of the BV Unit 1 steam generators is
estimated at $125 million, $59 million of which would be the Company's
responsibility. The earliest that the BV Unit 1 steam generators could be
replaced during a currently scheduled refueling outage is the fall of 2001.
BV Unit 2, which was placed in service 11 years after BV Unit 1, has not yet
exhibited the degree of ODSCC experienced at BV Unit 1. It is too early in the
life of BV Unit 2 to determine the extent to which ODSCC may become a problem
at that unit.
Fossil Fuel
The Company believes that sufficient coal for its coal-fired generating units
will be available from various sources to satisfy its requirements for the
foreseeable future. During 1998, approximately 2.0 million tons of coal were
consumed at the Company's two wholly owned coal-fired stations, Cheswick Power
Station (Cheswick) and Elrama Power Station (Elrama).
The Company owns Warwick Mine, an underground mine located in southwestern
Pennsylvania. At December 31, 1998, the Company's net investment in the mine was
$4.4 million. The Company estimates that, at December 31, 1998, its economically
recoverable coal reserves at Warwick Mine were in excess of 1.4 million tons.
Commencing in 1997, an unaffiliated operator began producing up to 360,000 tons
of coal per year, for exclusive use at Elrama. This arrangement terminates in
March 2000. The Company purchases the remaining coal for use at Elrama on the
open market. The current estimated liability for mine closing, including final
site reclamation, mine water treatment and certain labor liabilities is
$47.6 million, and the Company has recorded a liability on the consolidated
balance sheet of approximately $39.9 million toward these costs. The remaining
$7.7 million will be charged to expense during 1999 and the first quarter of
2000.
During 1998, 48 percent of the Company's coal supplies were provided by
contracts, including Warwick Mine, with the remainder satisfied through
purchases on the spot market. The Company had three long-term contracts in
effect at December 31, 1998, that, in combination with spot market purchases,
are expected to furnish an adequate future coal supply. The Company does not
anticipate any difficulty in replacing or renewing these contracts as they
expire from 2000 through 2005. At December 31, 1998, the Company's wholly owned
generating units had on hand an average coal supply of 45 days.
Nuclear Fuel
The cycle of production and utilization of nuclear fuel consists of (1) mining
and milling of uranium ore and processing the ore into uranium concentrates, (2)
converting uranium concentrates to uranium hexafluoride, (3) enriching the
uranium hexafluoride, (4) fabricating fuel assemblies, (5) utilizing the nuclear
fuel in the generating station reactor, and (6) storing and disposing of spent
fuel.
An adequate supply of uranium is under contract to meet the Company's
requirements for its jointly owned/leased nuclear units through 2000. An
adequate supply of conversion services through the year 2002 is also under
contract. Enrichment services for the Company's joint interests in BV Units 1
and 2 and Perry Unit 1 will be supplied through fiscal year 1999 under a United
States Enrichment Corporation (USEC) Utility Services contract. The Company has
terminated, at zero cost, all of its enrichment services requirements under this
contract for the fiscal years 2000 through 2009 and is planning to secure
required enrichment services during this period from other suppliers. The
Company continues to review on an annual basis its alternatives for enrichment
services for the years 2010 through 2014 under the USEC contract and may
terminate these future years if it can arrange more cost-effective enrichment
services. Fuel fabrication contracts are in place to supply reload requirements
through 2005 and 2004 respectively, for BV Unit 1 and BV Unit 2, and for the
life of plant for Perry Unit 1. The Company will continue to make arrangements
for future uranium supply and related services, as required. (See "Nuclear Fuel
Leasing" discussion on page 18.)
4
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Nuclear Decommissioning
The Company expects to decommission BV Unit 1, BV Unit 2 and Perry Unit 1 no
earlier than the expiration of each plant's operating license in 2016, 2027 and
2026, respectively. At the end of its operating life, BV Unit 1 may be placed in
safe storage until BV Unit 2 is ready to be decommissioned, at which time the
units may be decommissioned together.
Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit 2,
and a 1997 update of the 1994 study for Perry Unit 1, the Company's approximate
share of the total estimated decommissioning costs, including removal and
decontamination costs, is $170 million, $55 million and $90 million,
respectively. The amount currently being used to determine the Company's cost of
service related to decommissioning all three nuclear units is $224 million.
Funding for nuclear decommissioning costs is deposited in external, segregated
trust accounts and invested in a portfolio of corporate common stock and debt
securities, municipal bonds, certificates of deposit and United States
government securities. The market value of the aggregate trust fund balances at
December 31, 1998, totaled approximately $62.7 million.
As part of the power station exchange, FirstEnergy has agreed to assume the
decommissioning liability for each of the nuclear plants in exchange for the
balance in the decommissioning trust funds, plus the decommissioning costs
expected to be collected through the CTC.
Nuclear Insurance
The Price-Anderson Amendments to the Atomic Energy Act of 1954 limit public
liability from a single incident at a nuclear plant to $9.8 billion. The maximum
available private primary insurance of $200 million has been purchased by the
Company. Additional protection of $9.6 billion would be provided by an
assessment of up to $88.1 million per incident on each licensed nuclear unit in
the United States. The Company's maximum total possible assessment, $66.1
million, which is based on its ownership or leasehold interests in three nuclear
generating units, would be limited to a maximum of $7.5 million per incident per
year. This assessment is subject to indexing for inflation and may be subject to
state premium taxes. If assessments from the nuclear industry prove insufficient
to pay claims, the United States Congress could impose other revenue-raising
measures on the industry.
The Company's share of insurance coverage for property damage, decommissioning
and decontamination liability is $1.2 billion. The Company would be responsible
for its share of any damages in excess of insurance coverage. In addition, if
the property damage reserves of Nuclear Electric Insurance Limited (NEIL), an
industry mutual insurance company that provides a portion of this coverage, are
inadequate to cover claims arising from an incident at any United States nuclear
site covered by that insurer, the Company could be assessed retrospective
premiums totaling a maximum of $7.3 million.
In addition, the Company participates in a NEIL program that provides
insurance for the increased cost of generation and/or purchased power resulting
from an accidental outage of a nuclear unit. Subject to the policy deductible,
terms and limit, the coverage provides for a weekly indemnity of the estimated
incremental costs during the three-year period starting 17 weeks after an
accident, with no coverage thereafter. If NEIL's losses for this program ever
exceed its reserves, the Company could be assessed retrospective premiums
totaling a maximum of $2.6 million.
Spent Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 established a federal policy for handling
and disposing of spent nuclear fuel and a policy requiring the establishment of
a final repository to accept spent nuclear fuel. Electric utility companies have
entered into contracts with the United States Department of Energy (DOE) for the
permanent disposal of spent nuclear fuel and high-level radioactive waste in
compliance with this legislation. The DOE has indicated that its repository
under these contracts will not be available for acceptance of spent nuclear fuel
before 2010. The DOE has not yet established an interim or permanent storage
facility, despite a ruling by the United States Court of Appeals for the
District of Columbia Circuit that the DOE was legally obligated to begin
acceptance of spent nuclear fuel for disposal by January 31, 1998. Existing
on-site spent nuclear fuel storage capacities at BV Unit 1, BV Unit 2 and Perry
Unit 1 are expected to be sufficient until 2018, 2012 and 2011, respectively.
In early 1997, the Company joined 35 other electric utilities and 46 states,
state agencies and regulatory commissions in filing suit in the United States
Court of Appeals for the District of Columbia Circuit against the DOE. The
parties requested the court to suspend the utilities' payments into the Nuclear
Waste Fund and to place future payments into an escrow account until the DOE
fulfills its obligation to accept spent nuclear fuel. The DOE had requested that
the court delay litigation while it pursued alternative dispute resolution under
the terms of its contracts with the utilities. The court ruling, issued November
14, 1997, and affirmed on rehearing May 5, 1998, denied the relief requested by
the utilities and states and permitted the DOE to pursue alternative dispute
resolution, but prohibited the DOE from using its lack of a spent fuel
repository as a defense. The United States Supreme Court declined to review the
decision. The utilities' remaining remedy is to sue the DOE in federal court for
money damages caused by the DOE's delay in fulfilling its obligations.
5
<PAGE>
Uranium Enrichment Obligations
Nuclear reactor licensees in the United States are assessed annually for the
decontamination and decommissioning of DOE uranium enrichment facilities.
Assessments are based on the amount of uranium a utility had processed for
enrichment prior to enactment of the National Energy Policy Act of 1992 and are
to be paid by such utilities over a 15-year period. At December 31, 1998, the
Company's liability for contributions was approximately $6.2 million (subject to
an inflation adjustment), which will be recovered through the CTC as part of
transition costs.
Environmental Matters
- --------------------------------------------------------------------------------
Various federal and state authorities regulate the Company with respect to air
and water quality and other environmental matters. The Company believes it is in
current compliance with all material applicable environmental regulations. As
discussed above, the Company anticipates divesting itself of its generation
assets, and expects that environmental obligations related to divested assets
will transfer to the new owners.
As required by Title V of the Clean Air Act Amendments (Clean Air Act), the
Company filed comprehensive air operating permit applications for Cheswick,
Elrama, BI and Phillips in 1995. Approval is still pending for these
applications. The Company filed its Title IV Phase II Clean Air Act compliance
plan with the PUC on December 27, 1995. The Company 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.
Approval is also pending for these applications.
Acid Rain Program Requirements. Although the Company believes it has
satisfied all of the Phase I Acid Rain Program requirements of the Clean Air
Act, the Phase II Acid Rain Program requires significant additional reductions
of sulfur dioxide (SO/2/) through the end of 2000. The Company currently has 662
MW of nuclear capacity and 887 MW of coal capacity equipped with SO/2/ emission-
reducing equipment. Through the year 2000, the Company will implement a
combination of compliance methods that include fuel switching; increased use of,
and improvements in, SO/2/ emission-reducing equipment; and the purchase of
emission allowances for those remaining stations where it is anticipated that
emissions will exceed allocated SO/2/ allowances.
The Company has developed, patented and installed low NO/X/ burner technology
for the Elrama boilers. These cost-effective NO/X/ reduction systems installed
on the Elrama roof-fired boilers were specified as the benchmark for the
industry for this class of boilers in the Environmental Protection Agency's
(EPA) final Group II rulemaking. In 1998, the Company 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, the Company is 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. The Company believes it will continue its current low NO/X/
emission levels under the maintenance plan being established by the DEP. The
Company further believes it 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 EPA issued additional ozone-related NO/X/ reduction
requirements under the Clean Air Act, which will affect the Company's power
plants and will supersede reduction levels specified for 2003 by the Ozone
Transport Commission control program. The EPA requires states in the northeast
and midwest to amend their implementation plans to impose NO/X/ allowance caps
on emissions during the May to September control period. Because the DEP has
only recently proposed implementation regulations, the costs of compliance
cannot be determined by the Company at this time. However, the Company
anticipates that compliance would require additional capital and operation costs
beyond those already estimated through 2000.
Future Air Quality Requirements. The Company is closely monitoring other
future air quality programs and air emission control requirements that could
result from more stringent ambient air quality and emission standards for SO/2/
and NO/X/ particulates and other by-products of coal combustion. In 1997, the
DEP finalized a regulation to implement additional NO/X/ control requirements
that were recommended by the Ozone Transport Commission. The estimated costs to
comply with this program have been included in the Company's capital cost
estimates through the year 2000. The Company currently estimates that additional
capital costs to comply with the Clean Air Act requirements through the year
2000 will be approximately $5 million. These capital costs may be reduced by
short term optimization of NO/X/ reduction systems and the purchase of NO/X/
emission allowances.
In July 1997, the EPA announced new national ambient air quality standards for
ozone and fine particulate matter. To allow each state time to determine which
areas may not meet the standards, and to adopt control strategies to achieve
compliance, the ozone standards will not be implemented until 2004, and the fine
particulate matter standards will not be implemented until 2007 or later.
Because appropriate state ambient air monitoring and implementation plans have
not been developed, the costs of compliance with these new standards cannot be
determined by the Company at this time.
6
<PAGE>
In December 1997, more than 160 nations reached a preliminary agreement (Kyoto
Protocol), under which, among other things, the United States would be required
to reduce its greenhouse gas emissions during the years 2008 through 2012. The
Kyoto Protocol has been signed by the Clinton administration. However, until the
Kyoto Protocol has been ratified by the Senate and the related greenhouse gas
reduction programs have been developed, the costs of compliance cannot be
determined by the Company at this time.
Other. In 1992, the DEP issued Residual Waste Management Regulations
governing the generation and management of non-hazardous residual waste, such as
coal ash. The Company is assessing the sites it utilizes and has developed
compliance strategies that are currently under review by the DEP. Capital costs
of $3.8 million were incurred by the Company in 1998 to comply with these DEP
regulations. Based on information currently available, approximately $4.5
million will be spent in 1999. The additional capital cost of compliance is
estimated, based on current information, to be approximately $4.8 million per
year for the next three years. This estimate is subject to the results of
groundwater assessments and DEP final approval of compliance plans.
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 is due July 1, 1999, to report on emissions and discharges
for 1998. Toxic release inventory reporting does not involve emission
reductions. The Company does not anticipate any material impact resulting from
this requirement.
The Comprehensive Environmental Response, Compensation and Liability Act of
1980 and the Superfund Amendments and Reauthorization Act of 1986 established a
variety of informational and environmental action programs. Through its
investment in GSF Energy (GSF), the Company indirectly became involved in three
hazardous waste sites. GSF was a minor contributor of materials to each site,
and other solvent potentially responsible parties are involved. GSF believes
that available defenses, along with its overall limited involvement, will limit
any potential liability it may have for clean-up costs. Additionally, as part of
the GSF investment the Company is indemnified for any costs that it may incur
related to these sites by at least one financially responsible party.
Accordingly, the Company believes that these matters will not have a material
adverse effect on its financial position, results of operations or cash flows.
The Company's water and water-related operations are subject to the federal
Safe Drinking Water Act, which provides for uniform minimum national water
quality standards, as well as governmental authority to specify treatment
processes to be used for drinking water. These operations are also subject to
the federal Clean Water Act, which regulates the discharge of pollutants into
waterways.
The Company is involved in various other environmental matters. The Company
believes that such matters, in total, will not have a materially adverse effect
on its financial position, results of operations or cash flows.
Other
- --------------------------------------------------------------------------------
Customer Advanced Reliability System
The Customer Advanced Reliability System (CARS) is a communications service
that provides the Company with an electronic link to its customers, including
the ability to read customer meters. During 1998, the Company's service contract
with Itron, Inc. was expanded to include additional advanced commercial and
industrial customer metering capabilities and associated software. Installation
of this advanced metering subsystem commenced in 1998 and will continue during
1999. As of December 31, 1998, the base CARS system had essentially been
completed, with nearly all residential meters adapted for CARS, and
approximately 470,000 meters being read daily.
Retirement Plan Measurement Assumptions
The Company decreased the discount rate used to determine the projected
benefit obligation on the Company's retirement plans at December 31, 1998, to
6.5 percent. The assumed change in compensation levels and the assumed rate of
return on plan assets were also decreased to reflect current market and economic
conditions. The effects of these changes on the Company's retirement plan
obligations are reflected in the amounts shown in "Employee Benefits," Note N to
the consolidated financial statements, on page 46. 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 (SFAS No. 133).
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.
The adoption of SFAS No. 133 is not expected to have a significant impact on the
Company's financial statements and disclosures.
------------------------------
Except for historical information contained herein, the matters discussed in
this Annual Report on Form 10-K are forward-looking statements which involve
risks and uncertainties including, but not limited to, economic, competitive,
governmental and technological factors affecting the Company's operations,
markets, products, services and prices and other factors discussed in the
Company's filings with the Securities and Exchange Commission.
7
<PAGE>
Executive Officers of the Registrant
- --------------------------------------------------------------------------------
Set forth below are the names, ages as of March 10, 1999, and positions during
the past five years of the executive officers of DQE. Additional information
related to the executive officers of DQE is set forth on page 20 of DQE's Annual
Report to Shareholders for the year ended December 31, 1998. The information is
incorporated here by reference.
<TABLE>
<CAPTION>
Name Age Office
<S> <C> <C>
David D. Marshall 46 President and Chief Executive Officer since August 1996.
Executive Vice President since February 1995. Vice
President from July 1989 to February 1995.
Victor A. Roque 52 Executive Vice President since November 1998 and
General Counsel since November 1994. Vice
President from April 1995 to November 1998.
Previously Vice President, General Counsel and
Secretary for Orange and Rockland Utilities from
April 1989 to November 1994.
Gary L. Schwass 53 Executive Vice President and Chief Financial
Officer since February 1995. Vice President from
January 1990 to February 1995 and Treasurer and
Principal Financial Officer from July 1989 to
September 1996.
William J. DeLeo 48 Vice President and Chief Administrative Officer
since November 1998. Vice President - Corporate
Services at Duquesne since November 1998. Vice
President - Marketing and Corporate Performance
at Duquesne from April 1995 to November 1998. Vice
President - Corporate Performance and Information
Services at Duquesne from January 1991 to April
1995.
James D. Mitchell 47 Vice President since February 1995. Assistant
Treasurer from January 1990 to February 1995.
Morgan K. O'Brien 38 Vice President since October 1997. Controller and
Principal Accounting Officer since October 1995, and
Treasurer since November 1998. Assistant Controller
from December 1993 to October 1995.
Jack E. Saxer, Jr. 55 Vice President since April 1996. Assistant Vice
President - Administration of Duquesne Light
Company since January 1995, and General
Manager - Pension, Investments and Insurance
from January 1989 to January 1995.
</TABLE>
8
<PAGE>
Item 2. Properties.
The principal properties of the Company 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 Company's electric utility properties are
subject to a first mortgage lien.
The Company owns all or a portion of the following generating units except
Beaver Valley Unit 2, which is leased. These units are used in the electricity
generation business segment. The Company anticipates divesting itself of these
units through the auction and the power station exchange by early 2000. (See
"Restructuring Plan" discussion on page 19.)
<TABLE>
<CAPTION>
Company's
Share of Plant Output
Capacity Year Ended
(Megawatts) December 31, 1998
Name and Location Type Summer Winter (Megawatt-hours)
----------------- ---- ------- ------ ----------------
<S> <C> <C> <C> <C>
Cheswick Coal 562 570 2,294,365
Springdale, Pa.
Elrama Coal 474 487 2,326,506
Elrama, Pa.
Sammis Unit 7 (1) Coal 187 187 1,363,910
Stratton, Ohio
Eastlake Unit 5 (1) Coal 186 186 989,035
Eastlake, Ohio
Beaver Valley Unit 1 (1) Nuclear 385 385 1,328,159
Shippingport, Pa.
Beaver Valley Unit 2 (1) Nuclear 113 113 244,879
Shippingport, Pa.
Perry Unit 1 (1) Nuclear 161 164 1,400,345
North Perry, Ohio
Bruce Mansfield Unit 1 (1) Coal 228 228 1,344,605
Shippingport, Pa.
Bruce Mansfield Unit 2 (1) Coal 62 62 287,293
Shippingport, Pa.
Bruce Mansfield Unit 3 (1) Coal 110 110 604,720
Shippingport, Pa.
Brunot Island Oil 166 178 5,740
Brunot Island, Pa. ----- ----- ----------
Total 2,634 2,670 12,189,557
===== ===== ==========
</TABLE>
(1) Amounts represent the Company's share of the unit, which is owned by the
Company in common with one or more other electric utilities (or, in the case
of Beaver Valley Unit 2, leased by the Company).
The Company owns 24 transmission substations (including interests in common in
the step-up transformers at Sammis Unit 7; Eastlake Unit 5; Bruce Mansfield Unit
1; Beaver Valley Unit 1; Beaver Valley Unit 2; Perry Unit 1; Bruce Mansfield
Unit 2; and Bruce Mansfield Unit 3) and 562 distribution substations. The
Company has 714 circuit-miles of transmission lines, comprising 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 cables. These
facilities are used in the electricity delivery business segment.
The Company owns 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. (See "Fossil Fuel" discussion on page 4.) This property is
used in the electricity generation business segment.
The Company owns three office buildings in Pennsylvania: the corporate
headquarters at 500 Cherrington Parkway in Coraopolis; Duquesne's headquarters
at 411 Seventh Avenue in Pittsburgh; and One NorthShore Center, 15 Federal
Street in Pittsburgh. The Company also owns the six E-Fuel(R) plants located in
Kentucky, North Carolina, Ohio, Pennsylvania, South Carolina, and Virginia.
Additional information relating to properties is set forth in "Property, Plant
and Equipment," Note C to the consolidated financial statements on page 33 of
this Report. The information is incorporated here by reference.
9
<PAGE>
Item 3. Legal Proceedings.
Eastlake Unit 5
In September 1995, the Company commenced arbitration against CEI, seeking
damages, termination of the operating agreement for Eastlake and partition of
the parties' interests in Eastlake through a sale and division of the proceeds.
The arbitration demand alleged, among other things, the improper allocation by
CEI of fuel and related costs; the mismanagement of the administration of the
Saginaw coal contract in connection with the closing of the Saginaw mine, which
historically supplied coal to Eastlake; and the concealment by CEI of material
information. CEI also seeks monetary damages from the Company for alleged unpaid
joint costs in connection with the operation of Eastlake. The Company removed
the action to the United States District Court for the Northern District of
Ohio, Eastern Division, where it is now pending. Pursuant to the agreement in
principle regarding the power station exchange between Duquesne and FirstEnergy,
the parties jointly sought and received, on October 26, 1998, a court order
staying all proceedings pending execution of definitive exchange agreements. The
parties will now seek a further stay of proceedings pending the closing of the
exchange. (See "Power Station Exchange" discussion on page 20.)
Termination of the AYE Merger
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement with AYE. More information regarding this termination is set
forth in the Company's Current Report on Form 8-K dated October 5, 1998. AYE
promptly filed suit in the United States District Court for the Western District
of Pennsylvania, seeking to compel the Company to proceed with the merger and
seeking a temporary restraining order and preliminary injunction to prevent the
Company from certain actions pending a trial, or in the alternative seeking an
unspecified amount of money damages. On October 28, 1998, the judge denied AYE's
motion for the temporary restraining order and preliminary injunction. AYE
appealed to the United States Court of Appeals for the Third Circuit, asking for
an injunction pending the appeal and expedited treatment of the appeal. On
November 6, 1998, the Third Circuit denied the motion for an injunction and
granted the motion to expedite the appeal.
On March 11, 1999, the Third Circuit vacated the October 28 denial of a
preliminary injunction. The Third Circuit remanded the case to the District
Court for further proceedings to address certain issues, including whether AYE
could demonstrate a reasonable likelihood of success on the merits, before
determining whether any injunctive relief is warranted. On March 12, 1999, AYE
filed a motion for a temporary restraining order with the district court, and a
hearing was held that same day. On March 16, 1999, AYE and DQE entered into a
consent agreement, which was approved by the district court on March 18.
Pursuant to the consent agreement, AYE and DQE have agreed, among other things,
that pending the consolidated hearing on AYE's application for a preliminary
injunction and/or an expedited trial on the merits, both parties will give each
other 10 business days' notice before taking or omitting to take any action
which would prevent the merger from qualifying for "pooling of interests"
accounting treatment. This would not prevent either party from entering into any
agreement, but would require the 10 business days' notice prior to closing any
transaction which prevents pooling. The consent agreement shall terminate on
September 16, 1999, unless earlier terminated or extended by mutual agreement or
an order of the district court.
The Company continues to believe that AYE's claim is entirely without merit in
light of the $1 billion disallowance of its stranded costs, which constituted a
material adverse effect under the merger agreement and entitled the Company to
terminate it as of October 5, 1998. The Company will continue to defend itself
vigorously against AYE's claims and intends to pursue a prompt resolution of the
litigation. On March 25, 1999, the Company petitioned the Third Circuit for
rehearing. The ultimate outcome of this suit cannot be determined at this time.
Proceedings involving the Company's rates are reported in Item 7 under "Rate
Matters."
10
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders.
a. On November 24, 1998, DQE held its 1998 Annual Meeting of Stockholders.
b. Proxies for the Annual Meeting were solicited pursuant to Regulation 14A
under the Securities and Exchange Act of 1934, as amended. There was no
solicitation in opposition to management's nominees for directors as
listed in the proxy statement dated October 9, 1998, and all nominees were
elected.
c. Two proposals were submitted to stockholders for a vote at the Annual
Meeting.
Proposal 1 was the election of two directors to the Board of Directors to serve
until the 2001 Annual Meeting and until their respective successors have been
chosen and qualified. The vote on this proposal was as follows:
<TABLE>
<CAPTION>
Broker
Nominee Type of Stock For Withheld Non-Votes
------- ------------- --- -------- --------
<S> <C> <C> <C> <C>
Doreen E. Boyce Common 64,740,858 555,049 2,439,219
Preferred 747,150 -- --
David D. Marshall Common 64,958,414 555,049 2,439,219
Preferred 747,150 -- --
</TABLE>
The following Directors' terms continue after the Annual Meeting of
Stockholders: until 1999 - Sigo Falk and Eric W. Springer; until 2000 - Daniel
Berg, Robert P. Bozzone, William H. Knoell and Thomas J. Murrin.
Proposal 2 was the ratification of the appointment, by the Board of Directors,
of Deloitte & Touche LLP as independent public accountants to audit the books of
the Company for the year ending December 31, 1998. The vote on this proposal was
as follows:
<TABLE>
<CAPTION>
Broker
Type of Stock For Against Non-Votes Abstain
- -------------- ---- ------- --------- -------
<S> <C> <C> <C> <C>
Common 64,736,283 285,747 2,435,293 426,833
Preferred 747,150 -- -- --
</TABLE>
Part II
Item 5. Market for Registrant's Common Equity and Related Shareholder Matters.
Information relating to the market for DQE's Common Stock and other matters
related to its holders is set forth inside of the back cover of the DQE Annual
Report to Shareholders for the year ended December 31, 1998 and on page 46 in
Note M and page 51 in Note P hereto. The information is incorporated here by
reference. During 1998 and 1997, DQE declared quarterly dividends on its common
stock totaling $1.46 per share and $1.38 per share, respectively. At February
28, 1999, there were approximately 67,000 holders of record of the Common Stock
of DQE.
Item 6. Selected Financial Data.
Selected financial data for each year of the eleven-year period ended December
31, 1998, are set forth on pages 22 and 23 of the DQE Annual Report to
Shareholders for the year ended December 31, 1998. The information is
incorporated here by reference.
11
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.
Results of Operations
- --------------------------------------------------------------------------------
Overall Performance
1998 Compared to 1997
On May 29, 1998, the PUC issued its final order related to the Company's
restructuring plan. In the second quarter of 1998 the Company recorded an
extraordinary charge (Pennsylvania restructuring charge) against earnings for
$142.3 million ($82.5 million, net of tax) for the generation-related stranded
costs not considered by the PUC's restructuring order to be recoverable from
customers. The Pennsylvania restructuring charge included Phillips Power Station
(Phillips), Brunot Island Power Station (BI), deferred caretaker costs related
to the two stations, and deferred coal costs. The charge resulted in a reduction
of Duquesne's contribution to the Company's earnings per share by $1.06. (See
"Rate Matters" on page 19.)
The Company's earnings per share in 1998 were $2.52, excluding the
Pennsylvania restructuring charge, compared to $2.57 in 1997, resulting in a
decrease of $0.05 per share or 1.9 percent. Earnings available for common stock
were $195.8 million in 1998, excluding the Pennsylvania restructuring charge,
compared to $199.1 million in 1997, resulting in a decrease of $3.3 million or
1.7 percent. The decrease in earnings available for common stock can be
primarily attributed to the gains recorded on the sale of Chester Engineers
(Chester) and of Exide Electronics Group, Inc. (Exide) stock in 1997, which
together contributed $0.17 to earnings per share. Excluding these gains, the
resulting increase to earnings per share of $0.12 in 1998 is primarily the
result of income attributable to the increased level of long-term investments
made late in 1997 and throughout 1998 through the expanded business lines.
1997 Compared to 1996
The Company's earnings per share in 1997 of $2.57 increased by $0.25 or 10.8
percent, compared to earnings per share of $2.32 in 1996. Earnings for common
stock were $199.1 million in 1997 compared to $179.1 million in 1996, an
increase of $20.0 million or 11.2 percent. The sale of Chester and of Exide
stock in 1997 together contributed $0.17 to earnings per share, and an
additional $0.19 per share was earned by the expanded business lines, the result
of income attributable to the increased level of long-term investments. A
partial offset to these increases in net income in 1997 was an incremental $25
million of accelerated nuclear fixed asset recovery as detailed in Duquesne's
1996 PUC-approved mitigation plan.
Dividends
Once all dividends on DQE's Preferred Stock, Series A (Convertible), $100
liquidation preference per share (DQE Preferred Stock), have been paid,
dividends may be paid on the Company's common stock to the extent permitted by
law and as declared by the board of directors. However, payments of dividends on
Duquesne's common stock may be restricted by Duquesne's obligations to holders
of preferred and preference stock pursuant to Duquesne's Restated Articles of
Incorporation and by obligations of Duquesne's subsidiaries to holders of their
preferred securities. No dividends or distributions may be made on Duquesne's
common stock if Duquesne has not paid dividends or sinking fund obligations on
its preferred or preference stock. Further, the aggregate amount of Duquesne's
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. As all of Duquesne's
common stock is owned by DQE, to the extent that Duquesne cannot pay common
dividends, the Company may not be able to pay dividends on its common stock or
DQE Preferred Stock.
The Company has continuously paid dividends on common stock since 1953. The
Company's annualized dividends per share were $1.52, $1.44, and $1.36 at
December 31, 1998, 1997 and 1996. During 1998, the Company paid a quarterly
dividend of $0.36 per share on each of January 1, April 1, July 1 and October 1.
The quarterly dividend declared in the fourth quarter of 1998 was increased from
$0.36 to $0.38 per share payable January 1, 1999. The Company expects that funds
generated from operations will continue to be sufficient to pay dividends. The
Company's need for and the availability of funds will be influenced by, among
other things: new investment opportunities; the economic activity within the
Company's utility service territory; competitive and environmental legislation;
the results of the anticipated divestiture; and regulatory matters experienced
by the electric utility industry generally, more specifically the transition to
competition in Pennsylvania. (See "Rate Matters" on page 19.) The Company's
stock price was $43 15/16 at the end of 1998.
12
<PAGE>
Results of Business Segments
Beginning in 1999, the Company will have two principal business segments:
(1) the transmission and distribution by Duquesne of electricity (electricity
delivery business segment) and (2) the generation by Duquesne of electricity and
collection of the CTC (electricity generation business segment). To comply with
SFAS No. 131, the Company has reported the results for 1998, 1997 and 1996 by
these business segments and an "all other" category. The all other category
includes the Company's expanded business lines and Duquesne investments. These
expanded business lines include water utilities, energy products and services,
and other activities. Intercompany transactions primarily relate to sales of
electricity, property rental, management fees and dividends. Upon the
anticipated completion of the auction of the Company's generation assets and
provider of last resort services, the electricity generation business segment
will be comprised solely of the collection of the CTC.
1998 Compared to 1997
Electricity Delivery Business Segment. The electricity delivery business
segment contributed $57.2 million to net income in 1998 compared to $61.9
million in 1997, a decrease of $4.7 million or 7.7 percent. Operating revenues
for this business segment are primarily derived from the Company's 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 are also affected
by regional development. Sales to industrial customers are influenced by
national and global economic conditions.
Operating revenues increased by $4.5 million or 1.4 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 kilowatt-hours
(KWH) delivered to electric utility customers.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------
KWH Delivered
------------------------------
(In Thousands)
------------------------------
1998 1997 Change
- ----------------------------------------------------------------------
<S> <C> <C> <C>
Residential 3,382,323 3,273,532 3.3 %
Commercial 5,896,036 5,785,745 1.9 %
Industrial 3,411,648 3,501,107 (2.6)%
- --------------------------------------------------------------
Sales to Electric Utility Customers 12,690,007 12,560,384 1.0 %
======================================================================
</TABLE>
Operating expenses for the electricity delivery business segment are
primarily made up of costs to operate and maintain the transmission and
distribution system; meter reading and billing costs; customer service;
collection; administrative expenses; and non-income taxes, such as property and
payroll taxes. Operating expenses increased $9.9 million or 7.2 percent from
1997, primarily as a result of higher costs of maintenance of the transmission
and distribution system, and start-up costs related to the Customer Advanced
Reliability System, including electronic meter reading and installation. The
increase in the system maintenance was primarily due to the increase in
frequency and severity of storms during 1998.
Depreciation and amortization expense increased $1.7 million or 3.8 percent
in 1998 due to additions to the plant and equipment balance throughout the year
partially offset by retirements.
Other income is primarily comprised of interest and dividend income. A
decrease of $1.6 million or 22.8 percent was the result of lower interest income
from a smaller amount of cash available for investing compared to the prior
year.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. 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.
Decreased taxable income during 1998 resulted in lower income taxes by $3.1
million or 7.6 percent.
Electricity Generation Business Segment. In 1998, the electricity generation
business segment reported net income of $71.9 million, excluding the
Pennsylvania restructuring charge, compared to $60.5 million in 1997, an
increase of $11.4 million or 18.8 percent.
For the electricity generation business segment, operating revenues are
primarily derived from the Company's supply of electricity for delivery to
retail customers and the supply of electricity to wholesale customers. Beginning
in 1999, revenues will include the recovery of transition costs through the
collection of the CTC. Under prior fuel cost recovery provisions, fuel revenues
generally equaled fuel expense, as costs were recoverable from customers through
the Energy
13
<PAGE>
Cost Rate Adjustment Clause (ECR), including the fuel component of purchased
power, and did not affect net income. Beginning May 29, 1998 (the date of the
PUC's final restructuring order), fuel costs were expensed as incurred, and had
an impact on net income to the extent fuel costs exceeded amounts included in
Duquesne's authorized generation rates. (See "Rate Matters" on page 19.)
Energy requirements for 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 energy
requirements are also affected by regional development. Energy requirements for
industrial customers are 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 the Company's customer
energy requirements, the energy market and transmission conditions, and the
availability of the Company's generating stations. Future levels of short-term
sales to other utilities will be affected by market rates, the level of
participation in customer choice, the Company's decision to sell 600 MW to
licensed generation suppliers and the Company's divestiture of its generation
assets. (See "Rate Matters" on page 19.)
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 participation in the customer
choice pilot program, 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 the customer choice pilot program. The following table sets forth KWH
supplied for customers who have not chosen an alternative generation supplier.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
KWH Supplied
---------------------------------
(In Thousands)
---------------------------------
1998 1997 Change
- --------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 3,190,451 3,267,941 (2.4)%
Commercial 5,579,888 5,777,750 (3.4)%
Industrial 3,357,371 3,499,699 (4.1)%
- ----------------------------------------------------------------
Sales to Electric Utility Customers 12,127,710 12,545,390 (3.3)%
- ----------------------------------------------------------------
Sales to Other Utilities 1,909,342 1,444,822 32.2 %
- ----------------------------------------------------------------
Total Sales 14,037,052 13,990,212 0.3 %
==========================================================================
</TABLE>
Operating expenses for the electricity generation business segment are
primarily made up of energy costs; costs to operate and maintain the power
stations; administrative expenses; and non-income taxes, such as property and
payroll taxes.
Fluctuations in energy costs generally result from changes in the cost of
fuel, the mix between coal and nuclear generation, total KWH supplied, and
generating station availability. Because of the ECR, changes in fuel and
purchased power costs did not impact earnings for the first five months of 1998
or any of 1997 or 1996. Beginning May 29, 1998, fuel costs for customers were
expensed as incurred, and had an impact on net income to the extent fuel costs
exceeded amounts included in Duquesne's authorized generation rates. (See "Rate
Matters" on page 19.)
Operating expenses increased $14.4 million or 2.8 percent from 1997 as a
result of increased energy costs, partially offset by decreased maintenance
costs and reduced BV Unit 2 lease costs due to the PUC's final restructuring
order.
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 the Company to purchase power and generate power from the higher
fuel cost fossil stations. (See "Beaver Valley Power Station" discussion on page
4.)
Maintenance expense decreased in 1998, primarily related to the reversal of
fossil station maintenance outage accruals for outages scheduled after the
Company's planned divestiture of generation. (See "Rate Matters" on page 19.) A
reduction in nuclear station outage cost amortization in 1998 also contributed
to the decrease in maintenance expense.
Depreciation and amortization expense includes the depreciation of the power
stations' plant and equipment and accrued nuclear decommissioning costs. A
decrease of $32.3 million or 16.8 percent compared to 1997 was the result of
reduced depreciation of generation assets in accordance with the PUC's final
restructuring order. Beginning in 1999, the Company will be recovering its
$2,133 million ($1,485 million, net of tax) of transition costs, as may be
adjusted to account for the proceeds of the generation asset auction, through
the CTC and will reflect amortization expense related to this recovery.
Other income is primarily comprised of interest and dividend income. A
decrease of $3.7 million or 29.1 percent was the result of lower interest
income, due to a smaller amount of cash available for investing compared to the
prior year.
14
<PAGE>
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In 1998 there was a $5.2
million or 8.1 percent reduction in interest and other charges 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.
Increased taxable income during 1998 resulted in higher income tax expense
by $4.4 million or 13.5 percent.
All Other. The all other category contributed $69.0 million to net income in
1998 compared to $78.1 million in 1997, a decrease of $9.1 million or 11.6
percent.
Operating revenues primarily include revenues from operating activities of
the expanded business lines. Operating revenues increased in 1998 by $41.7
million or 64.3 percent compared to 1997. This increase was primarily the result
of increased revenues from AquaSource and other new investments through the
operating activities of the expanded business lines, partially offset by the
loss of operating revenues from the sale of Chester in the second quarter of
1997.
Operating expenses include expenses from operating activities of the
expanded business lines and Duquesne investments. In 1998, operating expenses
increased $51.1 million or 81.4 percent over 1997. The growth of the expanded
business lines' start-up and developmental activities and acquisitions accounted
for most of the increase. Also, in the third quarter of 1998 the Company wrote
off costs related to the failed merger with Allegheny Energy, Inc. (AYE),
resulting in an increase to other operating expenses of $14.1 million. (See
"Rate Matters" on page 19.) Offsetting in part the increases to operating
expenses was the 1997 sale of Chester, which resulted in reduced operating costs
of $7.8 million and the recognition of the favorable resolution of certain
associated contingencies in 1998.
Depreciation and amortization expense primarily includes the depreciation of
plant and equipment of the expanded business lines and amortization of certain
investments. In 1998, depreciation and amortization expense increased by
$4.9 million or 107.1 percent, primarily due to the acquisition of water and
water-related companies by AquaSource during 1997 and throughout 1998.
Other income primarily includes long-term investment income, and interest
and dividend income related to the expanded business lines and Duquesne
investments. Other income in 1998 was $9.7 million or 8.1 percent higher than in
1997. This increase was the result of new investments made by the expanded
business lines during late 1997 and throughout 1998, and a new investment made
at Duquesne in the fourth quarter of 1997. Partially offsetting the increase
were the gains on the sale of Chester and of Exide stock in 1997 of
approximately $23 million ($13 million, net of tax), net of costs of the sale
and reserves for contingencies realized for the sale of Chester.
Interest and other charges are made up of interest on long-term debt, other
interest and preferred stock dividends of the expanded business lines, and
Duquesne investments. An increase of $0.6 million or 4.5 percent in 1998 was the
result of higher long-term debt interest expense, primarily related to
AquaSource debt assumptions associated with the acquisition of certain water and
water service companies.
Higher income tax expense of $3.8 million or 15.6 percent in 1998 can be
attributed to the increase in taxable income.
1997 Compared to 1996
Electricity Delivery Business Segment. The electricity delivery business
segment contributed $61.9 million to net income in 1997 compared to $56.6
million in 1996, an increase of $5.3 million or 9.4 percent.
Operating revenues increased by $8.1 million or 2.6 percent compared to
1996, due to an increase in sales to electric utility customers of 1.1 percent
in 1997 and a settlement for pole rental revenue in 1997. Sales to electric
utility customers increased despite 1997's mild temperatures compared to 1996
primarily as a result of stronger industrial sales. The following table sets
forth KWH delivered for electric utility customers.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------
KWH Delivered
-----------------------------
(In Thousands)
-----------------------------
1997 1996 Change
- -----------------------------------------------------------------------
<S> <C> <C> <C>
Residential 3,273,532 3,320,870 (1.4)%
Commercial 5,785,745 5,820,585 (0.6)%
Industrial 3,501,107 3,284,986 6.6 %
- --------------------------------------------------------------
Sales to Electric Utility Customers 12,560,384 12,426,441 1.1 %
=======================================================================
</TABLE>
Operating expenses decreased $1.0 million or 0.7 percent from 1996, as a
result of small decreases in operating and maintenance costs of the transmission
and distribution system.
Depreciation and amortization expense increased $0.2 million or 0.5 percent
in 1997 due to additions to the plant and equipment balance throughout the year,
which were partially offset by retirements.
Other income increased $1.6 million or 31.4 percent and was the result of
higher interest income from a larger amount of cash available for investing
compared to 1996.
15
<PAGE>
In 1997, there was a $1.4 million or 3.8 percent increase in interest and
other charges compared to 1996. This increase was the result of paying a full
year of dividends in 1997 related to the Monthly Income Preferred Securities
(MIPS) issued in May 1996.
Increased taxable income during 1997 resulted in higher income tax expense
by $3.8 million or 10.3 percent.
Electricity Generation Business Segment. In 1997, the electricity generation
business segment reported net income of $60.5 million compared to $77.6 million
in 1996, a decrease of $17.0 million or 22.0 percent.
Operating revenues decreased by $19.6 million or 2.2 percent compared to
1996, due to a decrease in energy supplied to other utilities of 56.4 percent in
1997. This decrease was due to reduced availability resulting from the sale of
the Ft. Martin Power Station in the fourth quarter of 1996 and increased forced
outages. Partially offsetting the decrease in energy supplied to other utilities
was a $3.2 million increase related to charges to the other BVPS owners for
administrative costs. The following table sets forth KWH supplied for customers
who have not chosen an alternative generation supplier.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
KWH Supplied
----------------------------------
(In Thousands)
----------------------------------
1997 1996 Change
- --------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 3,267,941 3,320,870 (1.6)%
Commercial 5,777,750 5,820,585 (0.7)%
Industrial 3,499,699 3,284,986 6.5 %
- ----------------------------------------------------------------
Sales to Electric Utility Customers 12,545,390 12,426,441 1.0 %
- ----------------------------------------------------------------
Sales to Other Utilities 1,444,822 3,310,206 (56.4)%
- ----------------------------------------------------------------
Total Sales 13,990,212 15,736,647 (11.1)%
==========================================================================
</TABLE>
Operating expenses decreased $9.7 million or 1.8 percent from 1996, as a
result of decreased energy volume supplied partially offset by increased
maintenance costs.
In 1997, fuel and purchased power expense decreased by $13.5 million or 5.7
percent compared to 1996, as a result of an 11.1 percent reduction in energy
volume supplied. This $26.7 million decrease due to energy volume supplied was
partially offset by increased energy costs of $13.2 million, primarily the
result of purchased power prices. Reduced availability of generating stations
due to an increase in outage hours forced the Company to purchase power during
high demand periods, resulting in increased costs.
Maintenance expense increased in 1997 compared to 1996. The increase was due
to more forced outage hours at nuclear stations than during 1996.
An increase in depreciation and amortization expense of $19.7 million or
11.4 percent over 1996 was due to the May 1, 1996, increase in the Company's
nuclear generation plant depreciation rate resulting in higher depreciation for
the first four months of 1997. In addition, accelerated nuclear lease recovery,
which began on May 1, 1997, resulted in higher annualized amortization expense
of $25 million. Offsetting these increases by $8.5 million was the mid-1996
completion of the recovery of the investment in Perry Unit 2, the construction
of which was abandoned by the Company in 1986. The remaining increase can be
attributed to incremental depreciation for 1997 fixed asset additions and an
increased level of nuclear decommissioning cost recognition.
Other income increased $2.9 million or 29.7 percent and was the result of
higher interest income, due to a larger amount of cash available for investing
compared to the prior year.
In 1997 there was a $0.4 million or 0.7 percent increase in interest and
other charges compared to 1996. The increase was the result of paying a full
year of dividends in 1997 related to the MIPS issued in May 1996.
Decreased taxable income during 1997 resulted in lower income tax expense by
$10.1 million or 23.9 percent.
All Other. The all other category contributed $78.1 million to net income in
1997 compared to $48.7 million in 1996, an increase of $29.4 million or 60.4
percent.
Operating revenues increased in 1997 by $5.9 million or 10.0 percent
compared to 1996. The increase resulted primarily from a $20.4 million increase
in revenues from a landfill gas recovery investment made in the fourth quarter
of 1996 and growth in the operating activities of the expanded business lines.
Partially offsetting the increase in revenues was the sale of Chester in the
second quarter of 1997, which decreased revenues by approximately $20 million.
In 1997 operating expenses increased $8.3 million or 15.2 percent over 1996.
The increase is attributable to operating costs from a landfill gas recovery
investment made during 1996 and the growth of the expanded business lines,
partially offset by the reduced operating costs associated with Chester during
the first half of 1997.
16
<PAGE>
Other income in 1997 was $48.0 million or 67.5 percent higher compared to
1996. The increase was the result of long-term investment income, gains on the
sale of Chester and of Exide stock, and interest and dividend income from a
higher level of short-term investments. The increase in long-term investment
income of approximately $15 million was the result of investments made during
1996 and 1997. The Company invested approximately $180 million in lease
investments in 1997. In the second quarter of 1997, Chester was sold for a pre-
tax gain of approximately $12 million, net of estimated costs of the sale. Also,
in the fourth quarter of 1997, the Company sold its investment in Exide stock
for a pre-tax gain of approximately $11 million.
An increase in interest and other charges of $3.0 million or 27.5 percent in
1997 compared to 1996 was the result of higher long-term debt interest expense
associated with higher average borrowings outstanding.
Higher income tax expense of $13.2 million or 117.7 percent in 1997 resulted
from an increase in taxable income.
Liquidity and Capital Resources
- --------------------------------------------------------------------------------
Capital Expenditures
The Company spent approximately $190.5 million in 1998, $116.0 million in 1997
and $101.2 million in 1996 for capital expenditures, of which $113.3 million in
1998, $90.4 million in 1997 and $87.9 million in 1996 was spent for electric
utility construction. The remaining capital expenditures were related to the
Company's expanded business lines and Duquesne investments. The Company's
capital expenditures for electric utility construction focus on improving and/or
expanding electric utility generation, transmission and distribution systems.
The Company currently estimates that it will spend, excluding allowance for
funds used during construction (AFC) and nuclear fuel, approximately $110
million during 1999 (including $30 million for generation), $75 million in 2000
(excluding generation) and $70 million in 2001 (excluding generation) for
electric utility construction.
In 1998 the Company completed construction of six plants to produce E-
Fuel(R), a coal-based synthetic fuel, at a cost of approximately $40 million.
All of these plants are currently in operation.
Long-Term Investments
The Company has made long-term investments in the following areas: leases,
affordable housing, gas reserves and energy solutions. Investing activities
during 1998 included approximately $22 million in affordable housing
partnerships, $22 million in natural gas reserves and the remaining $25 million
in the decommissioning trust fund and other investments. This $25 million
includes investments in BroadPoint Communications, Inc. BroadPoint has
introduced the FreeWay(TM) Service, in which customers earn free long-distance
telephone service in exchange for listening to short, targeted audio
advertisements. The Company also invested in North American Power Brokers, Inc.,
a provider of a low-bid, Internet auction-based approach to purchasing natural
gas and electricity through a secure website. Investing activities during 1997
included approximately $180 million in lease investments, $11 million in
landfill gas reserve investments, $16 million in affordable housing
partnerships, and $12 million in the decommissioning trust fund and other
investments. During 1997, the Company committed to approximately $5 million in
equity funding obligations for lease investments. Investing activities during
1996 included approximately $50 million in lease investments, $30 million in
gas reserve investments, $15 million in affordable housing partnerships, and
$6 million in energy solution and other investments. During 1996, the Company
also committed to approximately $37 million in equity funding obligations for
lease and affordable housing partnerships.
Acquisitions and Dispositions
In 1998, the Company issued 337,262 shares of DQE Preferred Stock,
representing an investment of approximately $34 million (out of a total
investment of approximately $156 million in stock and cash) in the acquisition
of water and water-related companies. The Company has invested approximately $35
million in stock and cash for additional water and water-related company
acquisitions through February 1999. The Company also invested $22 million to
acquire a 50 percent interest in and finance the growth of Control Solutions,
LLC, a commercial and industrial heating, ventilation and air conditioning
service and energy controls company.
Dispositions in 1998 related to assets acquired by the Company through
leasehold interest investments. Dispositions in 1997 related primarily to the
sale of Chester and of Exide stock. Dispositions in 1996 were comprised of long-
term leveraged lease assets totaling $18 million.
The Company is studying restructuring its current investment portfolio,
including the possible divestiture of its $131 million portfolio of affordable
housing investments.
Financing
The Company currently expects to meet its current obligations and debt
maturities through the year 2003 with funds generated from operations, through
new financings and through the proceeds from the auction of generation assets.
To the extent that acquisition and long-term investment opportunities prior to
the generation divestiture exceed current expectations, the Company may explore
various financing alternatives. At December 31, 1998, the Company was in
compliance with all of its debt covenants.
17
<PAGE>
During 1998, $75 million of mortgage bonds matured and were retired and $100
million of 8.75 percent mortgage bonds due in May 2022 were redeemed. The
retirement and redemption were financed using available cash, the proceeds of
the $40 million of 6.45 percent mortgage bonds due in February 2008 and the
proceeds of the $100 million of 7.375 percent mortgage bonds due in April 2038
issued by Duquesne. Mortgage bonds in the amount of $75 million will mature in
July 1999. The Company expects to retire these bonds with available cash, or to
refinance the bonds.
In connection with the investment in certain landfill gas property and
equipment during 1998, the Company issued a $25 million note maturing in 2019,
with an annual interest rate of 8.0 percent.
In connection with the power station exchange with FirstEnergy, the Company
anticipates terminating the BV Unit 2 lease, in which case the lease liability
recorded on the consolidated balance sheet would no longer be an obligation of
the Company. The underlying collateralized lease bonds ($371.0 million at
December 31, 1998) would become direct obligations of the Company and be
recorded on the consolidated balance sheet. The Company would also pay
approximately $230 million in termination costs, a portion of which the Company
expects to recover through the proceeds of the generation asset auction. (See
"Power Station Exchange" discussion on page 20.)
The Company has $150 million in bank term loans outstanding at December 31,
1998, with $65 million maturing in 2000 and $85 million maturing in 2001.
In July 1997, the Company authorized and registered 1,000,000 shares of the
DQE Preferred Stock, all with $100 liquidation preference, for use in connection
with acquisitions by the Company of other businesses, assets or securities.
Approximately $25 million in long-term debt has been assumed in connection with
these acquisitions. (See "Acquisitions and Dispositions" discussion on page 17.)
As of December 31, 1998, 352,742 shares of DQE Preferred Stock had been issued
and were outstanding. An additional 29,928 shares of DQE Preferred Stock were
issued in January and February 1999.
A Duquesne subsidiary has 15 shares of preferred stock, par value $100,000
per share outstanding. The holders of such shares are entitled to a 6.5 percent
annual dividend to be paid each September 30.
In May 1996, Duquesne Capital L.P. (Duquesne Capital), a special-purpose
limited partnership of which Duquesne is the sole general partner, issued $150.0
million principal amount of 8 3/8 percent MIPS with a stated liquidation value
of $25.00. The holders of MIPS are entitled to annual dividends of 8 3/8
percent, payable monthly. Such dividends are guaranteed by Duquesne.
The Company repurchased shares of its common stock on the open market late in
1998.
Short-Term Borrowings
At December 31, 1998, the Company had two extendible revolving credit
arrangements, including a $125 million facility expiring in June 1999 and a $150
million facility expiring in October 1999. Interest rates can, in accordance
with the option selected at the time of the borrowing, be based on prime,
Eurodollar or certificate of deposit rates. Commitment fees are based on the
unborrowed amount of the commitments. Both credit facilities contain two-year
repayment periods for any amounts outstanding at the expiration of the revolving
credit periods. At December 31, 1998 and December 31, 1997, there were no short-
term borrowings outstanding.
Sale of Accounts Receivable
The Company and an unaffiliated corporation have an agreement that entitles
the Company to sell, and the corporation to purchase, on an ongoing basis, up to
$50 million of accounts receivable. The Company had no receivables sold at
December 31, 1998 or December 31, 1997. The accounts receivable sales agreement,
which expires in June 1999, is one of many sources of funds available to the
Company. The Company may attempt to extend the agreement, replace it with a
similar facility, or eliminate it upon expiration.
Nuclear Fuel Leasing
The Company finances its acquisitions of nuclear fuel through a leasing
arrangement, under which it may finance up to $75 million of nuclear fuel. As of
December 31, 1998, the amount of nuclear fuel financed by the Company under this
arrangement totaled approximately $41.8 million. The actual nuclear fuel costs
to be financed will be influenced by such factors as changes in interest rates;
lengths of the respective fuel cycles; reload cycle design; operations; the
power station exchange; and changes in nuclear material costs and services, the
prices and availability of which are not known at this time. Such costs may also
be influenced by other events not presently foreseen. The Company plans to
continue leasing nuclear fuel to fulfill its requirements at least through
September 1999, the remaining term of the leasing arrangement. The Company may
attempt to extend the arrangement, replace it with a similar facility, or
eliminate it upon expiration through the purchase of the balance of the nuclear
fuel. The Company anticipates divesting its nuclear stations. (See "Power
Station Exchange" discussion on page 20.)
18
<PAGE>
Rate Matters
- --------------------------------------------------------------------------------
Competition and the Customer Choice Act
The electric utility industry continues to undergo fundamental change in
response to development of open transmission access and increased availability
of energy alternatives. Under historical 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 historical ratemaking process, utilities had assets recorded on their
balance sheets at above-market costs, thus creating transition and stranded
costs.
In Pennsylvania, the Customer Choice Act went into effect on January 1, 1997.
The Customer Choice Act enables Pennsylvania's electric utility customers to
purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act provides that the
existing franchised utility may recover, through a CTC, an amount of transition
costs that are determined by the PUC to be just and reasonable. Pennsylvania's
electric utility restructuring is being accomplished through a two-stage process
consisting of an initial customer choice pilot period (which ended in December
1998) and a phase-in to competition period (which began in January 1999). The
Company's estimated negative net income impact of the customer choice pilot
program during 1998, with five percent of customers participating, was
approximately $6 million.
Phase-In to Competition
The phase-in to competition began in January 1999, when 66 percent of
customers became eligible to participate in customer choice (including customers
covered by the pilot program); all customers will have customer choice in
January 2000. As of February 28, 1999, approximately 12.5 percent of the
Company's customers had chosen alternative generation suppliers. Customers that
have chosen an electricity generation supplier other than the Company pay that
supplier for generation charges, and pay the Company a CTC (discussed below) and
charges for transmission and distribution. Customers that continue to buy their
generation from the Company pay for their service at current regulated tariff
rates divided into generation, transmission and distribution charges. Under the
Customer Choice Act, an electric distribution company, such as Duquesne, remains
a regulated utility and may only offer PUC-approved rates, including generation
rates. Also under the Customer Choice Act, electricity delivery (including
transmission, distribution and customer service) remains regulated in
substantially the same manner as under current regulation.
In an effort to "jump start" retail competition, the Company has made 600 MW
of power available to licensed electric generation suppliers, to be used in
supplying electricity to Duquesne's customers who have chosen alternative
generation suppliers. The power will be available for the first six months of
1999 at a price of 2.6 cents per KWH. This power availability will be structured
to ensure the power is used to benefit Duquesne's retail customers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, has been
imposed on the transmission and distribution charges of Pennsylvania electric
utility companies under the Customer Choice Act. Additionally, electric utility
companies may not increase the generation price component of rates as long as
transition costs are being recovered, with certain exceptions.
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that the
Company should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The total of the transition costs to be recovered is
$2,133 million ($1,485 million, net of tax) over a seven-year period beginning
January 1, 1999, as may be adjusted to account for the proceeds of the
generation asset auction. In addition, the transition costs as reflected on the
consolidated balance sheet will be amortized over the same period that the CTC
revenues are being recognized. The Company will earn an 11 percent pre-tax
return on the unrecovered balance.
In the second quarter of 1998, the Company recorded an extraordinary charge
(PUC restructuring charge) against earnings of $142.3 million ($82.5 million,
net of tax) for the generation-related stranded costs not considered by the
PUC's restructuring order to be recoverable from customers. The Pennsylvania
restructuring charge included Phillips, BI, deferred caretaker costs related to
the two stations and deferred coal costs. The charge resulted in a reduction of
Duquesne's contribution to the Company's earnings per share by $1.06.
19
<PAGE>
Restructuring Plan and Auction Plan. With respect to transition cost
recovery, the PUC's final order on the restructuring plan approved Duquesne's
proposal to auction its generation assets and use the proceeds to offset
transition costs. The remaining balance of such costs (with certain exceptions
described below) will be recovered from ratepayers through a CTC, collectible
through 2005. Until the divestiture is complete, Duquesne has been ordered to
use an interim system average CTC and price to compare based on the methodology
approved in its pilot program (approximately 2.9 cents per KWH for the CTC and
approximately 3.8 cents per KWH for the price to compare).
On December 18, 1998, the PUC approved Duquesne's auction plan, including an
auction of its provider of last resort service, as well as an agreement in
principle to exchange certain generation assets with FirstEnergy. The assets to
be auctioned will include Duquesne's wholly owned Cheswick Power Station, Elrama
Power Station, Phillips and BI, as well as the stations to be received from
FirstEnergy in the power station exchange described below. The auction plan
calls for a two-phase, sealed bid process similar to that used in other power
plant divestitures. The initial confidential bidding process is expected to
begin in the spring of 1999, with potential buyers identified by Duquesne being
asked to submit non-binding bids. Final agreements governing the transactions
must be approved by various regulatory agencies, including the PUC, the FERC,
the NRC, the Department of Justice and/or the Federal Trade Commission. Duquesne
currently expects the sale to close at the end of 1999 or the beginning of
2000.
Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999 (which remain subject to regulatory approval), Duquesne and
FirstEnergy will exchange ownership interests in certain power stations.
Duquesne will receive 100 percent ownership rights in three coal-fired power
plants located in Avon Lake and Niles, Ohio and New Castle, Pennsylvania
(totaling approximately 1,300 MW), which the Company expects to sell
simultaneously as part of the auction of generation assets. FirstEnergy will
acquire Duquesne's interests in BV Unit 1, BV Unit 2, Perry Unit 1, Sammis
Unit 7, Eastlake Unit 5 and Bruce Mansfield Units 1, 2 and 3 (totaling
approximately 1,400 MW). In connection with the power station exchange, the
Company anticipates terminating the BV Unit 2 lease. (See "Financing" discussion
on page 17.) Pursuant to the December 18, 1998, PUC order and subject to final
approval, the proceeds from the sale of the power stations received in the
exchange will be used to offset the transition costs associated with Duquesne's
currently-held generation assets and the costs associated with completing the
exchange. Duquesne expects this exchange to enhance the value received from the
auction, because participants will bid on plants that are wholly owned by
Duquesne, rather than plants that are jointly owned and/or operated by another
entity. Additionally, the auction will include only coal- and oil-fired plants,
which are anticipated to have a higher market value than nuclear plants. These
value-enhancing features, along with a minimum level of auction proceeds
guaranteed by FirstEnergy, are expected to maximize auction proceeds, minimize
transition costs required to be recovered through the CTC (by shortening the
length of the CTC recovery period), and thus reduce customer bills as rapidly as
possible. Other benefits of this exchange include the resolution of all joint
ownership issues, and other risks and costs associated with the jointly-owned
units. Although the PUC has said the exchange appears to be in the public
interest, the definitive exchange agreement must be submitted for PUC approval,
and certain aspects of the exchange will have to be approved by, among other
agencies, the FERC, the NRC and the Department of Justice. The power station
exchange is expected to occur simultaneously with the anticipated closing of the
sale of Duquesne's generation through the auction at the end of 1999 or in early
2000.
Termination of the AYE Merger
On July 28, 1998, DQE's board of directors concluded that it could not
consummate the merger with AYE, toward which the Company had been working. The
Company 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. More information regarding this decision is set forth in the
Company's Current Report on Form 8-K dated July 28, 1998. On July 30, 1998, AYE
informed DQE that it would continue to work toward consummation of the merger,
and also pursue all remedies available to protect the legal and financial
interests of AYE and its shareholders.
On September 17, 1998, the PUC issued an order stating that, unless the
parties jointly agreed to an extension of time to consummate the merger beyond
October 5, 1998 (the relevant date under the merger agreement), their merger
application with the PUC would be considered withdrawn. On October 5, 1998, the
Company announced its unilateral termination of the merger agreement. More
information regarding this termination is set forth in the Company's Current
Report on Form 8-K dated October 5, 1998. In a letter dated February 24, 1999,
the PUC informed the Company that the merger application was deemed withdrawn
and the docket was closed.
AYE filed suit in the United States District Court for the Western District
of Pennsylvania, seeking to compel the Company to proceed with the merger and
seeking a temporary restraining order and preliminary injunction to prevent the
Company from certain actions pending a trial, or in the alternative seeking an
unspecified amount of money damages. On October 28, 1998, the judge denied AYE's
motion for the temporary restraining order and preliminary injunction. AYE
appealed to the United States Court of Appeals for the Third Circuit, asking for
an injunction pending the appeal and expedited treatment of the appeal. On
November 6, 1998, the Third Circuit denied the motion for an injunction and
granted the motion to expedite the appeal.
20
<PAGE>
On March 11, 1999, the Third Circuit vacated the October 28 denial of a
preliminary injunction. The Third Circuit remanded the case to the District
Court for further proceedings to address certain issues, including whether AYE
could demonstrate a reasonable likelihood of success on the merits, before
determining whether any injunctive relief is warranted. On March 12, 1999, AYE
filed a motion for a temporary restraining order with the district court, and a
hearing was held that same day. On March 16, 1999, AYE and DQE entered into a
consent agreement, which was approved by the district court on March 18.
Pursuant to the consent agreement, AYE and DQE have agreed, among other things,
that pending the consolidated hearing on AYE's application for a preliminary
injunction and/or an expedited trial on the merits, both parties will give each
other 10 business days' notice before taking or omitting to take any action
which would prevent the merger from qualifying for "pooling of interests"
accounting treatment. This would not prevent either party from entering into any
agreement, but would require the 10 business days' notice prior to closing any
transaction which prevents pooling. The consent agreement shall terminate on
September 16, 1999, unless earlier terminated or extended by mutual agreement or
an order of the district court.
The Company continues to believe that AYE's claim is entirely without merit
in light of the $1 billion disallowance of its stranded costs, which constituted
a material adverse effect under the merger agreement and entitled the Company to
terminate it as of October 5, 1998. The Company will continue to defend itself
vigorously against AYE's claims and intends to pursue a prompt resolution of the
litigation. On March 25, 1999, the Company petitioned the Third Circuit for
rehearing. In the interim, the Company intends to continue to pursue the
implementation of customer choice under its PUC-approved restructuring plan,
including the power station exchange with FirstEnergy and the generation asset
auction. The ultimate outcome of this suit cannot be determined at this time.
Deferred Energy Costs
As part of its restructuring plan filing, the Company 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. The Company also requested recovery of an
additional $31.2 million ($18.2 million, net of tax). This amount relates to
fuel costs that had been deferred between the time of the restructuring plan
filing and the restructuring order in accordance with a PUC order with respect
to the Company's ECR. As part of its December 18, 1998, order the PUC denied
recovery of this additional amount. The Company has appealed the PUC's denial of
recovery to the Pennsylvania Commonwealth Court.
Based upon the Customer Choice Act, which mandates recovery of all
regulatory assets, and the PUC's specific authorization for the Company to
create a regulatory asset for these costs, the Company believes that it is
probable that these costs will be recovered through retail rates. In the event
that the Company does not prevail in its appeal with the Pennsylvania
Commonwealth Court, these costs would be written off as a charge against
income.
Year 2000
- --------------------------------------------------------------------------------
Many existing computer programs and embedded microprocessors use only two
digits to identify a year (for example, "98" is used to represent "1998"). Such
programs read "00" as the year 1900, and thus may not recognize dates beginning
with the year 2000, or may otherwise produce erroneous results or cease
processing when dates after 1999 are encountered.
Year 2000 Plan. In 1994, the Company began reviewing its critical
information systems that impact operations and financial reporting in order to
develop a strategy to address required computer software and system changes and
upgrades. The Company has since assembled a Year 2000 team, comprised of
management representatives from all functional areas of the Company, which
continues to explore the exposure to Year 2000-related issues in computer
software and in devices and equipment (such as plant components, substations,
elevators, and heating and cooling systems) containing embedded microprocessors
that may not correctly identify the year. The team is also exploring potential
related issues that may originate with third parties with whom the Company does
business. To support the planning, organization and management of its efforts,
the team has retained Year 2000 consultants.
In general, the Company's overall strategy to address the Year 2000 issue is
comprised of four phases that, in some cases, are performed simultaneously.
These phases are: inventory, assessment, remediation, and testing and
implementation.
Inventory consists of identifying the various components, equipment,
hardware, and software used in the Company's operations that may potentially be
faced with Year 2000 issues. This inventory effort was completed during the
fourth quarter of 1998.
Assessment consists of evaluating all inventoried items for Year 2000
compliance or readiness. This is accomplished by contacting the vendors and
manufacturers, inspecting software and code, researching the results of other
companies' assessment of like components, and various other means. Assessment
activities have been completed as of the date of this Report. The Company's
business is dependent upon external suppliers for the reliable delivery of their
products and services. The Company has inquired in writing of its suppliers and
service providers with regard to their Year 2000 readiness. The Company is
meeting with critical suppliers and service providers to further corroborate
evidence of their Year 2000 readiness.
21
<PAGE>
Remediation refers to the activities necessary to fix or replace those
components that have Year 2000 issues that will adversely affect the Company's
operations. Remediation concentrates first on those systems, components, and
equipment that substantially impact the Company's ability to perform its
essential business functions (mission critical). Remediation is currently under
way and is scheduled to be substantially complete in the second quarter of 1999.
This remediation is in addition to previously planned improvements to the
Company's systems with benefits beyond Year 2000 solutions, such as total system
replacements discussed below.
Testing and implementation consists of placing renovated processes, systems,
equipment, and other items into use within the Company's operations. Testing is
performed on all mission critical processes, whether or not remediation
activities were involved in the process. Testing and implementation will be
substantially completed during the second quarter of 1999.
Throughout the execution of its Year 2000 plan, the Company has been
providing and will continue to provide information on its activities to the PUC,
the NRC and the North American Electric Reliability Counsel (NERC), which
coordinates the network of interconnected utilities across the nation. The
Company's plan is in accordance with NRC guidelines, and the Company is working
with the NRC to certify that its nuclear power station safety and operations
systems, and issues related to suppliers, will be ready for the Year 2000. NERC
has been requested by the United States Department of Energy (DOE) to review the
national electric power production and delivery infrastructure to ensure a
reliable power supply during the Year 2000 transition period. The Company is
working with NERC to address these issues through monthly status reporting and
participation in regional Year 2000 tests. The Company also participates in the
Electric Power Research Institute's project to share information about technical
issues regarding Year 2000 with other entities in the electric utility
industry.
Risks and Contingency Plans. The Company currently believes that
implementation of its plan will minimize the Year 2000 issues relating to its
systems and equipment. The Company's goal is to ensure that all components and
services that in any material manner contribute to operational reliability,
customer relations, safety, revenue and regulatory compliance will be suitable
for continued use beyond December 31, 1999, in some cases with appropriate work-
arounds or contingency plans. The Company understands that many variables
outside the control of the Company may have an adverse affect on the ability of
the Company to perform its mission critical processes (e.g.,telecommunication
providers may not be able to provide uninterrupted service). Therefore, the
Company is developing contingency plans for all mission critical processes in an
effort to mitigate these risks. Contingency plans will be developed and tested
for all mission critical processes by the end of the second quarter of 1999. The
Company continues to review its operations and its critical external suppliers
and service providers in order to determine any worst-case scenarios it could
face as a result of Year 2000 problems.
Costs. The estimated total cost of implementing the Company's Year 2000 plan
is approximately $49 million, which includes costs related to total system
replacements (the Year 2000 solution comprises only a portion of the benefit
resulting from such replacements). These costs to date, primarily incurred as a
result of software and system changes and upgrades by Duquesne, have been
approximately $39 million. Of this amount, approximately $35 million represents
capital costs attributable to the licensing and installation of new software for
total system replacements. The remaining $4 million has been expensed as
incurred. Funds for the Company's Year 2000 plan have come from the Company's
operating and capital budgets. Approximately $10 million has been budgeted for
1999 to address Year 2000 issues. The Company does not anticipate that Year 2000
issues and related costs will be material to the Company's operations, financial
condition and results of operations.
The foregoing paragraphs contain forward-looking statements regarding the
timetable, effectiveness and ultimate cost of the Company's Year 2000 strategy.
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
possibility that changes and upgrades are not timely completed, that corrections
to the systems of other companies on which the Company's systems rely may not be
timely completed, and that such changes and upgrades may be incompatible with
the Company's systems; the availability and cost of trained personnel; and the
ability to locate and correct all relevant computer code and microprocessors.
22
<PAGE>
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Market risk represents the risk of financial loss that may impact the
Company's consolidated financial position, results of operations or cash flows
due to adverse changes in market prices and rates.
Funding for nuclear decommissioning costs is deposited by the Company in
external, segregated trust accounts and invested in a portfolio of corporate
common stock and debt securities, municipal bonds, certificates of deposit and
United States government securities. The market value of the aggregate trust
fund balances at December 31, 1998 totaled approximately $62.7 million. The
amount funded into the trusts is based on estimated returns which, if not
achieved as projected, could require additional unanticipated funding
requirements.
23
<PAGE>
Item 8. Consolidated Financial Statements and Supplementary Data.
Report of Independent Certified Public Accountants
- --------------------------------------------------------------------------------
To the Directors and Shareholders of DQE, Inc.:
We have audited the accompanying consolidated balance sheets of DQE, Inc.
and its subsidiaries as of December 31, 1998 and 1997, 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, 1998.
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 the 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 signicant 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 DQE, Inc. and its
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998 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 herein.
/s/ Deloitte & Touche LLP
Pittsburgh, Pennsylvania
January 26, 1999
24
<PAGE>
Statement of Consolidated Income
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars, Except
Per Share Amounts)
----------------------------------------
Year Ended December 31,
----------------------------------------
1998 1997 1996
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues:
Sales of Electricity:
Residential $ 410,960 $ 405,915 $ 405,392
Commercial 490,009 494,834 489,646
Industrial 189,617 198,708 190,723
- -------------------------------------------------------------------------------------------
Total customer revenues 1,090,586 1,099,457 1,085,761
Utilities 36,203 24,861 58,292
- -------------------------------------------------------------------------------------------
Total Sales of Electricity 1,126,789 1,124,318 1,144,053
Other 142,809 105,856 92,724
- -------------------------------------------------------------------------------------------
Total Operating Revenues 1,269,598 1,230,174 1,236,777
- -------------------------------------------------------------------------------------------
Operating Expenses:
Fuel and purchased power 262,560 223,411 236,924
Other operating 361,790 317,747 309,559
Maintenance 74,908 82,869 78,386
Depreciation and amortization 217,156 242,843 222,928
Taxes other than income taxes 81,318 82,567 85,974
- -------------------------------------------------------------------------------------------
Total Operating Expenses 997,732 949,437 933,771
- -------------------------------------------------------------------------------------------
Operating Income 271,866 280,737 303,006
- -------------------------------------------------------------------------------------------
Other Income:
Long-term investment income 105,139 64,464 49,636
Gain on dispositions 6,809 34,364 5,119
Interest and other income 24,057 30,979 19,035
- -------------------------------------------------------------------------------------------
Total Other Income 136,005 129,807 73,790
- -------------------------------------------------------------------------------------------
Interest and Other Charges 110,201 115,638 110,270
- -------------------------------------------------------------------------------------------
Income Before Income Taxes and Extraordinary Item 297,670 294,906 266,526
- -------------------------------------------------------------------------------------------
Income Taxes 100,982 95,805 87,388
Income Before Extraordinary Item 196,688 199,101 179,138
Extraordinary Item, Net of Tax (82,548) -- --
Net Income, After Extraordinary Item 114,140 199,101 179,138
Dividends on Preferred Stock 866 -- --
Earnings Available for Common Stock $ 113,274 $ 199,101 $ 179,138
===========================================================================================
Average Number of Common Shares
Outstanding (Thousands of Shares) 77,683 77,492 77,349
===========================================================================================
Basic Earnings Per Share of Common Stock:
Before Extraordinary Item $ 2.52 $ 2.57 $ 2.32
===========================================================================================
Extraordinary Item $ (1.06) -- --
===========================================================================================
After Extraordinary Item $ 1.46 $ 2.57 $ 2.32
===========================================================================================
Diluted Earnings Per Share of Common Stock:
Before Extraordinary Item $ 2.48 $ 2.54 $ 2.29
===========================================================================================
Extraordinary Item $ (1.04) -- --
===========================================================================================
After Extraordinary Item $ 1.44 $ 2.54 $ 2.29
===========================================================================================
Dividends Declared Per Share of Common Stock $ 1.46 $ 1.38 $ 1.30
===========================================================================================
</TABLE>
See notes to consolidated financial statements.
25
<PAGE>
Consolidated Balance Sheet
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
--------------------------
As of December 31,
- -------------------------------------------------------------------------------
ASSETS 1998 1997
- -------------------------------------------------------------------------------
<S> <C> <C>
Current Assets:
Cash and temporary cash investments $ 108,790 $ 356,412
- -------------------------------------------------------------------------------
Receivables:
Electric customer accounts receivable 87,262 90,149
Water customer accounts receivable 10,591 471
Other utility receivables 25,412 23,106
Other receivables 51,944 33,001
Less: Allowance for uncollectible accounts (9,415) (15,016)
- -------------------------------------------------------------------------------
Total Receivables -- Net 165,794 131,711
- -------------------------------------------------------------------------------
Materials and supplies (at average cost):
Operating and construction 58,747 53,088
Coal 25,702 20,418
- -------------------------------------------------------------------------------
Total Materials and Supplies 84,449 73,506
- -------------------------------------------------------------------------------
Other current assets 15,719 7,727
- -------------------------------------------------------------------------------
Total Current Assets 374,752 569,356
- -------------------------------------------------------------------------------
Long-Term Investments:
Leveraged leases 388,113 349,129
Affordable housing 131,395 137,860
Gas reserves 103,270 92,645
Other leases 38,783 69,329
Other 98,877 73,823
- -------------------------------------------------------------------------------
Total Long-Term Investments 760,438 722,786
- -------------------------------------------------------------------------------
Property, Plant and Equipment:
Electric plant in service 4,379,703 4,335,149
Property held under capital leases 123,374 113,662
Construction work in progress 79,644 56,471
Other 301,417 119,846
- -------------------------------------------------------------------------------
Gross property, plant and equipment 4,884,138 4,625,128
Less: Accumulated depreciation and amortization (3,167,328) (1,962,794)
- -------------------------------------------------------------------------------
Total Property, Plant and Equipment -- Net 1,716,810 2,662,334
- -------------------------------------------------------------------------------
Other Non-Current Assets:
Transition costs 2,132,980 --
Regulatory assets 64,568 680,885
Other 198,015 59,041
- -------------------------------------------------------------------------------
Total Other Non-Current Assets 2,395,563 739,926
- -------------------------------------------------------------------------------
Total Assets $ 5,247,563 $ 4,694,402
===============================================================================
</TABLE>
See notes to consolidated financial statements.
26
<PAGE>
<TABLE>
<CAPTION>
(Thousands of Dollars)
------------------------
As of December 31,
------------------------
CAPITALIZATION AND LIABILITIES 1998 1997
- --------------------------------------------------------------------------------------------
<S> <C> <C>
Current Liabilities:
Accounts payable $ 121,100 $ 85,085
Current maturities and sinking fund requirements 100,822 97,844
Dividends declared 33,009 30,312
Accrued liabilities 87,944 79,949
Notes payable 4,525 --
Other 6,864 14,339
- --------------------------------------------------------------------------------------------
Total Current Liabilities 354,264 307,529
- --------------------------------------------------------------------------------------------
Non-Current Liabilities:
Deferred income taxes -- net 777,017 667,652
Beaver Valley lease liability 475,570 --
Deferred income 156,579 225,107
Capital lease obligations 36,596 37,540
Deferred investment tax credits 24,076 97,782
Other 310,981 255,467
- --------------------------------------------------------------------------------------------
Total Non-Current Liabilities 1,780,819 1,283,548
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes B through O)
- --------------------------------------------------------------------------------------------
Capitalization:
Long-Term Debt 1,364,879 1,376,121
- --------------------------------------------------------------------------------------------
Preferred and Preference Stock:
DQE preferred stock 35,274 1,548
Preferred stock of subsidiaries 215,608 214,608
Preference stock of subsidiaries 26,914 28,295
- --------------------------------------------------------------------------------------------
Total preferred and preference stock before deferred employee
stock ownership plan (ESOP) benefit 277,796 244,451
- --------------------------------------------------------------------------------------------
Deferred ESOP benefit (14,240) (16,400)
- --------------------------------------------------------------------------------------------
Total Preferred and Preference Stock 263,556 228,051
- --------------------------------------------------------------------------------------------
Common Shareholders' Equity:
Common stock -- no par value (authorized -- 187,500,000
shares; issued -- 109,679,154 shares) 994,996 996,508
Retained earnings 869,671 869,749
Treasury stock (at cost) (32,305,726 and 31,998,723 shares) (385,976) (371,821)
Accumulated other comprehensive income 5,354 4,717
- --------------------------------------------------------------------------------------------
Total Common Shareholders' Equity 1,484,045 1,499,153
- --------------------------------------------------------------------------------------------
Total Capitalization 3,112,480 3,103,325
- --------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $ 5,247,563 $ 4,694,402
============================================================================================
</TABLE>
See notes to consolidated financial statements.
27
<PAGE>
Statement of Consolidated Cash Flows
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
----------------------------------
Year Ended December 31,
----------------------------------
1998 1997 1996
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net income $ 114,140 $ 199,101 $ 179,138
Principal non-cash charges (credits) to net income:
Extraordinary item, net of tax 82,548 -- --
Depreciation and amortization 217,156 242,843 222,928
Deferred income and other taxes 119,945 60,811 (43,170)
Capital lease, nuclear fuel and investment amortization 80,574 67,671 53,166
Investment income (111,904) (66,246) (57,429)
Gain on disposition of investments (6,809) (34,364) (5,119)
Changes in working capital other than cash (36,995) (36,758) 2,915
Increase in ECR (19,219) (25,318) (3,948)
Other (78,479) (40,038) 34,445
- -------------------------------------------------------------------------------------------------------
Net Cash Provided from Operating Activities 360,957 367,702 382,926
- -------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Capital expenditures (190,548) (116,004) (101,150)
Acquisition of water companies (122,007) (6,611) --
Long-term investments (68,895) (219,122) (101,381)
Acquisition of Control Solutions (21,954) -- --
Proceeds from disposition of investments 6,809 86,300 18,100
Sale of generating station -- -- 169,100
Other (512) (1,132) (1,898)
- -------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (397,107) (256,569) (17,229)
- -------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Reductions of long-term obligations:
Long-term debt (198,272) (52,100) (50,812)
Capital leases (12,897) (13,551) (19,326)
Dividends on common and preferred stock (114,218) (106,959) (100,517)
Repurchase of common stock (14,155) (30) (11,717)
Increase (decrease) in notes payable 4,313 -- (28,637)
Issuance of long-term debt 140,000 -- 85,000
Issuance of subsidiary preferred stock -- -- 150,000
Other (16,243) 6,941 (3,477)
- -------------------------------------------------------------------------------------------------------
Net Cash (Used in) Provided from Financing Activities (211,472) (165,699) 20,514
- -------------------------------------------------------------------------------------------------------
Net (decrease) increase in cash
and temporary cash investments (247,622) (54,566) 386,211
Cash and temporary cash investments at beginning of year 356,412 410,978 24,767
- -------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year $ 108,790 $ 356,412 $ 410,978
=======================================================================================================
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized) $ 91,462 $ 95,413 $ 95,702
- -------------------------------------------------------------------------------------------------------
Income taxes $ 27,978 $ 66,703 $ 91,641
- -------------------------------------------------------------------------------------------------------
Non-cash investing and financing activities:
Preferred stock issued in conjunction with
long-term investments $ 33,726 $ 2,548 $ --
Note payable issued in conjunction with purchase
of property $ 25,000 $ -- $ --
Capital lease obligations recorded $ 7,855 $ 27,514 $ 13,050
Equity funding obligations cancelled $ -- $ 9,107 $ --
Equity funding obligations recorded $ -- $ 5,441 $ 36,716
On May 1, 1997, DQE exchanged its shares in Chester Engineers for shares of
common stock of the purchaser of Chester Engineers, which were subsequently sold
at various dates through June 5, 1997.
=======================================================================================================
</TABLE>
See notes to consolidated financial statements.
28
<PAGE>
Statement of Consolidated Comprehensive Income
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
------------------------------------
Year Ended December 31,
------------------------------------
1998 1997 1996
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net income $ 114,140 $ 199,101 $ 179,138
- ----------------------------------------------------------------------------------------------
Other comprehensive income:
Unrealized holding gains arising during the year,
net of tax of $452, $5,154 and $0 637 7,268 --
Less: reclassification adjustment for gains included
in net income, net of tax of $0, $4,440 and $0 -- (6,260) --
- ----------------------------------------------------------------------------------------------
Total Other Comprehensive Income 637 1,008 --
- ----------------------------------------------------------------------------------------------
Comprehensive Income $ 114,777 $ 200,109 $ 179,138
==============================================================================================
</TABLE>
See notes to consolidated financial statements.
Statement of Consolidated Retained Earnings
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
-------------------------------------
As of December 31,
-------------------------------------
1998 1997 1996
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at beginning of year $ 869,749 $ 777,607 $ 698,986
Net income 114,140 199,101 179,138
Dividends declared (114,218) (106,959) (100,517)
- -----------------------------------------------------------------------------------------------
Balance at End of Year $ 869,671 $ 869,749 $ 777,607
===============================================================================================
</TABLE>
See notes to consolidated financial statements.
Notes to Consolidated Financial Statements
A.
Summary of
Significant
Accounting
Policies
Consolidation
DQE, Inc. (DQE) is a multi-utility delivery and services company. Its
subsidiaries are Duquesne Light Company (Duquesne); AquaSource, Inc.
(AquaSource); DQE Energy Services, Inc. (DES); DQEnergy Partners, Inc.
(DQEnergy); Duquesne Enterprises, Inc. (DE); and Montauk, Inc. (Montauk). DQE
and its subsidiaries are collectively referred to as "the Company."
The Company's utility operations include an electric utility engaged in the
generation, transmission, distribution and sale of electric energy and a water
resource management company that acquires, develops and manages water and
wastewater utilities. The Company's expanded business lines offer a wide range
of energy-related technologies, industrial and commercial energy services,
telecommunications and other complementary services. The expanded business
lines' initiatives include energy facility development and operation, domestic
and international independent power production, the production and supply of
innovative fuels, investments in communications systems (including long-distance
telephone service) and electronic commerce. In addition, one of the Company's
subsidiaries is a financial services company that makes long-term investments
and provides financing for the other expanded business lines and related
customers.
On December 18, 1998, the Pennsylvania Public Utility Commission (PUC)
approved the Company's plan to divest itself of its generation assets through an
auction (including an auction of its provider of last resort service), and an
agreement in principle to exchange certain power stations with FirstEnergy
Corporation (FirstEnergy). Final agreements governing these transactions must be
approved by various regulatory agencies. The Company currently expects these
transactions to close in late 1999 or early 2000. (See "Rate Matters"
discussion, Note F, on page 34.)
Basis of Accounting
The Company is subject to the accounting and reporting requirements of the
Securities and Exchange Commission (SEC). In addition, the Company's 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.
29
<PAGE>
As a result of the PUC's final order regarding the Company's restructuring
plan under the Customer Choice Act (see "Rate Matters," Note F, on page 34), the
electricity generation portion of the Company's business no longer meets the
criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, application of SFAS No. 71 to this portion of the Company's
business has been discontinued and the Company now applies SFAS No. 101,
Regulated Enterprises -- Accounting for the Discontinuation of Application of
FASB Statement No. 71 (SFAS No. 101) as interpreted by Emerging Issues Task
Force 97-4, Deregulation of the Pricing of Electricity -- Issues Related to the
Application of FASB Statements No. 71 and 101. Under SFAS No. 101, the
regulatory assets and liabilities of the generation portion of the Company are
determined on the basis of the source from which the regulated cash flows to
realize such regulatory assets and settle such liabilities will be derived.
Pursuant to the PUC's final restructuring order, certain of the Company's
generation-related regulatory assets will be recovered through a competitive
transition charge (CTC) collected in connection with providing transmission and
distribution services (the electricity delivery business segment). The Company
will continue to apply SFAS No. 71 with respect to such assets. Fixed assets
related to the generation portion of the Company's business have been evaluated
in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived
Assets to Be Disposed Of (SFAS No. 121). Applying SFAS No. 121 to the non-
regulated generation assets, it has been determined that the Company's
generation assets are impaired. However, pursuant to the PUC's final
restructuring order, the Company will recover its above-market investment in
generation assets through the CTC. Under the Company's plan to auction its
generation assets, the market value utilized by the PUC in determining the value
of the generation assets will be the net after-tax proceeds received from the
auction. Accordingly, the amount of book value authorized by the PUC to be
recovered has been reclassified on the consolidated balance sheet from property,
plant and equipment to transition costs, until the auction has been completed
and all approvals for the final CTC accounting have been granted. 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 to the Company, 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 F, on page
34.)
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities, at the date of the financial
statements. The reported amounts of revenues and expenses during the reporting
period may also be affected by the estimates and assumptions management is
required to make. Actual results could differ from those estimates.
Energy Cost Rate Adjustment Clause (ECR)
Through the ECR, the Company previously recovered (to the extent that such
amounts were not included in base rates) nuclear fuel, fossil fuel and purchased
power expenses. Also through the ECR, the Company passed to its customers the
profits from short-term power sales to other utilities (collectively, ECR energy
costs). As a consequence of the PUC's final order regarding the Company's
restructuring plan (see "Rate Matters," Note F, on page 34), such fuel costs are
no longer recoverable through the ECR. Instead, effective May 29, 1998 (the date
of the PUC's final restructuring order), fuel costs are expensed as incurred and
thus impact net income.
Under-recoveries from customers prior to May 29, 1998, were recorded on the
consolidated balance sheet as a regulatory asset. At December 31, 1998, $42.7
million was receivable from customers. The Company expects to recover this
amount through the CTC. (See "Restructuring Plan" discussion, Note F, on page
35.) At December 31, 1997, $23.5 million was receivable from customers.
Revenues from Utility Sales
The Company's electric utility operations provide service to customers in
the City of Pittsburgh and surrounding areas. (See "Rate Matters," Note F, on
page 34.) This territory represents approximately 800 square miles in
southwestern Pennsylvania. The population of the area served by the Company's
electric utility operations, based on 1990 census data, is approximately
1,510,000, of whom 370,000 reside in the City of Pittsburgh. In addition to
serving approximately 580,000 direct customers, the Company's utility operations
also sell electricity to other utilities.
30
<PAGE>
The Company's water utility operations provide service to customers
throughout the United States. The Company's water operations have grown rapidly
and are currently approaching 300,000 customer connections.
Meters are read monthly and 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 on page 30.)
Maintenance
Effective January 1, 1999, as a result of the PUC's final restructuring
order, all electric utility maintenance costs will be expensed as incurred.
Historically, incremental maintenance costs incurred for refueling outages at
the Company's nuclear units were deferred for amortization over the period
between refueling outages (generally 18 months); the Company 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. During the fourth quarter of 1998, a reversal of the fossil
maintenance outage accrual was made for outages planned to occur after the
divestiture of the generation assets.
Depreciation and Amortization
Depreciation of property, plant and equipment, including plant-related
intangibles, is recorded on a straight-line basis over the estimated remaining
useful lives of properties. Goodwill, representing the excess of the cost over
the net tangible and identifiable assets of acquired businesses, is stated at
cost and is amortized on a straight-line basis over the estimated future periods
to be benefited (25 to 40 years). Goodwill is included in other non-current
assets on the consolidated balance sheet. In certain regulatory jurisdictions
the Company expects to recover its goodwill and to earn a return on those costs
through the ratemaking process. Amortization of gas reserve investments and
depreciation of related property are 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; and
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.
The Company records nuclear decommissioning costs under the category of
depreciation and amortization expense, and accrues a liability, equal to that
amount, for nuclear decommissioning expense. On the Company's consolidated
balance sheet, the decommissioning trusts have been reflected in other long-term
investments, and the related liability has been recorded as other non-current
liabilities. Trust fund earnings increase the fund balance and the recorded
liability. (See "Nuclear Decommissioning" discussion, Note J, on page 40.)
The Company's electric utility operations' composite depreciation rate
increased from 3.5 percent to 4.25 percent effective May 1, 1996. Also in 1996,
the Company expensed $9 million related to the depreciation portion of deferred
rate synchronization costs in conjunction with the Company's 1996 PUC-approved
mitigation plan. As a result of the May 29, 1998, PUC restructuring order, the
Company reduced its rate of depreciation on its generation assets, including
plant and transition costs, to achieve a net book value as of December 31, 1998,
equal to the level approved for recovery as transition costs.
Income Taxes
The Company uses the liability method in computing deferred taxes on all
differences between book and tax bases of assets. These book/tax differences
occur when events and transactions recognized for financial reporting purposes
are not recognized in the same period for tax purposes. The deferred tax
liability or asset is also adjusted in the period of enactment for the effect of
changes in tax laws or rates.
For its electricity delivery business segment, the Company recognizes a
regulatory asset for the deferred tax liabilities that are expected to be
recovered from customers through rates. (See "Rate Matters," Note F, and "Income
Taxes," Note H, on pages 34 and 38.)
The Company reflects the amortization of the regulatory tax receivable
resulting from reversals of deferred taxes as depreciation and amortization
expense. Reversals of accumulated deferred income taxes are included in income
tax expense.
When applied to reduce the Company's income tax liability, investment tax
credits related to the electricity delivery business segment generally are
deferred. Such credits are subsequently reflected, over the lives of the related
assets, as reductions to income tax expense.
31
<PAGE>
Other Operating Revenues and Other Income
Other operating revenues include the Company's non-kilowatt-hour (KWH)
utility revenues and revenues from expanded business lines' operating
activities. Other income primarily is made up of income from long-term
investments entered into by the expanded business lines. 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 the Company's 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 Company's electricity generation business segment
properties were written down to market value in accordance with SFAS No. 121 in
conjunction with the final PUC restructuring order. (See "Basis of Accounting"
discussion on page 29.)
Substantially all of the Company's 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. The Company considers temporary cash investments to be cash
equivalents.
Earnings Per Share
Basic earnings per share is computed by dividing income available to common
stockholders by the weighted-average number of common shares outstanding for the
period. Diluted earnings per share reflects the potential dilution that could
occur if securities or other contracts to issue common stock were exercised or
converted into common stock, or resulted in the issuance of common stock that
then shared in the earnings of the entity.
The preference stock of the ESOP, as described in Note N, "Employee
Benefits," was the primary cause for the dilution of earnings per share for the
years ended December 31, 1998, 1997 and 1996 as shown on the statement of
consolidated income. Each share of the preference stock is exchangeable for one
and one-half shares of DQE common stock. Assuming conversion at the beginning of
each year, the number of DQE shares was added to the denominator (weighted-
average number of common shares outstanding). Partially offsetting the dilutive
effect of the additional shares, the preference stock has an annual dividend
rate of $2.80 per share, which was added back to the numerator (income available
to common stockholders). The result of calculating both basic and dilutive
earnings per share was a $0.02 dilutive effect for 1998, after the Pennsylvania
restructuring charge, and a $0.03 dilutive effect for 1997 and 1996.
Stock-Based Compensation
The Company accounts 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 the
Company's 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 annually, based on the quoted market price of the Company's stock at
the end of the period.
Reclassification
The 1997 and 1996 consolidated financial statements have been reclassified
to conform with 1998 presentation.
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133).
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.
The adoption of SFAS No. 133 is not expected to have a significant impact on the
Company's financial statements and disclosures.
32
<PAGE>
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,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
----------------------------------
1998 1997 1996
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Receivables $ (19,080) $ (14,476) $ (1,946)
Materials and supplies (10,942) (1,740) 1,286
Other current assets (1,020) (519) (948)
Accounts payable 30,745 (4,993) 4,691
Other current liabilities (36,698) (15,030) (168)
- ------------------------------------------------------------------------------------------------------------
Total $ (36,995) $ (36,758) $ 2,915
============================================================================================================
</TABLE>
C.
Property,
Plant and
Equipment
In addition to its wholly owned generating units, the Company, together with
FirstEnergy, has an ownership or leasehold interest in certain jointly owned
units. The Company is required to pay its share of the construction and
operating costs of the units. The Company's share of the operating expenses of
the units is included in the statement of consolidated income. The Company
anticipates divesting itself of its generation assets at the end of 1999 or in
early 2000. (See "Rate Matters," Note F, on page 34.)
Generating Units
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Generating
Capability Fuel
Unit (Megawatts) Source
- -----------------------------------------------------------------------
<S> <C> <C>
Cheswick 570 Coal
Elrama (a) 487 Coal
Eastlake Unit 5 (f) 186 Coal
Sammis Unit 7 (f) 187 Coal
Bruce Mansfield Units 1, 2 and 3 (a)(f) 400 Coal
Beaver Valley Unit 1 (b)(f) 385 Nuclear
Beaver Valley Unit 2 (c)(d)(f) 113 Nuclear
Perry Unit 1 (e)(f) 164 Nuclear
Brunot Island Units 1 and 2 178 Fuel Oil
- -----------------------------------------------------------------------
Total Generating Capability 2,670
=======================================================================
</TABLE>
(a) The units are equipped with flue gas desulfurization equipment.
(b) The Nuclear Regulatory Commission (NRC) has granted a license to operate
through January 2016.
(c) In 1987, the Company sold and leased back its 13.74 percent interest in
Beaver Valley Unit 2.
(d) The NRC has granted a license to operate through May 2027.
(e) The NRC has granted a license to operate through March 2026.
(f) Jointly owned with FirstEnergy.
Additionally, the Company has an ownership interest in certain generating
units not currently included in electric plant in service on the consolidated
balance sheet. The Brunot Island (BI) Units 3 and 4 and the Phillips Power
Station (Phillips) will be offered as part of the Company's generation asset
auction.
D.
Long-Term
Investments
The Company makes equity investments in affordable housing and gas reserve
partnerships as a limited partner. At December 31, 1998, the Company had
investments in 27 affordable housing funds and 29 gas reserve sites. The Company
is the lessor in nine leveraged lease arrangements involving mining equipment,
rail equipment, fossil generating stations, a waste-to-energy facility, high
speed service ferries and natural gas processing equipment. These leases expire
in various years beginning in 2004 through 2033. The recorded residual value of
the equipment at the end of the lease terms is approximately two percent of the
original cost. The Company's aggregate investment represents 20 percent of the
aggregate original cost of the property and is either leased to a creditworthy
lessee or is secured by guarantees of the lessee's parent or affiliate. The
remaining 80 percent was financed by non-recourse debt provided by lenders who
have been granted, as their sole remedy in the event of default by the lessees,
an assignment of rentals due under the leases and a security interest in the
leased property. This debt amounted to $949 million and $950 million at
December 31, 1998 and 1997.
33
<PAGE>
<TABLE>
<CAPTION>
Net Leveraged Lease Investments as of December 31, (Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------------------------
1998 1997
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Rentals receivable (net of non-recourse debt) $632,879 $638,030
Estimated residual value of leased assets 22,029 22,029
Less: Unearned income (266,795) (310,930)
- -----------------------------------------------------------------------------------------------------------------------
Leveraged lease investments 388,113 349,129
Less: Deferred taxes arising from leveraged leases (185,639) (115,383)
- -----------------------------------------------------------------------------------------------------------------------
Net Leveraged Lease Investments $202,474 $233,746
=======================================================================================================================
</TABLE>
The Company's other leases include investments in fossil generating
stations, a waste-to-energy facility, computers, vehicles and equipment. The
Company's other investments are primarily in assets of nuclear decommissioning
trusts and marketable securities. Deferred income primarily relates to the
Company's other lease investments and certain gas reserve investments. Deferred
amounts will be recognized as income over the lives of the underlying
investments for periods generally not exceeding seven years from the time of
investment.
E.
Acquisitions
In 1997, the Company created the Preferred Stock, Series A (Convertible),
$100 liquidation preference per share (DQE Preferred Stock), to issue as
consideration in lieu of cash in connection with acquisitions by the Company of
other businesses, assets or securities. (See "Preferred and Preference Stock,"
Note L, on page 44.) Through December 31, 1998, the Company had invested
approximately $166 million (of which approximately $35 million was in the form
of DQE Preferred Stock) to acquire the stock or assets of water and water-
related companies. The Company also invested $22 million to acquire a 50 percent
interest in and finance the growth of Control Solutions, LLC, a commercial and
industrial heating, ventilation and air conditioning service and energy controls
company.
F.
Rate Matters
Competition and the Customer Choice Act
The electric utility industry continues to undergo fundamental change in
response to development of open transmission access and increased availability
of energy alternatives. Under historical 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 historical ratemaking process, utilities had assets recorded on their
balance sheets at above-market costs, thus creating transition and stranded
costs.
In Pennsylvania, the Customer Choice Act went into effect on January 1, 1997.
The Customer Choice Act enables Pennsylvania's electric utility customers to
purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act provides that the
existing franchised utility may recover, through a CTC, an amount of transition
costs that are determined by the PUC to be just and reasonable. Pennsylvania's
electric utility restructuring is being accomplished through a two-stage process
consisting of an initial customer choice pilot period (which ended in December
1998) and a phase-in to competition period (which began in January 1999). The
Company's estimated negative net income impact of the customer choice pilot
program during 1998, with five percent of customers participating, was
approximately $6 million.
Phase-In to Competition
The phase-in to competition began in January 1999, when 66 percent of
customers became eligible to participate in customer choice (including customers
covered by the pilot program); all customers will have customer choice in
January 2000. As of February 28, 1999, approximately 12.5 percent of the
Company's customers had chosen alternative generation suppliers. Customers that
have chosen an electricity generation supplier other than the Company pay that
supplier for generation charges, and pay the Company a CTC (discussed below) and
charges for transmission and distribution. Customers that continue to buy their
generation from the Company pay for their service at current regulated tariff
rates divided into generation, transmission and distribution
34
<PAGE>
charges. Under the Customer Choice Act, an electric distribution company, such
as Duquesne, remains a regulated utility and may only offer PUC-approved rates,
including generation rates. Also under the Customer Choice Act, electricity
delivery (including transmission, distribution and customer service) remains
regulated in substantially the same manner as under current regulation.
In an effort to "jump start" retail competition, the Company has made 600
megawatts (MW) of power available to licensed electric generation suppliers, to
be used in supplying electricity to Duquesne's customers who have chosen
alternative generation suppliers. The power will be available for the first six
months of 1999 at a price of 2.6 cents per kilowatt-hour (KWH). This power
availability will be structured to ensure the power is used to benefit
Duquesne's retail customers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, has been
imposed on the transmission and distribution charges of Pennsylvania electric
utility companies under the Customer Choice Act. Additionally, electric utility
companies may not increase the generation price component of rates as long as
transition costs are being recovered, with certain exceptions.
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that the
Company should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The total of the transition costs to be recovered is
$2,133 million ($1,485 million, net of tax) over a seven-year period beginning
January 1, 1999, as may be adjusted to account for the proceeds of the
generation asset auction. In addition, the transition costs as reflected on the
consolidated balance sheet will be amortized over the same period that the CTC
revenues are being recognized. The Company will earn an 11 percent pre-tax
return on the unrecovered balance.
In the second quarter of 1998, the Company recorded the Pennsylvania
restructuring charge against earnings of $142.3 million ($82.5 million, net of
tax) for the generation-related stranded costs not considered by the PUC's
restructuring order to be recoverable from customers. The Pennsylvania
restructuring charge included Phillips, BI, deferred caretaker costs related to
the two stations and deferred coal costs. The charge resulted in a reduction of
Duquesne's contribution to the Company's earnings per share by $1.06. The
following table sets forth the amounts reclassified from regulatory assets and
property, plant, and equipment to transition costs.
Other Non-Current Assets as of December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Other
Transition Regulatory
Costs Assets Assets
------------------------------------
(Thousands of Dollars) 1998 1998 1997
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Power plants (a) $1,073,730 $ -- $ --
Beaver Valley Unit 2 lease liability (See Note I) 475,570 -- --
Regulatory tax receivable 236,480 23,177 301,664
Beaver Valley Unit 2 sale/leaseback deferred taxes (b) 55,130 -- --
Unamortized debt costs 45,770 33,612 87,915
Beaver Valley Unit 2 sale/leaseback costs 37,790 -- 38,299
Deferred rate synchronization costs 25,370 -- 37,231
Deferred employee costs 14,240 7,779 25,130
Deferred energy costs 11,510 -- 23,514
DQE decontamination and decommissioning receivable 5,580 -- 8,847
Deferred nuclear maintenance outage costs 3,250 -- 17,013
Brunot Island and Phillips cold reserve units (c) -- -- 105,693
Deferred coal costs (c) -- -- 15,711
Other (c) (d) 148,560 -- 19,868
- ---------------------------------------------------------------------------------------------
Total $2,132,980 $ 64,568 $680,885
=============================================================================================
</TABLE>
(a) Amount represents the above-market costs of the power plants and was
reclassified in the second quarter of 1998 from property, plant, and
equipment to transition costs. A final determination of plant market value
will be determined in conjunction with the generation auction.
(b) Amount represents deferred taxes related to the taxable gain on the
sale/leaseback of Beaver Valley Unit 2 and was reclassified from deferred
tax liabilities to transition costs.
(c) In the second quarter of 1998 amounts were written off as an extraordinary
charge to the consolidated statement of income as part of the Pennsylvania
restructuring charge.
(d) Amounts reflected in transition costs include reclassifications from other
non-current assets and other non-current liabilities. In addition, there are
amounts included in transition costs that had not previously been recorded
on the consolidated balance sheet but were determined in the final PUC
restructuring order to be costs recoverable from customers through the CTC.
In the case of amounts not recorded, a regulatory liability was recorded for
the same amount as the transition costs.
35
<PAGE>
As part of its restructuring plan filing, the Company 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. The Company also requested recovery of an
additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On
December 18, 1998, the PUC denied recovery of this additional amount. The
Company has appealed the PUC's denial of recovery to the Pennsylvania
Commonwealth Court. Based upon the Customer Choice Act, which mandates recovery
of all regulatory assets, and the PUC's specific authorization for the Company
to create a regulatory asset for these costs, the Company believes that it is
probable that these costs will be recovered through retail rates. In the event
that the Company does not prevail in its appeal, these costs would be written
off as a charge against income during 1999.
Restructuring Plan and Auction Plan. With respect to transition cost
recovery, the PUC's final order on the restructuring plan approved Duquesne's
proposal to auction its generation assets and use the proceeds to offset
transition costs. The remaining balance of such costs (with certain exceptions
described below) will be recovered from ratepayers through a CTC, collectible
through 2005. Until the divestiture is complete, Duquesne has been ordered to
use an interim system average CTC and price to compare based on the methodology
approved in its pilot program (approximately 2.9 cents per KWH for the CTC and
approximately 3.8 cents per KWH for the price to compare).
On December 18, 1998, the PUC approved Duquesne's auction plan, including an
auction of its provider of last resort service, as well as an agreement in
principle to exchange certain generation assets with FirstEnergy. The assets to
be auctioned will include Duquesne's wholly owned Cheswick Power Station, Elrama
Power Station, Phillips and BI, as well as the stations to be received from
FirstEnergy in the power station exchange described below. The auction plan
calls for a two-phase, sealed bid process similar to that used in other power
plant divestitures. The initial confidential bidding process is expected to
begin in the spring of 1999, with potential buyers identified by Duquesne being
asked to submit non-binding bids. Final agreements governing the transactions
must be approved by various regulatory agencies, including the PUC, the FERC,
the NRC, the Department of Justice and/or the Federal Trade Commission. Duquesne
currently expects the sale to close at the end of 1999 or the beginning of
2000.
Power Station Exchange. Pursuant to the definitive agreements entered into on
March 25, 1999 (which remain subject to regulatory approval), Duquesne and
FirstEnergy will exchange ownership interests in certain power stations.
Duquesne will receive 100 percent ownership rights in three coal-fired power
plants located in Avon Lake and Niles, Ohio and New Castle, Pennsylvania
(totaling approximately 1,300 MW), which the Company expects to sell
simultaneously as part of the auction of generation assets. FirstEnergy will
acquire Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley
Unit 2 (BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce
Mansfield Units 1, 2 and 3 (totaling approximately 1,400 MW). In connection with
the power station exchange, the Company anticipates terminating the BV Unit 2
lease. (See "Leases," Note I, on page 39.) Pursuant to the December 18, 1998,
PUC order and subject to final approval, the proceeds from the sale of the power
stations received in the exchange will be used to offset the transition costs
associated with Duquesne's currently-held generation assets and costs associated
with completing the exchange. Duquesne expects this exchange to enhance the
value received from the auction, because participants will bid on plants that
are wholly owned by Duquesne, rather than plants that are jointly owned and/or
operated by another entity. Additionally, the auction will include only coal-
and oil-fired plants, which are anticipated to have a higher market value than
nuclear plants. These value-enhancing features, along with a minimum level of
auction proceeds guaranteed by FirstEnergy, are expected to maximize auction
proceeds, minimize transition costs required to be recovered through the CTC (by
shortening the length of the CTC recovery period), and thus reduce customer
bills as rapidly as possible. Other benefits of this exchange include the
resolution of all joint ownership issues, and other risks and costs associated
with the jointly-owned units. Although the PUC has said the exchange appears to
be in the public interest, the definitive exchange agreement must be submitted
for PUC approval, and certain aspects of the exchange will have to be approved
by, among other agencies, the FERC, the NRC and the Department of Justice. The
power station exchange is expected to occur simultaneously with the anticipated
closing of the sale of Duquesne's generation through the auction at the end of
1999 or in early 2000.
36
<PAGE>
Termination of the AYE Merger
On July 28, 1998, DQE's board of directors concluded that it could not
consummate the merger with AYE, toward which the Company had been working. The
Company 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. More information regarding this decision is set forth in the
Company's Current Report on Form 8-K dated July 28, 1998. On July 30, 1998, AYE
informed DQE that it would continue to work toward consummation of the merger,
and also pursue all remedies available to protect the legal and financial
interests of AYE and its shareholders.
On September 17, 1998, the PUC issued an order stating that, unless the
parties jointly agreed to an extension of time to consummate the merger beyond
October 5, 1998 (the relevant date under the merger agreement), their merger
application with the PUC would be considered withdrawn. On October 5, 1998, the
Company announced its unilateral termination of the merger agreement. More
information regarding this termination is set forth in the Company's Current
Report on Form 8-K dated October 5, 1998. In a letter dated February 24, 1999,
the PUC informed the Company that the merger application was deemed withdrawn
and the docket was closed.
AYE filed suit in the United States District Court for the Western District
of Pennsylvania, seeking to compel the Company to proceed with the merger and
seeking a temporary restraining order and preliminary injunction to prevent the
Company from certain actions pending a trial, or in the alternative seeking an
unspecified amount of money damages. On October 28, 1998, the judge denied AYE's
motion for the temporary restraining order and preliminary injunction. AYE
appealed to the United States Court of Appeals for the Third Circuit, asking for
an injunction pending the appeal and expedited treatment of the appeal. On
November 6, 1998, the Third Circuit denied the motion for an injunction and
granted the motion to expedite the appeal.
On March 11, 1999, the Third Circuit vacated the October 28 denial of a
preliminary injunction. The Third Circuit remanded the case to the District
Court for further proceedings to address certain issues, including whether AYE
could demonstrate a reasonable likelihood of success on the merits, before
determining whether any injunctive relief is warranted. On March 12, 1999, AYE
filed a motion for a temporary restraining order with the district court, and a
hearing was held that same day. On March 16, 1999, AYE and DQE entered into a
consent agreement, which was approved by the district court on March 18.
Pursuant to the consent agreement, AYE and DQE have agreed, among other things,
that pending the consolidated hearing on AYE's application for a preliminary
injunction and/or an expedited trial on the merits, both parties will give each
other 10 business days' notice before taking or omitting to take any action
which would prevent the merger from qualifying for "pooling of interests"
accounting treatment. This would not prevent either party from entering into any
agreement, but would require the 10 business days' notice prior to closing any
transaction which prevents pooling. The consent agreement shall terminate on
September 16, 1999, unless earlier terminated or extended by mutual agreement or
an order of the district court.
The Company continues to believe that AYE's claim is entirely without merit
in light of the $1 billion disallowance of its stranded costs, which constituted
a material adverse effect under the merger agreement and entitled the Company to
terminate it as of October 5, 1998. The Company will continue to defend itself
vigorously against AYE's claims and intends to pursue a prompt resolution of the
litigation. On March 25, 1999, the Company petitioned the Third Circuit for
rehearing. In the interim, the Company intends to continue to pursue the
implementation of customer choice under its PUC-approved restructuring plan,
including the power station exchange with FirstEnergy and the generation
exchange auction. The ultimate outcome of this suit cannot be determined at this
time.
G.
Short-Term
Borrowing
and Revolving
Credit
Arrangements
At December 31, 1998, the Company had two extendible revolving credit
arrangements, including a $125 million facility expiring in June 1999 and a $150
million facility expiring in October 1999. Interest rates can, in accordance
with the option selected at the time of the borrowing, be based on prime,
Eurodollar or certificate of deposit rates. Commitment fees are based on the
unborrowed amount of the commitments. Both credit facilities contain two-year
repayment periods for any amounts outstanding at the expiration of the revolving
credit periods. At December 31, 1998 and December 31, 1997, there were no short-
term borrowings outstanding.
37
<PAGE>
H.
Income Taxes
The annual federal corporate income tax returns have been audited by the
Internal Revenue Service (IRS) for the tax years through 1992. The IRS is
reviewing the 1993 and 1994 returns, and the tax years 1995, 1996, 1997 and 1998
remain subject to IRS review. The Company does not believe that final settlement
of the federal income tax returns for the years 1990 through 1998 will have a
materially adverse effect on its financial position, results of operations or
cash flows.
Deferred Tax Assets (Liabilities) as of December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
-------------------------
1998 1997
- ---------------------------------------------------------------------------------------------
<S> <C> <C>
Tax benefit -- long-term investments $ 221,277 $ 235,957
BV lease liability 167,440 --
Unbilled revenue 16,589 19,637
Investment tax credits unamortized 9,990 40,573
Gain on sale/leaseback of BV Unit 2 -- 58,137
Other 116,525 65,210
- ---------------------------------------------------------------------------------------------
Deferred tax assets 531,821 419,514
- ---------------------------------------------------------------------------------------------
Transition costs (664,810) --
Property depreciation (285,783) (712,247)
Leveraged leases (185,639) (115,383)
Deferred coal and energy costs (16,525) (15,910)
Loss on reacquired debt unamortized (12,976) (31,360)
Regulatory assets (9,620) (125,171)
Other (133,485) (87,095)
- ---------------------------------------------------------------------------------------------
Deferred tax liabilities (1,308,838) (1,087,166)
- ---------------------------------------------------------------------------------------------
Net Deferred Tax Liabilities $ (777,017) $ (667,652)
=============================================================================================
</TABLE>
Income Taxes
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
--------------------------------
Year Ended December 31,
--------------------------------
1998 1997 1996
- ------------------------------------------------------------------------------------
<S> <C> <C> <C>
Currently payable: Federal $ 2,245 $ 3,911 $ 85,976
State 26,946 31,083 44,582
Deferred -- net: Federal 80,104 69,324 (18,737)
State 2,072 (93) (14,874)
Investment tax credits deferred -- net (10,385) (8,420) (9,559)
- ------------------------------------------------------------------------------------
Income Taxes $100,982 $ 95,805 $ 87,388
====================================================================================
</TABLE>
Total income taxes differ from the amount computed by applying the statutory
federal income tax rate to income before income taxes.
Income Tax Expense Reconciliation
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
--------------------------------
Year Ended December 31,
--------------------------------
1998 1997 1996
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Computed federal income tax at statutory rate $104,185 $103,217 $ 93,284
Increase (decrease) in taxes resulting from:
State income taxes, net of federal income tax benefits 18,370 20,143 19,310
Investment tax benefits -- net (14,884) (17,831) (15,116)
Amortization of deferred investment tax credits (10,385) (8,420) (9,559)
Other 3,696 (1,304) (531)
- ------------------------------------------------------------------------------------------
Total Income Tax Expense $100,982 $ 95,805 $ 87,388
==========================================================================================
</TABLE>
38
<PAGE>
I.
Leases
The Company leases nuclear fuel, a portion of a nuclear generating plant,
certain office buildings, computer equipment, and other property and
equipment.
Capital Leases as of December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
----------------------
1998 1997
- -----------------------------------------------------------------------
<S> <C> <C>
Nuclear fuel $100,756 $ 92,901
Electric plant 19,923 20,761
Other 2,695 --
- -----------------------------------------------------------------------
Total 123,374 113,662
Less: Accumulated amortization (63,604) (50,725)
- -----------------------------------------------------------------------
Property Held Under Capital Leases Net (a) $ 59,770 $ 62,937
=======================================================================
</TABLE>
(a) Includes $2,037 in 1998 and $2,874 in 1997 of capital leases with
associated obligations retired.
In 1987, the Company sold and leased back its 13.74 percent interest in BV
Unit 2; the sale was exclusive of transmission and common facilities. The
Company subsequently leased back its interest in the unit for a term of 29.5
years. The lease provides for semi-annual payments and was accounted for as an
operating lease. In conjunction with the PUC restructuring order, it was
determined that the costs related to the lease were transition costs to be
recovered through the CTC. The Company recorded the lease liability and a
corresponding regulatory asset for the present value of the future lease
payments. The Company is responsible under the terms of the lease for all costs
related to its interest in the unit. In December 1992, the Company participated
in the refinancing of collateralized lease bonds to take advantage of lower
interest rates, thus reducing the annual lease payments. The bonds were
originally issued in 1987 to partially fund the lease of BV Unit 2. The
associated letter of credit securing the lessor's equity interest in the unit is
$194 million and the term of the letter of credit extends to 1999. The Company
currently anticipates terminating the lease in connection with the power station
exchange with FirstEnergy, in which case the lease liability recorded on the
consolidated balance sheet would no longer be an obligation of the Company. The
underlying collateralized lease bonds ($371.0 million at December 31, 1998)
would become direct obligations of the Company and be recorded as debt on the
consolidated balance sheet. (See "Rate Matters," Note F, on page 34.)
Leased nuclear fuel is amortized as the fuel is burned and charged to fuel
and purchased power expense on the statement of consolidated income. The
amortization of all other leased property is based on rental payments made
(except the BV Unit 2 lease). These lease-related expenses are charged to
operating expenses on the statement of consolidated income.
Summary of Rental Payments
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
-------------------------------
Year Ended December 31,
-------------------------------
1998 1997 1996
- ------------------------------------------------------------------------
<S> <C> <C> <C>
Operating leases $57,324 $60,684 $59,503
Amortization of capital leases 12,943 16,847 19,378
Interest on capital leases 4,386 3,435 3,703
- ------------------------------------------------------------------------
Total Rental Payments $74,653 $80,966 $82,584
========================================================================
</TABLE>
39
<PAGE>
Future Minimum Lease Payments
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
--------------------------------------
BV Unit 2 Operating Capital
Year Ended December 31, Lease Leases Leases
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
1999 $ 45,476 $ 8,846 $ 24,839
2000 45,670 8,610 13,516
2001 45,643 8,552 10,028
2002 47,305 8,441 5,132
2003 53,100 -- 3,085
2004 and thereafter 756,994 -- 16,919
- ----------------------------------------------------------------------------
Total Minimum Lease Payments $994,188 $34,449 $ 73,519
- ----------------------------------------------------------------------------
Less: Amount representing interest (15,786)
- ----------------------------------------------------------------------------
Present value of minimum lease payments for capital leases (a) $ 57,733
============================================================================
</TABLE>
(a) Includes current obligations of $21.1 million at December 31, 1998.
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 the estimated use of nuclear fuel financed through
leasing arrangements expiring in 1999 and building leases.
Future payments due to the Company, as of December 31, 1998, under subleases
of certain corporate office space are approximately $6.0 million in 1999, $6.0
million in 2000 and $12.7 million thereafter.
J.
Commitments
and
Contingencies
The Company anticipates divesting itself of its generation assets through
the auction and the power station exchange by early 2000 and, depending on the
regulatory approvals of the final agreements regarding the divestiture, expects
certain obligations related to the divested assets will be transferred to the
future owners. (See "Restructuring Plan" discussion, Note F, on page 35.)
Construction, Investments and Acquisitions
The Company estimates that it will spend, excluding AFC and nuclear fuel,
approximately $110 million in 1999 (including $30 million for generation), $75
million in 2000 (excluding generation) and $70 million in 2001 (excluding
generation) for electric utility construction.
Nuclear-Related Matters
The Company has an interest in three nuclear units, two of which it
operates. The operation of a nuclear facility involves special risks, potential
liabilities, and specific regulatory and safety requirements. Specific
information about risk management and potential liabilities is discussed
below.
Nuclear Decommissioning. The Company expects to decommission BV Unit 1, BV
Unit 2 and Perry Unit 1 no earlier than the expiration of each plant's operating
license in 2016, 2027 and 2026, respectively. At the end of its operating life,
BV Unit 1 may be placed in safe storage until BV Unit 2 is ready to be
decommissioned, at which time the units may be decommissioned together.
Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit
2, and a 1997 update of the 1994 study for Perry Unit 1, the Company's
approximate share of the total estimated decommissioning costs, including
removal and decontamination costs, is $170 million, $55 million and $90 million,
respectively. The amount currently used to determine the Company's cost of
service related to decommissioning all three nuclear units is $224 million.
Funding for nuclear decommissioning costs is deposited in external,
segregated trust accounts and invested in a portfolio of corporate common stock
and debt securities, municipal bonds, certificates of deposit and United States
government securities. The market value of the aggregate trust fund balances at
December 31, 1998, totaled approximately $62.7 million.
As part of the power station exchange, FirstEnergy has agreed to assume the
decommissioning liability for each of the nuclear plants in exchange for the
balance in the decommissioning trust funds, plus the decommissioning costs
expected to be collected through the CTC.
40
<PAGE>
Nuclear Insurance. The Price-Anderson Amendments to the Atomic Energy Act of
1954 limit public liability from a single incident at a nuclear plant to $9.8
billion. The maximum available private primary insurance of $200 million has
been purchased by the Company. Additional protection of $9.6 billion would be
provided by an assessment of up to $88.1 million per incident on each licensed
nuclear unit in the United States. The Company's maximum total possible
assessment, $66.1 million, which is based on its ownership or leasehold
interests in three nuclear generating units, would be limited to a maximum of
$7.5 million per incident per year. This assessment is subject to indexing for
inflation and may be subject to state premium taxes. If assessments from the
nuclear industry prove insufficient to pay claims, the United States Congress
could impose other revenue-raising measures on the industry.
The Company's share of insurance coverage for property damage, decommissioning
and decontamination liability is $1.2 billion. The Company would be responsible
for its share of any damages in excess of insurance coverage. In addition, if
the property damage reserves of Nuclear Electric Insurance Limited (NEIL), an
industry mutual insurance company that provides a portion of this coverage, are
inadequate to cover claims arising from an incident at any United States nuclear
site covered by that insurer, the Company could be assessed retrospective
premiums totaling a maximum of $7.3 million.
In addition, the Company participates in a NEIL program that provides
insurance for the increased cost of generation and/or purchased power resulting
from an accidental outage of a nuclear unit. Subject to the policy deductible,
terms and limit, the coverage provides for a weekly indemnity of the estimated
incremental costs during the three-year period starting 17 weeks after an
accident, with no coverage thereafter. If NEIL's losses for this program ever
exceed its reserves, the Company could be assessed retrospective premiums
totaling a maximum of $2.6 million.
Beaver Valley Power Station (BVPS). BVPS's two units are equipped with steam
generators designed and built by Westinghouse Electric Corporation
(Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter
stress corrosion cracking (ODSCC) has occurred in the steam generator tubes of
both units. BV Unit 1, which was placed in service in 1976, has removed
approximately 17 percent of its steam generator tubes from service through a
process called "plugging." However, BV Unit 1 still has the capability to
operate at 100 percent reactor power and has the ability to return tubes to
service by repairing them through a process called "sleeving." No tubes at
either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was
placed in service 11 years after BV Unit 1, has not yet exhibited the degree of
ODSCC experienced at BV Unit 1. Approximately 3 percent of BV Unit 2's tubes are
plugged; however, it is too early in the life of the unit to determine the
extent to which ODSCC may become a problem at that unit.
The Company has undertaken certain measures, such as increased inspections,
water chemistry control and tube plugging, to minimize the operational impact of
and reduce susceptibility to ODSCC. Although the Company has taken these steps
to allay the effects of ODSCC, the inherent potential for future ODSCC in steam
generator tubes of the Westinghouse design still exists. Material acceleration
in the rate of ODSCC could lead to a loss of plant efficiency, significant
repairs or the possible replacement of the BV Unit 1 steam generators. The total
replacement cost of the BV Unit 1 steam generators is currently estimated at
$125 million. The Company would be responsible for $59 million of this total,
which includes the cost of equipment removal and replacement steam generators,
but excludes replacement power costs. The earliest that the BV Unit 1 steam
generators could be replaced during a currently scheduled refueling outage is
the fall of 2001.
The Company continues to explore all viable means of managing ODSCC,
including new repair technologies, and plans to continue to perform 100 percent
tube inspections during future refueling outages. However, the Company may be
required to perform an earlier inspection of BV Unit 1's tubes and other
equipment during a mid-cycle outage in 1999, to comply with NRC requirements to
conduct such inspections at BV Unit 1 at least every 20 months. The Company has
requested permission from the NRC to postpone these inspections until BV Unit
1's next refueling outage, currently scheduled to begin in the spring of 2000.
The Company completed its inspection of BV Unit 2's tubes during a forced outage
in 1998 to comply with NRC requirements to conduct such inspections at BV Unit 2
at least every 24 months. The next refueling outage for BV Unit 2 is currently
scheduled to begin at the end of February 1999. No steam generator tube
inspections will be performed until the subsequent refueling outage, currently
scheduled for the fall of 2000. The Company will continue to monitor and
evaluate the condition of the BVPS steam generators.
41
<PAGE>
BV Unit 1 went off-line on January 30, 1998, due to an issue identified in a
technical review completed by the Company. BV Unit 2 went off-line on December
16, 1997, to repair the emergency air supply system to the control room. BV Unit
2 remained off-line due to other issues identified by a technical review,
similar to that performed at BV Unit 1. These technical reviews, held in
response to a 1997 commitment made by the Company to the NRC, have been
completed. The Company was one of many utilities faced with similar issues, some
of which date back to the initial start-up of BVPS. BV Unit 1 returned to
service on August 15, 1998, and BV Unit 2 returned to service on September 28,
1998.
Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982
established a federal policy for handling and disposing of spent nuclear fuel
and a policy requiring the establishment of a final repository to accept spent
nuclear fuel. Electric utility companies have entered into contracts with the
United States Department of Energy (DOE) for the permanent disposal of spent
nuclear fuel and high-level radioactive waste in compliance with this
legislation. The DOE has indicated that its repository under these contracts
will not be available for acceptance of spent nuclear fuel before 2010. The DOE
has not yet established an interim or permanent storage facility, despite a
ruling by the United States Court of Appeals for the District of Columbia
Circuit that the DOE was legally obligated to begin acceptance of spent nuclear
fuel for disposal by January 31, 1998. Existing on-site spent nuclear fuel
storage capacities at BV Unit 1, BV Unit 2 and Perry Unit 1 are expected to be
sufficient until 2018, 2012 and 2011, respectively.
In early 1997, the Company joined 35 other electric utilities and 46 states,
state agencies and regulatory commissions in filing suit in the United States
Court of Appeals for the District of Columbia Circuit against the DOE. The
parties requested the court to suspend the utilities' payments into the Nuclear
Waste Fund and to place future payments into an escrow account until the DOE
fulfills its obligation to accept spent nuclear fuel. The DOE had requested that
the court delay litigation while it pursued alternative dispute resolution under
the terms of its contracts with the utilities. The court ruling, issued November
14, 1997, and affirmed on rehearing May 5, 1998, denied the relief requested by
the utilities and states and permitted the DOE to pursue alternative dispute
resolution, but prohibited the DOE from using its lack of a spent fuel
repository as a defense. The United States Supreme Court declined to review the
decision. The utilities' remaining remedy is to sue the DOE in federal court for
money damages caused by the DOE's delay in fulfilling its obligations.
Uranium Enrichment Obligations. Nuclear reactor licensees in the United
States are assessed annually for the decontamination and decommissioning of DOE
uranium enrichment facilities. Assessments are based on the amount of uranium a
utility had processed for enrichment prior to enactment of the National Energy
Policy Act of 1992, and are to be paid by such utilities over a 15-year period.
At December 31, 1998, the Company's liability for contributions was
approximately $6.2 million (subject to an inflation adjustment), which will be
recovered through the CTC as part of transition costs.
Fossil Decommissioning
Based on studies conducted in 1997, the amount for fossil decommissioning is
currently estimated to be $130 million for the Company's interest in 17 units at
six sites. Each unit is expected to be decommissioned upon the cessation of the
unit's final operations. The Company was not permitted to recover these costs as
part of its restructuring plan. (See "Rate Matters," Note F, on page 34.)
Guarantees
The Company and the other owners of Bruce Mansfield Power Station (Bruce
Mansfield) have guaranteed certain debt and lease obligations related to a coal
supply contract for Bruce Mansfield. At December 31, 1998, the Company's share
of these guarantees was $10.4 million.
As part of the Company's investment portfolio in affordable housing, the
Company has received fees in exchange for guaranteeing a minimum defined yield
to third-party investors. A portion of the fees received has been deferred to
absorb any required payments with respect to these transactions. Based on an
evaluation of and recent experience with the underlying housing projects, the
Company believes that such deferrals are ample for this purpose.
42
<PAGE>
Residual Waste Management Regulations
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. The Company is
assessing the sites it utilizes and has developed compliance strategies that are
currently under review by the DEP. Based on information currently available,
$4.5 million will be spent in 1999 to comply with these DEP regulations. The
additional capital cost of compliance is estimated, based on current
information, to be approximately $4.8 million per year for the next three years.
This estimate is subject to the results of groundwater assessments and DEP final
approval of compliance plans.
Employees
Duquesne is party to a labor contract expiring in September 2001 with the
International Brotherhood of Electrical Workers (IBEW), which represents
approximately 2,000 of Duquesne's employees. The contract provides, among other
things, employment security, income protection and 3 percent annual wage
increases through September 2000. Duquesne and the IBEW have agreed on a package
of additional benefits and protections for union employees affected by the
divestiture of generation assets. Any buyer of generation assets currently owned
by Duquesne will be required to offer work to current IBEW employees on a
seniority basis, recognize the IBEW as the exclusive bargaining representative,
establish comparable employee benefit plans, and assume the current labor
contract.
In connection with the anticipated divestiture, Duquesne has developed early
retirement programs and enhanced separation packages available for eligible IBEW
and management employees. Duquesne expects to recover related costs through the
divestiture proceeds.
Other
The Company is involved in various other legal proceedings and environmental
matters. The Company believes that such proceedings and matters, in total, will
not have a materially adverse effect on its financial position, results of
operations or cash flows.
K.
Long-Term
Debt
The pollution control notes arise from the sale of bonds by public
authorities for the purposes of financing construction of pollution control
facilities at the Company's plants or refunding previously issued bonds. The
Company is obligated to pay the principal and interest on these bonds. For
certain of the pollution control notes, there is an annual commitment fee for an
irrevocable letter of credit. Under certain circumstances, the letter of credit
is available for the payment of interest on, or redemption of, all or a portion
of the notes.
Long-Term Debt as of December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
-----------------------------
Interest Principal Outstanding
Rate Maturity 1998 1997
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
First mortgage bonds 5.90%-8.375% 1999-2038 $743,000 (a) $ 778,000(b)
Pollution control notes Adjustable (c) 2009-2030 417,985 417,985
Sinking fund debentures 5.00% 2010 2,791 2,791
Term loans 6.47%-7.47% 2000-2001 150,000 150,000
Economic development
revenue bonds 5.5%-8.75% 1999-2024 10,760 --
Term notes Adjustable (d) 2008 9,500 --
Miscellaneous 34,271 31,017
Less: Unamortized debt discount
and premium -- net (3,428) (3,672)
- ----------------------------------------------------------------------------------------------------
Total Long-Term Debt $1,364,879 $1,376,121
====================================================================================================
</TABLE>
(a) Excludes $75.0 million related to current maturities during 1999.
(b) Excludes $75.0 million related to current maturities during 1998.
(c) The pollution control notes have adjustable interest rates. The interest
rates at year-end averaged 3.9 percent in 1998 and 3.9 percent in 1997.
(d) Term notes have variable rates, adjusted quarterly. The interest rate at
December 31, 1998, was 5.5 percent.
43
<PAGE>
At December 31, 1998, sinking fund requirements and maturities of long-term
debt outstanding for the next five years were $82.4 million in 1999, $167.1
million in 2000, $86.3 million in 2001, $1.2 million in 2002, and $101.1 million
in 2003.
Total interest and other charges were $110.2 million in 1998, $115.6 million
in 1997, and $110.3 million in 1996. Interest costs attributable to long-term
debt and other interest were $95.6 million, $101.2 million and $99.4 million in
1998, 1997 and 1996, respectively. Of these amounts, $2.2 million in 1998, $2.3
million in 1997 and $1.2 million in 1996 was capitalized as AFC. Debt discount
or premium and related issuance expenses are amortized over the lives of the
applicable issues.
At December 31, 1998, the fair value of the Company's 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 to the Company for debt of the same remaining maturities, was $1,467.6
million. The principal amount included in the Company's consolidated balance
sheet is $1,443.3 million.
At December 31, 1998 and 1997, the Company was in compliance with all of its
debt covenants.
L.
Preferred
and
Preference
Stock
Preferred and Preference Stock as of December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
-------------------------------------------------
1998 1997
Call Price -------------------------------------------------
Per Share Shares Amount Shares Amount
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Preferred Stock of DQE:
Series A Preferred Stock (a) -- 352,742 $35,274 15,480 $1,548
- ------------------------------------------------------------------------------------------------------------
Preferred Stock Series
of Subsidiaries:
3.75% (b) (c) $51.00 148,000 7,407 148,000 7,407
4.00% (b) (c) 51.50 549,709 27,486 549,709 27,486
4.10% (b) (c) 51.75 119,860 6,012 119,860 6,012
4.15% (b) (c) 51.73 132,450 6,643 132,450 6,643
4.20% (b) (c) 51.71 100,000 5,021 100,000 5,021
$2.10 (b) (c) 51.84 159,000 8,039 159,400 8,039
9.00% (d) -- 10 3,000 10 3,000
8.375% (e) -- 6,000,000 150,000 6,000,000 150,000
6.5% (f) -- 15 1,500 10 1,000
6.5% (g) -- 10 500 -- --
- ------------------------------------------------------------------------------------------------------------
Total Preferred Stock of Subsidiaries 215,608 214,608
- ------------------------------------------------------------------------------------------------------------
Preference Stock Series of Subsidiaries:
Plan Series A (c) (h) 36.90 779,394 26,914 799,456 28,295
- ------------------------------------------------------------------------------------------------------------
Deferred ESOP benefit (14,240) (16,400)
- ------------------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock $263,556 $228,051
============================================================================================================
</TABLE>
(a) Preferred Stock: 4,000,000 authorized shares; no par value; Convertible;
$100 liquidation preference per share
(b) Preferred stock: 4,000,000 authorized shares; $50 par value; cumulative;
$50 per share involuntary liquidation value
(c) Non-redeemable
(d) 500 authorized shares; $300,000 par value; involuntary liquidation value
$300,000 per share; mandatory redemption beginning August 2000
(e) Cumulative Monthly Income Preferred Securities, Series A (MIPS):
6,000,000 authorized shares; $25 involuntary liquidation value
(f) 1,500 authorized shares; $100,000 par value; $100,000 involuntary
liquidation value
(g) Preferred stock: 100 authorized shares; $50,000 par value; $50,000 per share
involuntary liquidation value
(h) Preference stock: 8,000,000 authorized shares; $1 par value; cumulative
$35.50 per share involuntary liquidation value
In July 1997, the Company authorized and registered 1,000,000 shares of DQE
Preferred Stock. As of December 31, 1998, 352,742 shares of DQE Preferred Stock
had been issued and were outstanding. An additional 29,928 shares of DQE
Preferred Stock were issued in January and February 1999. The DQE Preferred
Stock ranks senior to the Company's common stock as to the payment of dividends
and the distribution of assets on liquidations, dissolution or winding-up of the
Company. Holders of DQE Preferred Stock are entitled to vote on all matters
submitted to a vote of the holders of DQE common stock, voting together with the
holders of common stock as a single class. Each share of DQE Preferred Stock is
entitled to three votes. Each share of DQE Preferred Stock is convertible at the
Company's option into the number of shares of DQE common stock computed by
dividing the DQE Preferred Stock's $100 liquidation value by the five-day
average
44
<PAGE>
closing sales price of DQE common stock for the five trading days immediately
prior to the conversion date. Each unredeemed share of DQE Preferred Stock will
automatically be converted on the first day of the first month commencing after
the sixth anniversary of its issuance.
Dividends on DQE Preferred Stock are paid quarterly on each January 1, April
1, July 1 and October 1. 11,720 shares of DQE Preferred Stock are entitled to an
annual dividend of 4.3 percent, comprising a quarterly dividend of $1.075 per
share. 3,760 shares are entitled to an annual dividend of 4.2 percent,
comprising a quarterly dividend of $1.05 per share. 250,400 shares are entitled
to an annual dividend of 4.0 percent, comprising a quarterly dividend of $1.00
per share. 3,120 shares are entitled to an annual dividend of 3.4 percent,
comprising a quarterly dividend of $.85 per share. 107,543 shares (including
23,960 shares issued in January 1999) are entitled to an annual dividend of 3.6
percent, comprising a quarterly dividend of $.90 per share. 5,968 shares issued
in February 1999 are entitled to an annual dividend of 3.8 percent, comprising a
quarterly dividend of $.95 per share.
In June 1998, a DQE subsidiary issued 10 shares of preferred stock, par value
$50,000 per share. The holders of such shares are entitled to a 6.5 percent
annual dividend to be paid each September.
A Duquesne subsidiary has 15 shares of preferred stock, par value $100,000
per share, outstanding. The holders of such shares are entitled to a 6.5 percent
annual dividend to be paid each September 30. In 1995, another Duquesne
subsidiary issued 10 shares of preferred stock, par value $300,000 per share.
The holders of such shares are entitled to a 9.0 percent annual dividend paid
quarterly.
In May 1996, Duquesne Capital L.P. (Duquesne Capital), a special-purpose
limited partnership of which Duquesne is 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 Duquesne's 8 3/8 percent debentures, with a
principal amount of $151.5 million. These debt securities may be redeemed at
Duquesne's option on or after May 31, 2001. Duquesne has guaranteed the payment
of distributions on, and redemption price and liquidation amount in respect of
the MIPS, to the extent that Duquesne Capital has funds available for such
payment from the debt securities. Upon maturity or prior redemption of such debt
securities, the MIPS will be mandatorily redeemed. The Company's consolidated
balance sheet reflects only the $150.0 million of MIPS.
Holders of Duquesne's 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
Duquesne's board of directors until all dividends have been paid. Holders of
Duquesne's 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 Duquesne's directors until all
dividends have been paid. At December 31, 1998, Duquesne had made all dividend
payments. Preferred and preference dividends of subsidiaries included in
interest and other charges were $16.7 million, $16.7 million and $12.1 million
in 1998, 1997 and 1996. Total preferred and preference stock had involuntary
liquidation values of $278.4 million and $244.4 million, which exceeded par by
$26.9 million and $27.6 million at December 31, 1998 and 1997.
In December 1991, the Company 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 N, on page 46.) The
Company issued and sold 845,070 shares of preference stock, plan series A to the
trustee of the ESOP. As consideration for the stock, the Company 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,
1998, $14.2 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 the Company are used to fund the repayment of the
ESOP note. The Company was not required to make a cash contribution for 1998.
The Company made cash contributions of approximately $1.1 million for 1997 and
$1.4 million for 1996. These cash contributions were the difference between the
ESOP debt service and the amount of dividends on ESOP shares ($2.2 million in
1998, $2.3 million in 1997 and 1996). As shares of preference stock are
allocated to the accounts of participants in the ESOP, the Company recognizes
compensation expense, and the amount of the deferred compensation benefit is
amortized. The Company recognized compensation expense related to the 401(k)
plans of $1.6 million in 1998, $3.2 million in 1997 and $2.3 million in 1996.
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 Duquesne
preferred or preference stock issues has mandatory purchase requirements.
45
<PAGE>
M.
Equity
Changes in the Number of Shares of DQE Common Stock Outstanding as of
December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Shares)
--------------------------------
1998 1997 1996
- -----------------------------------------------------------------------
<S> <C> <C> <C>
Outstanding as of January 1 77,680 77,273 77,556
Reissuance from treasury stock 70 408 157
Repurchase of common stock (377) (1) (440)
- -----------------------------------------------------------------------
Outstanding as of December 31 77,373 77,680 77,273
=======================================================================
</TABLE>
The Company has continuously paid dividends on common stock since 1953. The
Company's annualized dividends per share were $1.52, $1.44 and $1.36 at December
31, 1998, 1997 and 1996. During 1998, the Company paid a quarterly dividend of
$0.36 per share on each of January 1, April 1, July 1 and October 1. The
quarterly dividend declared in the fourth quarter of 1998 was increased from
$0.36 to $0.38 per share payable January 1, 1999. During 1997, the Company paid
a quarterly dividend of $0.34.
Once all dividends on the DQE Preferred Stock have been paid, dividends may
be paid on the Company's common stock to the extent permitted by law and as
declared by the board of directors. However, payments of dividends on Duquesne's
common stock may be restricted by Duquesne's obligations to holders of preferred
and preference stock pursuant to Duquesne's Restated Articles of Incorporation
and by obligations of Duquesne's subsidiaries to holders of their preferred
securities. No dividends or distributions may be made on Duquesne's common stock
if Duquesne has not paid dividends or sinking fund obligations on its preferred
or preference stock. Further, the aggregate amount of Duquesne's 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. As all of Duquesne's common stock is owned
by the Company, to the extent that Duquesne cannot pay common dividends, the
Company may not be able to pay dividends on its common stock or DQE Preferred
Stock. No part of the retained earnings of the Company was restricted at
December 31, 1998.
Effective December 31, 1998, the Company adopted SFAS No. 130, Reporting
Comprehensive Income (SFAS No. 130). 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,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
--------------------------------
1998 1997 1996
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at beginning of year $ 4,717 $ (2,551) $ (2,551)
Unrealized gains on securities, net of tax 637 7,268 --
- ---------------------------------------------------------------------------------------
Balance at end of year $ 5,354 $ 4,717 $ (2,551)
=======================================================================================
</TABLE>
In accordance with SFAS No. 115, Accounting for Certain Investments in Debt
and Equity Securities (SFAS No. 115), these investments are classified as
available-for-sale and are stated at market value. The amount of unrealized
holding gains related to marketable securities was $8.9 million ($5.4 million,
net of tax) at December 31, 1998, and $8.1 million ($4.7 million, net of tax) at
December 31, 1997.
N.
Employee
Benefits
Pension and Postretirement Benefits
The Company maintains retirement plans to provide pensions for all eligible
employees. Upon retirement, an 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. The Company's 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 $12.2 million for 1998, $12.7 million for 1997, and $11.9
million for 1996.
46
<PAGE>
In addition to pension benefits, the Company provides 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. Company-provided health care benefits
terminate when covered individuals become eligible for Medicare benefits or
reach age 65, whichever comes first. The Company funds actual expenditures for
obligations under the plans on a "pay-as-you-go" basis. The Company has the
right to modify or terminate the plans.
The Company accrues 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. The Company has elected to
amortize the transition obligation over a 20 year period.
In 1998, the Company adopted SFAS No. 132, Employers' Disclosures about
Pensions and Other Postretirement Benefits. This statement revises employers'
disclosures about pension and other postretirement benefit plans.
The Company sponsors several qualified and nonqualified pension plans and
other postretirement benefit plans for its 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, 1998, a
statement of the funded status as of December 31, 1998 and 1997, and summary of
assumptions used in the measurement of the Company's benefit obligation:
Funded Status of the Pension and Postretirement Benefit Plans as of
December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
----------------------------------------------
Pension Postretirement
----------------------------------------------
1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of year $ 554,302 $ 497,098 $ 46,330 $ 39,021
Service cost 14,042 12,340 1,832 1,603
Interest cost 37,723 36,571 3,078 3,048
Actuarial loss (gain) 26,231 26,117 (3,003) 2,299
Benefits paid (26,592) (25,612) (1,879) (1,424)
Curtailments -- 2,923 -- 1,783
Settlements (109) (544) -- --
Special termination benefits -- 5,409 -- --
- --------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year 605,597 554,302 46,358 46,330
- --------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of year 605,457 525,871 -- --
Actual return on plan assets 91,561 95,444 -- --
Employer contributions 10,706 9,675 -- --
Benefits paid (26,480) (25,533) -- --
- --------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 681,244 605,457 -- --
- --------------------------------------------------------------------------------------------------------------
Funded status 75,647 51,155 (46,358) (46,330)
Unrecognized net actuarial loss (gain) (173,974) (153,682) (1,795) 1,208
Unrecognized prior service cost 36,285 39,800 -- --
Unrecognized net transition obligation 10,227 12,039 23,607 25,294
- --------------------------------------------------------------------------------------------------------------
Accrued benefit cost $ (51,815) $ (50,688) $ (24,546) $ (19,828)
==============================================================================================================
</TABLE>
Weighted-Average Assumptions for the Year Ended December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Pension Postretirement
------------------------------------------
1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Discount rate used to determine projected
benefits obligation 6.50% 7.00% 6.50% 7.00%
Assumed rate of return on plan assets 7.50% 8.00% -- --
Assumed change in compensation levels 4.25% 4.75% -- --
Ultimate health care cost trend rate -- -- 5.00% 5.50%
</TABLE>
47
<PAGE>
All of the Company's plans for postretirement benefits, other than pensions,
have no plan assets. The aggregate benefit obligation for those plans was $46.4
million as of December 31, 1998, and $46.3 million as of December 31, 1997. 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.
Pension assets consist primarily of common stocks, United States obligations
and corporate debt securities.
Components of Net Pension Cost for the Year Ended December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
-------------------------------
1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Components of net pension cost:
Service cost $ 14,042 $ 12,340 $ 12,209
Interest cost 37,723 36,571 32,597
Actual return on plan assets (91,561) (95,444) (58,173)
Net amortization and deferrals 52,032 65,800 25,312
- -------------------------------------------------------------------------------------------------------------------
Net Pension Cost $ 12,236 $ 19,267 $ 11,945
===================================================================================================================
</TABLE>
Components of Postretirement Cost for the Year Ended December 31,
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
--------------------------------
1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Components of postretirement cost:
Service cost $ 1,832 $ 1,603 $ 1,182
Interest cost 3,078 3,048 2,046
Amortization of the transition obligation 1,687 1,686 1,700
Other -- 218 (812)
- -------------------------------------------------------------------------------------------------------------------
Total Postretirement Cost $ 6,597 $ 6,555 $ 4,116
===================================================================================================================
</TABLE>
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans.
Effect of a One Percent Change in Health Care Cost Trend Rates
for the Year Ended December 31, 1998
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(Thousands of Dollars)
----------------------
1 Percent 1 Percent
Increase Decrease
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Effect on total of service and interest cost components of
net periodic postretirement health care benefit cost $ 602 $ (521)
Effect on the health care component of the accumulated
postretirement benefit obligation $ 4,819 $(4,202)
</TABLE>
Retirement Savings Plan and Other Benefit Options
The Company sponsors separate 401(k) retirement plans for its management and
bargaining unit employees.
The 401(k) Retirement Savings Plan for Management Employees provides that
the Company will match employee contributions to a 401(k) account up to a
maximum of 6 percent of an employee's eligible salary. The Company 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. The 1998 incentive target for management was not
accomplished. The Company is funding its matching contributions to the 401(k)
Retirement Savings Plan for Management Employees with payments to an ESOP
established in December 1991. (See "Preferred and Preference Stock," Note L, on
page 44.)
48
<PAGE>
The 401(k) Retirement Savings Plan for IBEW Represented Employees provides
that the Company will match employee contributions to a 401(k) account up to a
maximum of 4 percent of an employee's eligible salary. The Company 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 1998, the incentive target for bargaining unit employees was
not accomplished.
The Company's shareholders have approved a long-term incentive plan, as
amended, through which the Company may grant management employees options to
purchase, during the years 1987 through 2006, up to a total of 9.9 million
shares of the Company's common stock at prices equal to the fair market value of
such stock on the dates the options were granted. At December 31, 1998,
approximately 3.8 million of these shares were available for future grants.
As of December 31, 1998, 1997 and 1996, active grants totaled 1,230,946;
1,084,041; and 1,698,000 shares. Exercise prices of these options ranged from
$15.8334 to $43.4375 at December 31, 1998; $15.8334 to $33.7813 at December 31,
1997; and from $8.2084 to $30.875 at December 31, 1996. Expiration dates of
these grants ranged from 2000 to 2008 at December 31, 1998; from 2000 to 2007 at
December 31, 1997; and from 1997 to 2006 at December 31, 1996. As of December
31, 1998, 1997 and 1996, stock appreciation rights (SARs) had been granted in
connection with 867,104; 635,995; and 984,000 of the options outstanding. 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. During 1996, 715,000 SARs
were exercised; 267,000 options were exercised at prices ranging from $8.2084 to
$20.3334; and 150 options were cancelled. Of the active grants at December 31,
1998, 1997 and 1996, 750,463; 402,816; and 668,000 were not exercisable.
O.
Business
Segments
and Related
Information
Effective December 31, 1998, the Company adopted SFAS No. 131, Disclosures
about Segments of an Enterprise and Related Information (SFAS No. 131). This
statement establishes standards for the way that public business enterprises
report information about operating segments. Operating segments are components
of an enterprise about which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance. This statement also establishes
standards for related disclosures about products and services, geographic areas,
and major customers.
Historically, Duquesne has been 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 which was
cost-based and was designed to recover the Company's operating expenses and
investment in electric utility assets and to provide a return on the investment.
As a result of the Customer Choice Act, generation of electricity will be
deregulated and charged at a separate rate from the delivery of electricity
beginning in 1999 (five percent of customers chose alternative generation
suppliers in 1998). For the purposes of complying with SFAS No. 131, the Company
is required to disclose information about its business segments separately.
Accordingly, the Company has used the PUC-approved separate rates for 1999 to
develop the financial information of the business segments for the periods ended
December 31, 1998, 1997 and 1996.
Beginning in 1999, the Company's principal business segments (determined by
products and services) will consist of the transmission and distribution by
Duquesne of electricity (electricity delivery business segment) and the
generation by Duquesne of electricity and collection of the CTC (electricity
generation business segment). To comply with SFAS No. 131, the Company has
reported the results for 1998, 1997 and 1996 by these business segments and an
"all other" category. The all other category in the following table includes the
expanded business lines and Duquesne investments below the quantitative
threshold for separate disclosure. These expanded business lines include water
utilities, energy products and services, electronic commerce, and other
activities. Intercompany eliminations primarily relate to intercompany sales of
electricity, property rental, management fees and dividends. Upon the
anticipated completion of the auction of the Company's generation assets and
provider of last resort services, the electricity generation business segment
will be comprised solely of the collection of the CTC.
Financial data for business segments is provided as follows:
49
<PAGE>
<TABLE>
<CAPTION>
Business Segments for the Year Ended December 31,
- ----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------------------------------------------
Electricity Electricity All
Delivery Generation Other Eliminations Consolidated
--------------------------------------------------------------
1998
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 321,484 $ 855,310 $ 106,432 $ (13,628) $1,269,598
Operating expenses 147,373 536,964 113,830 (17,591) 780,576
Depreciation and
amortization expense 47,388 160,243 9,525 -- 217,156
- ----------------------------------------------------------------------------------------------------
Operating income (loss) 126,723 158,103 (16,923) 3,963 271,866
Other income 5,284 9,020 128,883 (7,182) 136,005
Interest and other charges 37,711 58,637 14,730 (877) 110,201
- ----------------------------------------------------------------------------------------------------
Income before taxes and
extraordinary item 94,296 108,486 97,230 (2,342) 297,670
Income taxes 37,141 36,616 28,197 (972) 100,982
- ----------------------------------------------------------------------------------------------------
Income before
extraordinary item 57,155 71,870 69,033 (1,370) 196,688
Extraordinary item, net of tax -- (82,548) -- -- (82,548)
- ----------------------------------------------------------------------------------------------------
Net income (loss) after
extraordinary item $ 57,155 $ (10,678) $ 69,033 $ (1,370) $ 114,140
====================================================================================================
Assets $1,314,266 $2,711,533 $1,221,764 $ -- $5,247,563
====================================================================================================
Capital expenditures $ 71,699 $ 41,629 $ 77,220 $ -- $ 190,548
====================================================================================================
</TABLE>
<TABLE>
<CAPTION>
(Thousands of Dollars)
--------------------------------------------------------------
Electricity Electricity All
Delivery Generation Other Eliminations Consolidated
--------------------------------------------------------------
1997
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 316,938 $ 859,003 $ 64,769 $ (10,536) $1,230,174
Operating expenses 137,425 522,531 62,748 (16,110) 706,594
Depreciation and
amortization expense 45,652 192,592 4,599 -- 242,843
- ----------------------------------------------------------------------------------------------------
Operating income (loss) 133,861 143,880 (2,578) 5,574 280,737
Other income 6,844 12,723 119,185 (8,945) 129,807
Interest and other charges 38,612 63,805 14,093 (872) 115,638
- ----------------------------------------------------------------------------------------------------
Income before taxes 102,093 92,798 102,514 (2,499) 294,906
Income taxes 40,195 32,252 24,395 (1,037) 95,805
- ----------------------------------------------------------------------------------------------------
Net income $ 61,898 $ 60,546 $ 78,119 $ (1,462) $ 199,101
====================================================================================================
Assets $1,476,133 $2,201,229 $1,017,040 $ -- $4,694,402
====================================================================================================
Capital expenditures $ 57,646 $ 32,763 $ 25,595 $ -- $ 116,004
====================================================================================================
</TABLE>
<TABLE>
<CAPTION>
(Thousands of Dollars)
--------------------------------------------------------------
Electricity Electricity All
Delivery Generation Other Eliminations Consolidated
--------------------------------------------------------------
1996
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 308,826 $ 878,581 $ 58,894 $ (9,524) $1,236,777
Operating expenses 138,384 532,190 54,455 (14,186) 710,843
Depreciation and
amortization expense 45,415 172,870 4,643 -- 222,928
- ----------------------------------------------------------------------------------------------------
Operating income (loss) 125,027 173,521 (204) 4,662 303,006
Other income 5,209 9,806 71,152 (12,377) 73,790
Interest and other charges 37,197 63,359 11,056 (1,342) 110,270
- ----------------------------------------------------------------------------------------------------
Income before taxes 93,039 119,968 59,892 (6,373) 266,526
Income taxes 36,436 42,389 11,207 (2,644) 87,388
- ----------------------------------------------------------------------------------------------------
Net income $ 56,603 $ 77,579 $ 48,685 $ (3,729) $ 179,138
====================================================================================================
Assets $1,407,529 $2,355,294 $ 876,169 $ -- $4,638,992
====================================================================================================
Capital expenditures $ 52,514 $ 35,371 $ 13,265 $ -- $ 101,150
====================================================================================================
</TABLE>
50
<PAGE>
P. Quarterly Financial Information (Unaudited)
<TABLE>
<CAPTION>
Summary of Selected Quarterly Financial Data (Thousands of Dollars, Except Per Share Amounts)
- -----------------------------------------------------------------------------------------------------
[The quarterly data reflect seasonal weather variations in the electric utility's service territory.]
- -----------------------------------------------------------------------------------------------------
1998 First Quarter Second Quarter Third Quarter Fourth Quarter
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues (a) $298,775 $303,510 $347,770 $319,543
Operating income 61,817 64,949 83,242 61,858
Income before extraordinary item 45,130 40,204 62,069 49,285
Extraordinary item -- (82,548) -- --
Net income after extraordinary
item 45,130 (42,344) 62,069 49,285
Basic earnings per share:
Before extraordinary item 0.58 0.52 0.80 0.62
Extraordinary item -- (1.06) -- --
After extraordinary item 0.58 (0.54) 0.80 0.62
Diluted earnings per share:
Before extraordinary item 0.57 0.51 0.78 0.62
Extraordinary item -- (1.04) -- --
After extraordinary item 0.57 (0.53) 0.78 0.62
Stock price:
High 37 1/4 37 5/16 39 1/4 43 15/16
Low 32 5/16 31 5/8 34 1/4 37 3/4
====================================================================================================
1997 First Quarter Second Quarter Third Quarter Fourth Quarter
- -----------------------------------------------------------------------------------------------------
Operating revenues (a) $306,334 $287,850 $334,714 $301,276
Operating income 76,817 55,631 97,209 51,080
Net income 45,097 46,778 58,665 48,561
Basic earnings per share 0.58 0.61 0.75 0.63
Diluted earnings per share 0.57 0.60 0.75 0.62
Stock price:
High 29 7/8 29 33 9/16 35 1/8
Low 27 3/4 26 7/8 31 7/16 30 7/16
====================================================================================================
</TABLE>
(a) Restated to conform with 1998 presentation.
51
<PAGE>
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 the Directors of DQE is set forth in the Proxy
Statement for the DQE Annual Meeting of Shareholders to be held April 27, 1999.
The information is incorporated here by reference. All Directors of DQE are also
Directors of Duquesne Light Company. Information relating to the executive
officers is set forth in Part I of this Report under the caption "Executive
Officers of the Registrant."
Item 11. Executive Compensation.
Information relating to executive compensation is set forth in the Proxy
Statement for the DQE Annual Meeting of Shareholders to be held April 27, 1999.
The information is incorporated here by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Information relating to the ownership of equity securities of DQE by DQE
directors, officers and certain beneficial owners is set forth under the caption
"Beneficial Ownership of Stock" in the Proxy Statement for the DQE Annual
Meeting of Shareholders to be held April 27, 1999. Information is incorporated
here by reference.
Item 13. Certain Relations and Related Transactions.
None.
52
<PAGE>
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 25 through 51 of this
Report. The following financial statements and Report of Independent Certified
Public Accountants are incorporated here by reference:
Report of Independent Certified Public Accountants.
Statement of Consolidated Income for the Three Years Ended December 31, 1998.
Consolidated Balance Sheet, December 31, 1997 and 1998.
Statement of Consolidated Cash Flows for the Three Years Ended December 31,
1998.
Statement of Consolidated Retained Earnings for the Three Years Ended
December 31, 1998.
Notes to Consolidated Financial Statements.
(a)(2) The following financial statement schedule and the related Report of
Independent Certified Public Accountants are filed here as a part of this
Report:
Schedule for the Three Years Ended December 31, 1998:
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) Two reports on Form 8-K were filed during the fiscal quarter ended
December 31, 1998, and two were filed thereafter.
A report was filed October 5, 1998, to report the Company's termination
of the merger agreement with AYE. No financial statements were filed
with this report.
A report was filed October 15, 1998, to report the execution by
Duquesne and FirstEnergy Corporation of an agreement in principle to
exchange interests in certain power stations. No financial statements
were filed with this report.
A report was filed March 19, 1999, to report the consent agreement
entered into by DQE and AYE. No financial statements were filed with
this report.
A report was filed March 26, 1999, to report the execution of
definitive power station exchange agreements. No financial statements
were filed this report.
53
<PAGE>
Exhibit Index
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
2.1 Generation Exchange Agreement by and between Duquesne Exhibit 2.1 to the Form 8-K
Light Company, on the one hand, and The Cleveland Current Report of DQE
Electric Illuminating Company, Ohio Edison Company and dated March 26, 1999.
Pennsylvania Power Company, on the other, dated as of
March 25, 1999.
2.2 Nuclear Generation Conveyance Agreement by and between Exhibit 2.2 to the Form 8-K
Duquesne Light Company, on the one hand, and Pennsylvania Current Report of DQE
Power Company and the Cleveland Electric Illuminating dated March 26, 1999.
Company, on the other, dated as of March 25, 1999.
3.1 Articles of Incorporation of DQE effective January 5, 1989. Exhibit 3.1 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1989.
3.2 Articles of Amendment of DQE effective April 27, 1989. Exhibit 3.2 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1989.
3.3 Articles of Amendment of DQE effective February 8, 1993. Exhibit 3.3 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1992.
3.4 Articles of Amendment of DQE effective May 24, 1994. Exhibit 3.4 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1994.
3.5 Articles of Amendment of DQE effective April 20, 1995. Exhibit 3.5 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1995.
3.6 Statement with respect to the Preferred Stock, Series A Exhibit 3.1 to the Form 10-Q
(Convertible), as filed with the Pennsylvania Department Quarterly Report of DQE
of State on August 29, 1997. for the quarter ended
September 30, 1997.
3.7 By-Laws of DQE, as amended through December 18, 1996 Exhibit 3.6 to the Form 10-K
and as currently in effect. Annual Report of DQE for the
year ended December 31, 1997.
4.1 Indenture dated March 1, 1960, relating to Duquesne Exhibit 4.3 to the Form 10-K
Light Company's 5% Sinking Fund Debentures. Annual Report of DQE for the
year ended December 31, 1989.
4.2 Indenture of Mortgage and Deed of Trust dated as of Exhibit 4.3 to Registration
April 1, 1992, securing Duquesne Light Company's Statement (Form S-3)
First Collateral Trust Bonds. No. 33-52782.
4.3 Supplemental Indentures supplementing the said
Indenture of Mortgage and Deed of Trust -
Supplemental Indenture No. 1. Exhibit 4.4 to Registration
Statement (Form S-3)
No. 33-52782.
</TABLE>
54
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
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.
4.4 Amended and Restated Agreement of Limited Partnership Exhibit 4.4 to the Form 10-K
of Duquesne Capital L.P., dated as of May 14, 1996. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
4.5 Payment and Guarantee Agreement, dated as of May 14, Exhibit 4.5 to the Form 10-K
1996, by Duquesne Light Company with respect to MIPS. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
4.6 Indenture, dated as of May 1, 1996, by Duquesne Light Exhibit 4.6 to the Form 10-K
Company to the First National Bank of Chicago as Trustee. Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
10.1 Deferred Compensation Plan for the Directors of Exhibit 10.1 to the Form 10-K
Duquesne Light Company, as amended to date. Annual Report of DQE for the
year ended December 31, 1992.
</TABLE>
55
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
10.2 Incentive Compensation Program for Certain Executive Exhibit 10.2 to the Form 10-K
Officers of Duquesne Light Company, as amended to Annual Report of DQE for the
date. 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 DQE, Inc. 1996 Stock Plan for Non-Employee Directors. Exhibit 10.5 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1996.
10.6 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.
10.7 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.
10.8 Employment Agreement dated as of August 30, 1994 Exhibit 10.9 to the Form 10-K
between DQE, Duquesne Light Company and Annual Report of DQE for the
David D. Marshall. year ended December 31, 1994.
10.9 First Amendment dated as of June 27, 1995 to Exhibit 10.68 to the Form 10-K
Employment Agreement dated as of August 30, 1994 Annual Report of Duquesne
between DQE, Duquesne Light Company and Light Company for the year
David D. Marshall. ended December 31, 1995.
10.10 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.
10.11 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, James D. Mitchell and James E. Cross.
10.12 Schedule to Non-Competition and Confidentiality Filed here.
Agreement dated as of October 3, 1996 (Exhibit 10.14
to the Form 10-K Annual Report of DQE for the year
ended December 31, 1996) listing a substantially identical
agreement with William J. DeLeo.
</TABLE>
56
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
10.13 Severance Agreement dated April 4, 1997, between the Exhibit 10.1 to the Form 10-Q
Company and David D. Marshall, together with a schedule Quarterly Report of DQE for
describing substantially identical agreements with Gary L. the quarter ended March 31,
Schwass, Victor A. Roque, James E. Cross and James D. 1997.
Mitchell.
10.14 Schedule to Severance Agreement dated April 4, 1997 Filed here.
(Exhibit 10.1 to the Form 10-Q Quarterly Report of DQE
for the quarter ended March 31, 1997) listing a
substantially identical agreement with William J. DeLeo.
10.15 Stock Purchase Agreement among Duquesne Enterprises, Exhibit 10.2 to the Form 10-Q
Inc., Chester Engineers, Inc., and Chester Acquisition Quarterly Report of DQE for
Corporation, dated March 17, 1997, as amended April 30, the quarter ended March 31,
1997. 1997.
10.16 Securities Purchase Agreement, dated as of May 28, 1997, Exhibit A to Schedule 13D of
among SatCon Technology Corporation, Beacon Power Duquesne Enterprises, Inc.
Corporation and Duquesne Enterprises,Inc. filed on June 9, 1997.
<CAPTION>
Agreements relating to Jointly Owned Generating Units:
<S> <C> <C>
10.17 Administration Agreement dated as of September 14, 1967. Exhibit 5.8 to Registration
Statement (Form S-7)
No. 2-43106.
10.18 Transmission Facilities Agreement dated as of Exhibit 5.9 to Registration
September 14, 1967. Statement (Form S-7)
No. 2-43106.
10.19 Operating Agreement dated as of September 21, 1972 Exhibit 5.1 to Registration
for Eastlake Unit No. 5. Statement (Form S-7)
No. 2-48164.
10.20 Memorandum of Agreement dated as of July 1, 1982 re Exhibit 10.14 to the Form 10-K
reallocation of rights and liabilities of the companies Annual Report of Duquesne
under uranium supply contracts. Light Company for the year
ended December 31, 1987.
10.21 Operating Agreement dated August 5, 1982 as of Exhibit 10.17 to the Form 10-K
September 1, 1971 for Sammis Unit No. 7. Annual Report of Duquesne
Light Company for the year
ended December 31, 1988.
10.22 Memorandum of Understanding dated as of March 31, Exhibit 10.19 to the Form 10-K
1985 re implementation of company-by-company Annual Report of DQE for the
management of uranium inventory and delivery. year ended December 31, 1989.
10.23 Restated Operating Agreement for Beaver Valley Unit Exhibit 10.23 to the Form 10-K
Nos. 1 and 2 dated September 15, 1987. Annual Report of Duquesne
Light Company for the year
ended December 31, 1987.
</TABLE>
57
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
10.24 Operating Agreement for Perry Unit No. 1 dated Exhibit 10.24 to the Form 10-K
March 10, 1987. Annual Report of Duquesne
Light Company for the year
ended December 31, 1987.
10.25 Operating Agreement for Bruce Mansfield Units Nos. 1, Exhibit 10.25 to the Form 10-K
2 and 3 dated September 15, 1987 as of June 1, 1976. Annual Report of Duquesne
Light Company for the year
ended December 31, 1987.
10.26 Basic Operating Agreement, as amended January 1, 1993. Exhibit 10.10 to the Form 10-K
Annual Report of Duquesne
Light Company for the year
ended December 31, 1993.
10.27 Amendment No. 1 dated December 23, 1993 to Exhibit 10.11 to the Form 10-K
Transmission Facilities Agreement (as of January 1, 1993). Annual Report of Duquesne
Light Company for the year
ended December 31, 1993.
10.28 Microwave Sharing Agreement (as amended Exhibit 10.12 to the Form 10-K
January 1, 1993) dated December 23, 1993. Annual Report of Duquesne
Light Company for the year
ended December 31, 1993.
10.29 Agreement (as of September 1, 1980) dated Exhibit 10.13 to the Form 10-K
December 23, 1993 for termination or construction Annual Report of Duquesne
of certain agreements. Light Company for the year
ended December 31, 1993.
<CAPTION>
Agreements relating to the Sale and Leaseback
of Beaver Valley Unit No. 2:
<S> <C> <C>
10.30 Order of the Pennsylvania Public Utility Commission Exhibit 28.2 to the Form 10-Q
dated September 25, 1987 regarding the application Quarterly Report of Duquesne
of the Duquesne Light Company under Section 1102(a)(3) Light Company for the quarter
of the Public Utility Code for approval in connection with ended September 30, 1987.
the sale and leaseback of its interest in Beaver Valley Unit
No. 2.
10.31 Order of the Pennsylvania Public Utility Commission Exhibit 10.28 to the Form 10-K
dated October 15, 1992 regarding the Securities Annual Report of Duquesne
Certificate of Duquesne Light Company for the Light Company for the year
assumption of contingent obligations under ended December 31, 1992.
financing agreements in connection with the
refunding of Collateralized Lease Bonds.
x10.32 Facility Lease dated as of September 15, 1987 between Exhibit (4)(c) to Registration
The First National Bank of Boston, as Owner Trustee Statement (Form S-3)
under a Trust Agreement dated as of September 15, 1987 No. 33-18144.
with the limited partnership Owner Participant named
therein, Lessor, and Duquesne Light Company, Lessee.
</TABLE>
58
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
y10.33 Facility Lease dated as of September 15, 1987 between Exhibit (4)(d) to Registration
The First National Bank of Boston, as Owner Trustee Statement (Form S-3)
under a Trust Agreement dated as of September 15, 1987, No. 33-18144.
with the corporate Owner Participant named therein,
Lessor, and Duquesne Light Company, Lessee.
x10.34 Amendment No. 1 dated as of December 1, 1987 to Exhibit 10.30 to the Form 10-K
Facility Lease dated as of September 15, 1987 between Annual Report of Duquesne
The First National Bank of Boston, as Owner Trustee Light Company for the year
under a Trust Agreement dated as of September 15, 1987 ended December 31, 1987.
with the limited partnership Owner Participant named
therein, Lessor, and Duquesne Light Company, Lessee.
y10.35 Amendment No. 1 dated as of December 1, 1987 to Exhibit 10.31 to the Form 10-K
Facility Lease dated as of September 15, 1987 between Annual Report of Duquesne
The First National Bank of Boston, as Owner Trustee Light Company for the year
under a Trust Agreement dated as of September 15, 1987 ended December 31, 1987.
with the corporate Owner Participant named therein,
Lessor, and Duquesne Light Company, Lessee.
x10.36 Amendment No. 2 dated as of November 15, 1992 to Exhibit 10.33 to the Form 10-K
Facility Lease dated as of September 15, 1987 between Annual Report of Duquesne
The First National Bank of Boston, as Owner Trustee Light Company for the year
under a Trust Agreement dated as of September 15, 1987 ended December 31, 1992.
with the limited partnership Owner Participant named
therein, Lessor, and Duquesne Light Company, Lessee.
y10.37 Amendment No. 2 dated as of November 15, 1992 to Exhibit 10.34 to the Form 10-K
Facility Lease dated as of September 15, 1987 between Annual Report of Duquesne
The First National Bank of Boston, as Owner Trustee Light Company for the year
under a Trust Agreement dated as of September 15, 1987 ended December 31, 1992.
with the corporate Owner Participant named therein,
Lessor, and Duquesne Light Company, Lessee.
x10.38 Amendment No. 3 dated as of October 13, 1994 to Exhibit 10.25 to the Form 10-K
Facility Lease dated as of September 15, 1987 between Annual Report of Duquesne
The First National Bank of Boston, as Owner Trustee Light Company for the year
under a Trust Agreement dated as of September 15, 1987 ended December 31, 1994.
with the limited partnership Owner Participant named
therein, Lessor, and Duquesne Light Company, Lessee.
y10.39 Amendment No. 3 dated as of October 13, 1994 to Exhibit 10.26 to the Form 10-K
Facility Lease dated as of September 15, 1987 between Annual Report of Duquesne
The First National Bank of Boston, as Owner Trustee Light Company for the year
under a Trust Agreement dated as of September 15, 1987 ended December 31, 1994.
with the corporate Owner Participant named therein,
Lessor, and Duquesne Light Company, Lessee.
</TABLE>
59
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
x10.40 Participation Agreement dated as of September 15, Exhibit (28)(a) to Registration
1987 among the limited partnership Owner Statement (Form S-3)
Participant named therein, the Original Loan No. 33-18144.
Participants listed in Schedule 1 thereto, as Original
Loan Participants, DQU Funding Corporation, as Funding
Corp, The First National Bank of Boston, as Owner
Trustee, Irving Trust Company, as Indenture Trustee and
Duquesne Light Company, as Lessee.
y10.41 Participation Agreement dated as of September 15, Exhibit (28)(b) to Registration
1987 among the corporate Owner Participant named Statement (Form S-3)
therein, the Original Loan Participants listed in No. 33-18144.
Schedule 1 thereto, as Original Loan Participants, DQU
Funding Corporation, as Funding Corp, The First
National Bank of Boston, as Owner Trustee, Irving
Trust Company, as Indenture Trustee and Duquesne
Light Company, as Lessee.
x10.42 Amendment No. 1 dated as of December 1, 1987 to Exhibit 10.34 to the Form 10-K
Participation Agreement dated as of September 15, Annual Report of Duquesne
1987 among the limited partnership Owner Participant Light Company for the year
named therein, the Original Loan Participants listed ended December 31, 1987.
therein, as Original Loan Participants, DQU
Funding Corporation, as Funding Corp, The First
National Bank of Boston, as Owner Trustee, Irving
Trust Company, as Indenture Trustee and Duquesne
Light Company, as Lessee.
y10.43 Amendment No. 1 dated as of December 1, 1987 to Exhibit 10.35 to the Form 10-K
Participation Agreement dated as of September 15, Annual Report of Duquesne
1987 among the corporate Owner Participant named Light Company for the year
therein, the Original Loan Participants listed therein, ended December 31, 1987.
as Original Loan Participants, DQU Funding
Corporation, as Funding Corp, The First
National Bank of Boston, as Owner Trustee, Irving
Trust Company, as Indenture Trustee and Duquesne
Light Company, as Lessee.
x10.44 Amendment No. 2 dated as of March 1, 1988 to Exhibit (28)(c)(3) to
Participation Agreement dated as of September 15, Registration Statement
1987 among the limited partnership Owner Participant (Form S-3) No. 33-54648.
named therein, DQU Funding Corporation, as Funding
Corp, The First National Bank of Boston, as Owner
Trustee, Irving Trust Company, as Indenture Trustee and
Duquesne Light Company, as Lessee.
</TABLE>
60
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
y10.45 Amendment No. 2 dated as of March 1, 1988 to Exhibit (28)(c)(4) to
Participation Agreement dated as of September 15, Registration Statement
1987 among the corporate Owner Participant named (Form S-3) No. 33-54648.
therein, DQU Funding Corporation, as Funding Corp,
The First National Bank of Boston, as Owner Trustee,
Irving Trust Company, as Indenture Trustee and Duquesne
Light Company, as Lessee.
x10.46 Amendment No. 3 dated as of November 15, 1992 to Exhibit 10.41 to the Form 10-K
Participation Agreement dated as of September 15, Annual Report of Duquesne
1987 among the limited partnership Owner Participant Light Company for the year
named therein, DQU Funding Corporation, as Funding ended December 31, 1992.
Corp, DQU II Funding Corporation, as New Funding
Corp, The First National Bank of Boston, as Owner
Trustee, The Bank of New York, as Indenture Trustee and
Duquesne Light Company, as Lessee.
y10.47 Amendment No. 3 dated as of November 15, 1992 to Exhibit 10.42 to the Form 10-K
Participation Agreement dated as of September 15, Annual Report of Duquesne
1987 among the corporate Owner Participant named Light Company for the year
therein, DQU Funding Corporation, as Funding Corp, ended December 31, 1992.
DQU II Funding Corporation, as New Funding Corp,
The First National Bank of Boston, as Owner Trustee, The
Bank of New York, as Indenture Trustee and Duquesne Light
Company, as Lessee.
x10.48 Amendment No. 4 dated as of October 13, 1994 to Exhibit 10.35 to the Form 10-K
Participation Agreement dated as of September 15, 1987 Annual Report of Duquesne
among the limited partnership Owner Participant named Light Company for the year
therein, DQU Funding Corporation, as Funding Corp, ended December 31, 1994.
DQU II Funding Corporation, as New Funding Corp,
The First National Bank of Boston, as Owner Trustee,
The Bank of New York, as Indenture Trustee and Duquesne
Light Company, as Lessee.
y10.49 Amendment No. 4 dated as of October 13, 1994 to Exhibit 10.36 to the Form 10-K
Participation Agreement dated as of September 15, 1987 Annual Report of Duquesne
among the corporate Owner Participant named therein, Light Company for the year
DQU Funding Corporation, as Funding Corp, DQU II ended December 31, 1994.
Funding Corporation, as New Funding Corp, The First
National Bank of Boston, as Owner Trustee, The Bank of
New York, as Indenture Trustee and Duquesne Light
Company, as Lessee.
z10.50 Ground Lease and Easement Agreement dated as of Exhibit (28)(e) to Registration
September 15, 1987 between Duquesne Light Company, Statement (Form S-3)
Ground Lessor and Grantor, and The First National Bank No. 33-18144.
of Boston, as Owner Trustee under a Trust Agreement
dated as of September 15, 1987 with the limited
partnership Owner Participant named therein, Tenant
and Grantee.
</TABLE>
61
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
z10.51 Assignment, Assumption and Further Agreement dated as Exhibit (28)(f) to Registration
of September 15, 1987 among The First National Bank of Statement (Form S-3)
Boston, as Owner Trustee under a Trust Agreement dated No. 33-18144.
as of September 15, 1987 with the limited partnership
Owner Participant named therein, The Cleveland Electric
Illuminating Company, Duquesne Light Company, Ohio
Edison Company, Pennsylvania Power Company and The
Toledo Edison Company.
z10.52 Additional Support Agreement dated as of September 15, Exhibit (28)(g) to Registration
1987 between The First National Bank of Boston, as Statement (Form S-3)
Owner Trustee under a Trust Agreement dated as of No. 33-18144.
September 15, 1987 with the limited partnership Owner
Participant named therein, and Duquesne Light Company.
z10.53 Indenture, Bill of Sale, Instrument of Transfer and Exhibit (28)(h) to Registration
Severance Agreement dated as of October 2, 1987 Statement (Form S-3)
between Duquesne Light Company, Seller, and The No. 33-18144.
First National Bank of Boston, as Owner Trustee under
a Trust Agreement dated as of September 15, 1987 with
the limited partnership Owner Participant named therein,
Buyer.
z10.54 Tax Indemnification Agreement dated as of September 15, Exhibit 28.1 to the Form 8-K
1987 between the Owner Participant named therein and Current Report of Duquesne
Duquesne Light Company, as Lessee. Light Company dated
November 20, 1987.
z10.55 Amendment No. 1 dated as of November 15, 1992 to Exhibit 10.48 to the Form 10-K
Tax Indemnification Agreement dated as of September 15, Annual Report of Duquesne
1987 between the Owner Participant named therein and Light Company for the year
Duquesne Light Company, as Lessee. ended December 31, 1992.
z10.56 Amendment No. 2 dated as of October 13, 1994 to Tax Exhibit 10.43 to the Form 10-K
Indemnification Agreement dated as of September 15, Annual Report of Duquesne
1987 between the Owner Participant named therein and Light Company for the year
Duquesne Light Company, as Lessee. ended December 31, 1994.
z10.57 Extension Letter dated December 8, 1992 from Exhibit 10.49 to the Form 10-K
Duquesne Light Company, each Owner Participant, The Annual Report of Duquesne
First National Bank of Boston, the Lease Indenture Light Company for the year
Trustee, DQU Funding Corporation and DQU II ended December 31, 1992.
Funding Corporation addressed to the New Collateral
Trust Trustee extending their respective representations
and warranties and covenants set forth in each of the
Participation Agreements.
</TABLE>
62
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
x10.58 Trust Indenture, Mortgage, Security Agreement and Exhibit (4)(g) to Registration
Assignment of Facility Lease dated as of September 15, Statement (Form S-3)
1987 between The First National Bank of Boston, as No. 33-18144.
Owner Trustee under a Trust Agreement dated as of
September 15, 1987 with the limited partnership Owner
Participant named therein, and Irving Trust Company,
as Indenture Trustee.
y10.59 Trust Indenture, Mortgage, Security Agreement and Exhibit (4)(h) to Registration
Assignment of Facility Lease dated as of September 15, Statement (Form S-3)
1987 between The First National Bank of Boston, as No. 33-18144.
Owner Trustee under a Trust Agreement dated as of
September 15, 1987 with the corporate Owner
Participant named therein, and Irving Trust Company,
as Indenture Trustee.
x10.60 Supplemental Indenture No. 1 dated as of December 1, Exhibit 10.45 to the Form 10-K
1987 to Trust Indenture, Mortgage, Security Agreement Annual Report of Duquesne
and Assignment of Facility Lease dated as of September 15, Light Company for the year
1987 between The First National Bank of Boston, as Owner ended December 31, 1987.
Trustee under a Trust Agreement dated as of September 15,
1987 with the limited partnership Owner Participant
named therein, and Irving Trust Company, as Indenture
Trustee.
y10.61 Supplemental Indenture No. 1 dated as of December 1, Exhibit 10.46 to the Form 10-K
1987 to Trust Indenture, Mortgage, Security Agreement Annual Report of Duquesne
and Assignment of Facility Lease dated as of September 15, Light Company for the year
1987 between The First National Bank of Boston, as ended December 31, 1987.
Owner Trustee under a Trust Agreement dated as of
September 15, 1987 with the corporate Owner
Participant named therein, and Irving Trust Company,
as Indenture Trustee.
x10.62 Supplemental Indenture No. 2 dated as of November 15, Exhibit 10.54 to the Form 10-K
1992 to Trust Indenture, Mortgage, Security Agreement Annual Report of Duquesne
and Assignment of Facility Lease dated as of September 15, Light Company for the year
1987 between The First National Bank of Boston, as ended December 31, 1992.
Owner Trustee under a Trust Agreement dated as of
September 15, 1987 with the limited partnership Owner
Participant named therein, and The Bank of New York,
as Indenture Trustee.
</TABLE>
63
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
y10.63 Supplemental Indenture No. 2 dated as of November 15, Exhibit 10.55 to the Form 10-K
1992 to Trust Indenture, Mortgage, Security Agreement Annual Report of Duquesne
and Assignment of Facility Lease dated as of September 15, Light Company for the year
1987 between The First National Bank of Boston, as ended December 31, 1992.
Owner Trustee under a Trust Agreement dated as of
September 15, 1987 with the corporate Owner
Participant named therein, and The Bank of New York,
as Indenture Trustee.
10.64 Reimbursement Agreement dated as of October 1, 1994 Exhibit 10.51 to the Form 10-K
among Duquesne Light Company, Swiss Bank Annual Report of Duquesne
Corporation, New York Branch, as LOC Bank, Union Light Company for the year
Bank, as Administrating Bank, Swiss Bank ended December 31, 1994.
Corporation, New York Branch, as Administrating Bank
and The Participating Banks Named Therein.
10.65 Collateral Trust Indenture dated as of November 15, Exhibit 10.58 to the Form 10-K
1992 among DQU II Funding Corporation, Duquesne Annual Report of Duquesne
Light Company and The Bank of New York, as Trustee. Light Company for the year
ended December 31, 1992.
10.66 First Supplemental Indenture dated as of November 15, Exhibit 10.59 to the Form 10-K
1992 to Collateral Trust Indenture dated as of November Annual Report of Duquesne
15, 1992 among DQU II Funding Corporation, Duquesne Light Light Company for the year
Company and The Bank of New York, as Trustee. ended December 31, 1992.
x10.67 Refinancing Agreement dated as of November 15, 1992 Exhibit 10.60 to the Form 10-K
among the limited partnership Owner Participant Annual Report of Duquesne
named therein, as Owner Participant, DQU Funding Light Company for the year
Corporation, as Funding Corp, DQU II Funding ended December 31, 1992.
Corporation, as New Funding Corp, The First
National Bank of Boston, as Owner Trustee, The Bank
of New York, as Indenture Trustee, The Bank of New
York, as Collateral Trust Trustee, The Bank of New York,
as New Collateral Trust Trustee, and Duquesne Light
Company, as Lessee.
y10.68 Refinancing Agreement dated as of November 15, 1992 Exhibit 10.61 to the Form 10-K
among the corporate Owner Participant named Annual Report of Duquesne
therein, as Owner Participant, DQU Funding Light Company for the year
Corporation, as Funding Corp, DQU II Funding ended December 31, 1992.
Corporation, as New Funding Corp, The First
National Bank of Boston, as Owner Trustee, The Bank
of New York, as Indenture Trustee, The Bank of New
York, as Collateral Trust Trustee, The Bank of New York,
as New Collateral Trust Trustee, and Duquesne Light
Company, as Lessee.
</TABLE>
64
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
x10.69 Addendum dated December 8, 1992 to Refinancing Exhibit 10.62 to the Form 10-K
Agreement dated as of November 15, 1992 among the Annual Report of Duquesne
limited partnership Owner Participant named therein, Light Company for the year
as Owner Participant, DQU Funding Corporation, as ended December 31, 1992.
Funding Corp, DQU II Funding Corporation, as New
Funding Corp, The First National Bank of Boston, as
Owner Trustee, The Bank of New York, as Indenture
Trustee, The Bank of New York, as Collateral Trust
Trustee, The Bank of New York, as New Collateral
Trust Trustee, and Duquesne Light Company, as Lessee.
y10.70 Addendum dated December 8, 1992 to Refinancing Exhibit 10.63 to the Form 10-K
Agreement dated as of November 15, 1992 among the Annual Report of Duquesne
corporate Owner Participant named therein, as Light Company for the year
Owner Participant, DQU Funding Corporation, as ended December 31, 1992.
Funding Corp, DQU II Funding Corporation, as New
Funding Corp, The First National Bank of Boston, as
Owner Trustee, The Bank of New York, as Indenture
Trustee, The Bank of New York, as Collateral Trust
Trustee, The Bank of New York, as New Collateral
Trust Trustee, and Duquesne Light Company, as Lessee.
<CAPTION>
Other Agreements
<S> <C> <C>
10.71 Form of Stock Purchase Agreement between AquaSource Filed here.
and each Class B Stockholder, dated February 16, 1999.
12.1 Ratio of Earnings to Fixed Charges. Filed here.
</TABLE>
65
<PAGE>
<TABLE>
<CAPTION>
Exhibit Method of
No. Description Filing
<S> <C> <C>
13.1 Pages 20, 22-23 and the inside back cover of the DQE Filed here.
Annual Report to Shareholders for the year ended
December 31, 1998. The Report, except those portions
specifically incorporated by reference here, is not to be
deemed "filed" for any purpose under the Securities
Exchange Act of 1934 or otherwise.
21.1 Subsidiaries of the registrant:
DQE's only significant subsidiary is Duquesne Light
Company, incorporated in Pennsylvania.
23.1 Independent Auditors' Consent. Filed here.
27.1 Financial Data Schedule. Filed here.
</TABLE>
x An additional document, substantially identical in all material respects
to this Exhibit, has been entered into relating to one additional limited
partnership Owner Participant. Although the additional document may differ
in some respects (such as name of the Owner Participant, dollar amounts
and percentages), there are no material details in which the document
differs from this Exhibit.
y Additional documents, substantially identical in all material respects to
this Exhibit, have been entered into relating to four additional corporate
Owner Participants. Although the additional documents may differ in some
respects (such as names of the Owner Participants, dollar amounts and
percentages), there are no material details in which the documents differ
from this Exhibit.
z Additional documents, substantially identical in all material respects to
this Exhibit, have been entered into relating to six additional Owner
Participants. Although the additional documents may differ in some
respects (such as names of the Owner Participants, dollar amounts and
percentages), there are no material details in which the documents differ
from this Exhibit.
Copies of the exhibits listed above will be furnished, upon request, to
holders or beneficial owners of any class of DQE's stock as of February 28,
1999, subject to payment in advance of the cost of reproducing the exhibits
requested.
66
<PAGE>
SCHEDULE II
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 1998, 1997 and 1996
(Thousands of Dollars)
<TABLE>
<CAPTION>
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
----------- ---------- ---------- ---------- ---------- -------
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1998
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $15,016 $11,278 $3,290(A) $20,169(B) $ 9,415
---------- ---------- ---------- ---------- -------
Year Ended December 31, 1997
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $18,688 $11,000 $3,934(A) $18,606(B) $15,016
---------- ---------- ---------- ---------- -------
Year Ended December 31, 1996
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $18,658 $10,582 $4,080(A) $14,632(B) $18,688
---------- ---------- ---------- ---------- -------
</TABLE>
Notes: (A) Recovery of accounts previously written off.
(B) Accounts receivable written off.
<PAGE>
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.
DQE
(Registrant)
Date: March 26, 1999 By: /s/ David D. Marshall
---------------------
(Signature)
David D. Marshall
President and Chief Executive Officer
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.
<TABLE>
<CAPTION>
Signature Title Date
<S> <C> <C>
/s/ David D. Marshall President, Chief Executive Officer and Director March 26, 1999
- ------------------------
David D. Marshall
/s/ Gary L. Schwass Executive Vice President and Chief Financial Officer March 26, 1999
- ------------------------
Gary L. Schwass
/s/ Morgan K. O'Brien Vice President, Treasurer and Controller March 26, 1999
- ------------------------ (Principal Accounting Officer)
Morgan K. O'Brien
/s/ Daniel Berg Director March 26, 1999
- ------------------------
Daniel Berg
Director
- ------------------------
Doreen E. Boyce
/s/ Robert P. Bozzone Director March 26, 1999
- ------------------------
Robert P. Bozzone
/s/ Sigo Falk Director March 26, 1999
- ------------------------
Sigo Falk
Director
- ------------------------
William H. Knoell
/s/ Thomas J. Murrin Director March 26, 1999
- ------------------------
Thomas J. Murrin
/s/ Eric W. Springer Director March 26, 1999
- ------------------------
Eric W. Springer
</TABLE>
<PAGE>
Exhibit 10.12
Schedule to Exhibit 10.14 to the Form 10-K Annual Report
of DQE for the year ended December 31, 1996
A Non-Competition and Confidentiality Agreement which was substantially
identical to that filed as Exhibit 10.14 was entered into with the following
parties, differing only as to the date executed:
William J. DeLeo Duquesne Light Company
<PAGE>
Exhibit 10.14
Schedule to Exhibit 10.1 to the Form 10-Q Quarterly Report
of DQE for the quarter ended March 31, 1997
A Severance Agreement which was substantially identical to that filed as
Exhibit 10.1 was entered into with the following party, materially differing
only as follows:
Other Party Material Differences
----------- --------------------
William J. DeLeo "Severance Benefit" under Section 3a:
aggregate lump sum payment of $284,416; no
additional lump sum amount payable if
terminated prior to June 30, 1999.
<PAGE>
Exhibit 10.71
AquaSource entered into Stock Purchase Agreements in the following form
with its 66 Class B stockholders to purchase 19,590 shares of Class B stock.
AquaSource placed $30 million in escrow to fund the payments described in the
agreement.
FORM OF
STOCK PURCHASE AGREEMENT
This STOCK PURCHASE AGREEMENT, dated as of February 16, 1999 (this
"Agreement") is by and between the undersigned owner (a "Class B Investor" or
the "Seller") of the designated number of shares set forth on the signature page
hereto ("Shares") of Class B Common Stock ("Class B Stock") of AquaSource, Inc.,
a Delaware corporation (the "Company"), and the Company.
RECITALS:
WHEREAS, the Seller owns the Shares; and
WHEREAS, subject to and according to the terms of this Agreement, the
Company wishes to purchase from the Seller, and the Seller wishes to sell to the
Company, the Shares; and
WHEREAS, in connection with such purchase and sale, the parties wish to
engage in certain other transactions which are the subject of this Agreement.
NOW, THEREFORE, in consideration of the premises and the mutual promises
herein made, as well as the representations, warranties, and covenants herein
contained, the parties, intending to be legally bound, agree as follows:
1. Definitions. Unless the context otherwise specifies or requires, the terms
defined in this Section 1 shall, for the purposes of this Agreement, have the
meanings herein specified.
"Additional Amount" is defined in Section 2.2.
"API" means Acquisition Partners, Inc.
"Appraised Value" has the meaning set forth in the Services Agreement.
"Business Day" means any day that is not a Saturday, a Sunday, or a day
that is a banking holiday under United States, Pennsylvania or Texas Law.
"Cash Amount" is defined in Section 2.2(1).
<PAGE>
"Closing" is defined in Section 6.
"Closing Date" is defined in Section 6.
"Closing Milestone" is defined in Section 2.2.
"Code" means the Internal Revenue Code of 1986, as amended.
"DQE Investment" has the meaning set forth in the Service Agreement.
"Employment Consent" is defined in Section 5(e).
"Escrow Agent" means the escrow agent serving from time to time under the
Escrow Agreement.
"Escrow Agreement" means the Escrow Agreement of even date herewith, by and
between the Company, the holders of Class B Stock listed therein (including the
Seller) and Chase Bank of Texas, National Association, as the same may be
amended, modified, supplemented or replaced from time to time in the form
attached as Exhibit A.
"Factor" is defined in Section 2.2(2).
"Final Value" is defined in Schedule A of the Services Agreement.
"Governmental Authority" means any federal, state, local or foreign
government or any department, agency, political subdivision, commission or court
thereof.
"Law" means any common law and any constitution, statute, code, regulation,
rule, injunction, judgment, order, decree, ruling, or other charge of any
applicable Governmental Authority.
"Person" means any individual, partnership, association, corporation,
limited liability company, trust, joint venture, other legal entity, or a
Governmental Authority.
"Purchase Price" is defined in Section 2.1.
"Representative" means Edward R. Wallace or such other Person as a majority
of the Class B Stockholders (other than the Company) may designate.
"Second Amendment" is defined in Section 2.4.
"Security Interest" means any mortgage, pledge, lien, encumbrance, charge,
or other security interest of any kind or type whatsoever.
"Services Agreement" means that certain Services Agreement by and among the
Company and API, as the same may be amended, modified, supplemented or replaced
from time to time.
-2-
<PAGE>
"Stockholders Agreement" means that certain Stockholders Agreement among
DQE, Inc. (successor in interest to DQEnergy Partners, Inc.), those Class B
Investors listed on the signature pages thereto and the Company dated as of
April 4, 1997, as previously amended by the First Amendment to Stockholders
Agreement dated as of April 4, 1997.
"Stock Power" is defined in Section 5.
"Transaction Documents" means this Agreement, the Second Amendment, the
Employment Consent, the Escrow Agreement, the Stock Power, Power of Attorney and
the Written Consent.
"Written Consent" is defined in Section 2.4.
2. Purchase and Sale.
2.1 Basic Transaction. On and subject to the terms and conditions of this
Agreement, the Company agrees to purchase from the Seller, and the Seller agrees
to sell to the Company, the Shares in exchange for, among other things, the
consideration being specified in this Section 2 (such consideration being
referred to herein as the "Purchase Price").
2.2 Transfer of Shares; Payment of Purchase Price.
(1) The Seller shall transfer Shares to the Company, and the Company
shall pay the Seller the Purchase Price, through the Escrow Agent on each of the
following dates (each a "Closing Milestone"), as follows:
(A) on the later of February 16, 1999 or 12 months after the date
on the initial certificate representing the Shares originally issued to
Seller, the Escrow Agent shall transfer or cause to be transferred one-
quarter of the Shares to the Company and the Escrow Agent shall pay to the
Seller $__________ (a "Cash Amount");
(B) on February 28, 2000, the Escrow Agent shall transfer or
cause to be transferred one-tenth of the Shares to the Company and the
Escrow Agent shall pay to the Seller $__________ (a "Cash Amount") plus the
Additional Amount for 1999;
(C) on February 28, 2001, the Escrow Agent shall transfer or
cause to be transferred one-tenth of the Shares to the Company and the
Escrow Agent shall pay to the Seller $__________ (a "Cash Amount") plus the
Additional Amount for 2000;
(D) on February 28, 2002, the Escrow Agent shall transfer or
cause to be transferred one-tenth of the Shares to the Company and the
Escrow Agent shall pay to the Seller the Additional Amount for 2001;
(E) on February 28, 2003, the Escrow Agent shall transfer or
cause to be transferred one-tenth of the Shares to the Company and the
Escrow Agent shall pay to the Seller the Additional Amount for 2002;
-3-
<PAGE>
(F) on February 28, 2004, the Escrow Agent shall transfer or
cause to be transferred one-tenth of the Shares to the Company and the
Escrow Agent shall pay to the Seller the Additional Amount for 2003; and
(G) upon termination of the Services Agreement, the Escrow Agent
shall transfer or cause to be transferred the remaining one-quarter or the
remaining balance of the Shares to the Company and the Escrow Agent shall
pay to Seller a final payment, if any, upon determination of the Final
Value.
The "Additional Amount" is an amount in dollars which is the product of (i)
66 2/3% multiplied by the number of Class B Shares owned by the Seller on the
date hereof divided by 19,590; and (ii) the Annual Distribution Amount, if any,
as such amount is determined from time to time pursuant to Schedule A of the
Services Agreement.
(2) Notwithstanding the foregoing, except for the payment due on the
Closing Milestone set forth in Section 2.2(1)(A) above, if the Seller's
employment with the Company or API, as the case may be, terminates for any
reason, Seller shall receive:
(i) the Additional Amount for the year in which Seller's
employment terminates at the time such payment is
scheduled to be paid; plus
(ii) on February 28, 2004, any of the unpaid Cash Amounts under
2.2 (B) or (C) multiplied by the Factor; plus
(iii) on February 28, 2004, an amount equal to the sum of all
Additional Amounts accrued through the time of Seller's
termination multiplied by the Factor.
The amount payable in (ii) and (iii) of the preceding sentence shall accrue
interest from the date of termination at a rate equal to that borne by six-month
U.S. Government T-Bills from time to time. The "Factor" means the lesser of the
ratio of (i) the Final Value at the termination of the Services Agreement
divided by the corresponding aggregate DQE Investment, and that quotient divided
by the value obtained by dividing by the Appraised Value for the year in which
the Seller's employment was terminated by the aggregate DQE Investment for that
year or (ii) the ratio of the Final Value less the corresponding aggregate DQE
Investment, and that difference divided by the value obtained by subtracting the
aggregate DQE Investment for the year in which the Seller's employment was
terminated from the Appraised Value for that year; provided, however, that the
Factor shall never be greater than one or less than zero. If there is no Final
Value determination at February 28, 2004, the Appraised Value determined as of
February 28, 2004 will be used. In the event Seller's termination of employment
with the Company or API, as applicable, the remaining balance of Seller's Shares
held by the Escrow Agent shall be surrendered to the Company on February 28,
2004.
(3) In the event that the Services Agreement is terminated prior to
February 28, 2004, Seller shall be paid all Cash Amounts, payable at their
respective Closing Milestone, plus the sum of all Additional Amounts accrued and
unpaid through the date of the
-4-
<PAGE>
termination of the Services Agreement and any payment due as a result of the
determination of a Final Value, as defined in the Services Agreement. The
remaining balance of Seller's Shares shall be transferred to the Company upon
payment to Seller of all amounts due under Section 2.2(3). Upon termination of
the Services Agreement, the Company at its sole discretion may accelerate any
payments set forth in Section 2.2(2) upon which the Company shall receive any
remaining Shares from the Escrow Agent.
(4) In the event of Seller's death, Seller's estate or personal
representative shall only receive the Cash Amounts in (A), (B) and (C) of
Section 2.2(1) payable upon the respective Closing Milestones plus any accrued
but unpaid Additional Amounts as of the date of death.
The Seller hereby acknowledges that the consideration received by the
Seller as set forth in this Section 2.2 for the Seller's Shares will be
different from and received at different times than that consideration per share
contemplated in the Stockholders Agreement and may be different from the
consideration per share received by other sellers of Class B Stock and consents
thereto.
2.3 Escrow. To facilitate and effect the transfer of Shares and payment
of Purchase Price at each Closing Milestone hereunder, the Company and the
Seller have agreed to the escrow arrangement provided for in the Escrow
Agreement, and, in connection therewith, will take the actions (among others)
set forth in Section 5(a), (b) and (c) and Section 7 of this Agreement.
2.4 Treatment of Stockholders Agreement. Seller will execute and deliver
the following documents:
(a) Contemporaneously with the execution of this Agreement, the Second
Amendment to Stockholders Agreement in the form attached hereto as Exhibit
B (the "Second Amendment"), which shall become effective upon the execution
and delivery of the same by the holders of at least 80% of the Class B
Common Stock; and
(b) Contemporaneously with the execution of this Agreement, a Written
Consent ("Written Consent") of the Class B Stockholders of AquaSource, Inc.
in the form attached hereto as Exhibit C.
2.5 Termination of Employment Agreement. By execution of this Agreement,
the Company and the Seller hereby terminate that certain Employment Agreement by
and between the Seller and the Company and hereby release each other from any
further obligations thereunder.
3. Representations and Warranties of the Seller. The Seller hereby represents
and warrants to the Company as follows:
3.1 Power and Authority; Enforceability. The Seller has all requisite
legal power and authority to enter into this Agreement, the other Transaction
Documents and all other documents to be entered into by the Seller in connection
with the consummation of the transactions contemplated hereby and to perform the
Seller's obligations hereunder and thereunder. This Agreement, the other
Transaction Documents and all other documents being
-5-
<PAGE>
entered into by the Seller in connection with the consummation of the
transactions contemplated hereby have been duly executed and delivered by the
Seller and, assuming due authorization, execution and delivery by the Company,
constitute the legal, valid and binding obligations of the Seller enforceable in
accordance with their respective terms, except that (i) such enforcement may be
limited by bankruptcy, insolvency, reorganization, moratorium or similar Laws
relating to or affecting creditors' rights generally and (ii) the remedy of
specific performance and injunction and other forms of equitable relief may be
subject to equitable defenses and to the discretion of the court before which
any proceeding therefor may be brought.
3.2 Ownership of Class B Company Stock. The Seller owns beneficially and,
of record, the Shares. Except for this Agreement and the Stockholders Agreement
there are no outstanding options, convertible securities, rights (preemptive or
other), warrants, calls or agreements relating to the Shares. The Seller is the
lawful owner of the Shares with full right, power and authority to sell and
transfer them, free and clear of any and all Security Interests, proxies,
shareholder agreements, voting agreements, voting trusts and adverse claims, to
the Company pursuant to the provisions of this Agreement. The Shares are being
sold and transferred by the Seller to the Company free and clear of any and all
Security Interests, proxies, shareholder agreements, voting agreements, voting
trusts and adverse claims.
3.3 No Default or Consents. Neither the execution and delivery of this
Agreement or any other Transaction Documents nor the consummation of the
transactions contemplated herein or therein (A) will conflict with or result in
(or with giving notice or passage of time would result in) a breach, default or
violation of any agreement, document, instrument, judgment, decree, order,
governmental permit, certificate or license to which the Seller is a party or to
which the Seller is subject or by which the Seller's property, including the
Shares, is bound, or (B) will result in the creation of any Security Interest on
any property or asset of the Seller, including the Shares; or (C) will require
the Seller to obtain the consent of any Person. No consent, action, approval or
authorization of, or registration, declaration or filing with, any Governmental
Authority having jurisdiction over the Seller or other Person is required to
authorize the execution and delivery of this Agreement or the other Transaction
Documents by the Seller or the performance of its or their terms or the
transactions contemplated hereby or thereby by the Seller.
3.4 Third-Party Fees. The Seller does not have any liability to pay any
fees or commissions to any broker, finder, or agent with respect to the
transactions contemplated by this Agreement for which the Company could be
liable or obligated at or after Closing.
4. Representations and Warranties of the Company. Subject to satisfying the
Conditions to Closing set forth in Section 6, the Company represents and
warrants to the Seller as follows:
4.1 Organization. The Company is a corporation duly organized, validly
existing, and in good standing under the Laws of the State of Delaware
4.2 Authorization of Transaction. The Company has all requisite power and
authority to execute and to deliver this Agreement and the Escrow Agreement, to
perform its obligations hereunder and thereunder and to consummate the
transactions contemplated hereby and thereby. The execution and delivery of
this Agreement and the Escrow Agreement by the
-6-
<PAGE>
Company and the consummation of the transactions contemplated hereby and thereby
have been duly authorized by all necessary corporate action and no other action
on the part of the Company is necessary to authorize this Agreement, the Escrow
Agreement or to consummate the transactions contemplated hereby. This Agreement
has been duly executed and delivered by the Company and constitutes the valid
and legally binding obligation of the Company, enforceable in accordance with
its terms.
4.3 Third-Party Fees. The Company does not have any liability to pay any
fees or commissions to any broker, finder, or agent with respect to the
transactions contemplated by this Agreement for which the Seller could become
liable or obligated.
4.4 Investment Intent. The Company is acquiring the Shares for the
Company's own account and not with a view to, or for sale in connection with,
directly or indirectly, any distribution thereof that would require registration
under the Securities Act of 1933, as amended (the "Securities Act") or
applicable state securities laws or would otherwise violate the Securities Act
or such state securities laws.
5. Pre-Closing Covenants and Actions. Contemporaneously with the execution of
this Agreement by the parties, the parties shall engage in the following
actions:
(a) The Seller, the Company and Escrow Agent shall enter into the
Escrow Agreement;
(b) The Seller shall deposit into escrow its Shares along with an
executed Stock Power duly endorsed in blank in the form attached hereto as
Exhibit D-1 or such Stock Power coupled with an endorsed Power of Attorney
in the form attached hereto as Exhibit D-2 in order to sell such Shares to
the Escrow Agent, in the event such shares are held by a fiduciary on
behalf of the Seller or the Seller's estate (the "Stock Power");
(c) The Company shall deposit with the Escrow Agent $30,000,000 to
fund the Cash Amounts referenced in Section 2.2;
(d) The Seller shall execute and deliver to the Company the Written
Consent; and
(e) The Seller shall execute that certain Employment Consent (the
"Employment Consent") attached hereto as Exhibit E by and between the
Company, API and Seller regarding the employment of Seller.
6. Closing; Closing Date. Upon the occurrence of a Closing Milestone, the
parties shall close the sale and purchase of the Shares specifically identified
to the Closing Milestone (the "Closing"), in accordance with the terms hereof
and the Escrow Agreement. The precise date and time will be established and
agreed to by the parties, but shall be not later than five Business Days
following the Closing Milestone (the "Closing Date").
-7-
<PAGE>
The following conditions shall have been satisfied prior to the initial
Closing:
(a) the Second Amendment shall have been entered into by Seller and
become effective as set forth in Section 2.4, thereby amending the
Stockholders Agreement; and
(b) the Written Consent shall have been executed and delivered by
Seller and the holders of a majority of the Class B Common Stock and the
Company's Certificate of Incorporation shall have been amended as
contemplated therein.
7. Closing; Closing Procedure. At each Closing, the following shall occur:
(a) The Escrow Agent on behalf of the Company shall deliver to the
Seller the applicable portion of the Purchase Price as set forth in Section
2.2 in cash or other immediately available funds in a manner which is
acceptable to the Seller, and the Company agrees to deliver to the Escrow
Agent an amount necessary to meet such Purchase Price obligation no later
than five Business Days prior to the Closing Date;
(b) If required by any party, both the Seller and the Company shall
sign a certificate indicating that the representations and warranties
specified in Section 3 as to the Seller and Section 4 as to the Company are
true and correct as of the Closing Date;
(c) The Escrow Agent on behalf of the Seller and pursuant to the Stock
Power shall sign, transfer and convey to the Company all of the Seller's
right, title and interest in that number of Shares to be delivered to the
Company pursuant to Section 2.2;
(d) Each party shall deliver any other documents or take any other
actions necessary or helpful to facilitate and accomplish the purposes of
this Agreement as well as to consummate the various transactions
contemplated herein necessary for Closing.
8. Post-Closing Covenants and Actions.
8.1 Other Required Actions. In case at any time after the Closing any
further action is necessary or desirable to carry out the purposes of this
Agreement, each of the parties will take such further action (including the
execution and delivery of such further instruments and documents) as the other
party reasonably may request; provided, however, that this Section 8.1 shall not
be deemed to require either party to expend funds or to incur obligations not
otherwise expressly required pursuant to this Agreement.
8.2 Non-Compete. The Seller further agrees that during the term of this
Agreement and for three years following the completion of the payments to the
Seller in exchange for the Shares as set forth in Section 2.2 (the "Restricted
Period"), the Seller shall not, directly or indirectly, compete with the Company
or any direct or indirect affiliate thereof in any manner, on behalf of the
Seller or any other Person, including, without limitation, that the Seller shall
not (i) engage in Company Business (as hereafter defined); (ii) enter the employ
of, or render any services to, any Person engaged in Company Business; (iii)
become interested in any such Person engaged in Company Business as an
individual, partner, shareholder, officer, director, licensor,
-8-
<PAGE>
licensee, principal, agent, employee, trustee, consultant or in any other
relationship or capacity; provided, however, that the Seller may own, directly
or indirectly, solely as an investment, securities of any Person which are
traded on any national securities exchange if the Seller (A) is not a
controlling Person of, or a member of a group which controls, such Person or (B)
does not, directly or indirectly, own 1% or more of any class of securities of
such Person; or (iv) request or instigate any account or customer of the Company
or any direct or indirect affiliate thereof to withdraw, diminish, curtail or
cancel any of its business with the Company. "Company Business" shall mean any
business actually conducted by the Company or any direct or indirect affiliate
thereof or contemplated to be conducted by the Company or any direct or indirect
affiliate thereof in the Geographic Proximity. "Geographic Proximity" shall mean
the states in which such business is conducted either at the beginning of the
Restricted Period or in the future. In addition, during the Restricted Period,
the Seller shall refrain from soliciting employees of the Company or its direct
or indirect affiliates for employment with the Seller or with any other Person
engaged in Company Business. The parties hereto agree that Seller's employment
with Acquisition Partners, Inc., if it occurs, does not violate the provisions
of this Section 8.2 as long as the Services Agreement is in effect.
9. Miscellaneous.
9.1 Advisors. Seller has been afforded the opportunity to discuss this
Agreement and the transactions contemplated herein with counsel and/or a
financial advisor of Seller's choice.
9.2 No Third-Party Beneficiaries; Standing. This Agreement shall not
confer any rights or remedies upon any Person other than the parties and their
respective successors and permitted assigns and no Person, other than the
parties and their respective successors and permitted assigns, shall have
standing with respect to the matters which are the subject of this Agreement,
including, without limitation, this Agreement, the various agreements attached
hereto or referenced herein and the transactions contemplated hereby or thereby.
9.3 Entire Agreement. This Agreement (including the documents referred to
herein) constitutes the entire agreement among the parties and supersedes any
prior understandings, agreements, or representations between the parties,
written or oral, to the extent they related in any way to the subject matter
hereof.
9.4 Succession and Assignment. This Agreement shall be binding upon and
inure to the benefit of the parties named herein and their respective heirs,
successors and permitted assigns. No party may assign either this Agreement or
any of its rights, interests, or obligations hereunder without the prior written
approval of the other parties hereto.
9.5 Multiple Counterparts. This Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of which
together will constitute one and the same instrument.
-9-
<PAGE>
9.6 Notices. Any notice, request, instruction, correspondence or other
documents to be given hereunder by either party to the other (herein
collectively called "Notice") shall be in writing and delivered in person or by
courier service requiring acknowledgment of receipt of delivery or mailed in the
country of origination by certified or registered mail, postage prepaid and
return receipt requested, or by telecopier, as follows:
If to the Seller, addressed as follows:
The name and address set forth on
the signature page hereto
If to the Company, addressed as follows:
AquaSource, Inc.
15th Floor
411-Seventh Avenue
Pittsburgh, PA 15230-1930
ATTN: Donald J. Clayton
Telecopier No.: 412-393-6721
Notice given by personal delivery or courier service shall be effective upon
actual receipt. Notice given by telecopier shall be confirmed by appropriate
answer back and shall be effective upon actual receipt if received during the
recipient's normal business hours, or at the beginning of the recipient's next
business day after receipt if not received during the recipient's normal
business hours. Notice given by mail shall be effective 72 hours after its
deposit in the mails as provided herein. Any party may change any address to
which Notice is to be given to it by giving at least 72 hours advance Notice as
provided above of such change of address.
9.7 Governing Law. This Agreement shall be governed by and construed in
accordance with the Laws of the State of Delaware without giving effect to any
choice or conflict of Law provision or rule (whether of the State of Delaware or
any other jurisdiction) that would cause the application of the Laws of any
jurisdiction other than the State of Delaware.
9.8 Amendments and Waivers. No amendments of any provision of this
Agreement shall be valid unless the same shall be in writing and signed by each
party hereto. No waiver by either party of any default, misrepresentation, or
breach of warranty or covenant hereunder, whether intentional or not, shall be
deemed to extend to any prior or subsequent default, misrepresentation, or
breach of warranty or covenant hereunder or affect in any way any rights arising
by virtue of any prior or subsequent such occurrence.
9.9 Severability. Any term or provision of this Agreement that is invalid
or unenforceable in any situation in any jurisdiction shall not affect the
validity or enforceability of the remaining terms and provisions hereof or the
validity or enforceability of the offending term or provision in any other
situation or in any other jurisdiction.
-10-
<PAGE>
9.10 Expenses. Each of the parties will bear its own costs and expenses
(including legal fees and expenses) incurred in connection with this Agreement
and the transactions contemplated hereby.
9.11 Construction. The parties have participated jointly in the
negotiation and drafting of this Agreement. In the event an ambiguity or
question of intent or interpretation arises, this Agreement shall be construed
as if drafted jointly by the parties, and no presumption or burden of proof
shall arise favoring or disfavoring either party by virtue of the authorship of
any of the provisions of this Agreement. Any reference to any federal, state,
local, or foreign statute or law shall be deemed also to refer to all rules and
regulations promulgated thereunder, unless the context requires otherwise. The
word "including" shall mean including without limitation.
9.12 Specific Performance. The parties hereto agree that this Agreement
shall be specifically enforceable and the parties hereto hereby waive any
defense to such a proceeding in equity that monetary damages are sufficient.
9.13 Exhibits. Each agreement, schedule and exhibit attached to this
Agreement or referred to herein is hereby incorporated herein and made a part
hereof for all purposes as if fully set out in this Agreement.
9.14 No Individual Liability. With respect to any party who has entered
into this Agreement in his or her capacity as a director, officer, employee,
trustee, fiduciary or other type of representative of another Person, this
Agreement and the various rights, obligations and liabilities imposed hereunder
apply to such party in his or her representative capacity only and shall not
impose nor create any rights, obligations and liabilities against such Person in
his or her individual capacity or in any other manner other than in his or her
representative capacity.
9.15 Waiver of Trial by Jury. The parties hereto (including, in the case
of the Company, in its own behalf and, to the extent permitted by applicable
law, on behalf of its subsidiaries and affiliates) waive all right to trial by
jury in any such action, proceeding or counterclaim (whether based on contract,
tort or otherwise) related to or arising out of this Agreement.
-11-
<PAGE>
IN WITNESS WHEREOF, the parties have executed this Agreement this ____ day
of February, 1999, to be effective as of the date first above written.
SELLER
By:
Fax No. (if applicable):
Number of Shares:
COMPANY
By:
Donald J. Clayton
President
-12-
<PAGE>
DQE Exhibit 12.1
DQE and Subsidiaries
Calculation of Ratio of Earnings to Fixed Charges
and Preferred and Preference Stock Dividend Requirements
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $ 81,076 $ 87,420 $ 88,478 $ 95,391 $101,027
Other interest 14,556 13,823 10,926 7,033 4,050
Portion of lease payments representing
an interest factor 44,146 44,208 44,357 44,386 44,839
Dividend requirement 15,612 21,649 14,385 7,374 9,355
-------- -------- -------- -------- --------
Total Fixed Charges $155,390 $167,100 $158,146 $154,184 $159,271
-------- -------- -------- -------- --------
EARNINGS:
Income from continuing operations $196,688 $199,101 $179,138 $170,563 $156,816
Income taxes 100,982* 95,805* 87,388* 96,661* 92,973*
Fixed charges as above 155,390 167,100 158,146 154,184 159,271
-------- -------- -------- -------- --------
Total Earnings $453,060 $462,006 $424,672 $421,408 $409,060
-------- -------- -------- -------- --------
RATIO OF EARNINGS TO FIXED CHARGES 2.92 2.76 2.69 2.73 2.57
======== ======== ======== ======== ========
</TABLE>
The Company's share of the fixed charges of an unaffiliated coal supplier,
which amounted to approximately $2.5 million for the twelve months ended
December 31, 1998, has been excluded from the ratio.
*Earnings related to income taxes reflect a $12.0 million, $17.0 million, $12.0
million, $13.5 million and $13.5 million decrease for the twelve months ended
December 31, 1998, 1997, 1996, 1995 and 1994, respectively, due to a financial
statement reclassification related to Statement of Financial Accounting
Standards No. 109, Accounting for Income Taxes. The ratio of earnings to fixed
charges, absent this reclassification equals 2.99, 2.87, 2.76, 2.82 and 2.65
for the twelve months ended December 31, 1998, 1997, 1996, 1995 and 1994,
respectively.
<PAGE>
Exhibit 13.1
DQE OFFICERS
David D. Marshall, 46. President and Chief Executive Officer. Previously held
senior executive positions in finance at Central Vermont Public Service. Joined
the company in 1985. Directorships included on page 19.
Gary L. Schwass, 53. Executive Vice President and Chief Financial Officer.
Previously served in a variety of senior executive positions in finance and
management with Consumers Power Company. Joined the company in 1985.
Directorships include Chair, Western Pennsylvania Development Credit Corporation
(promotes small business through lending activities), and Vice President and
Treasurer, Holy Family Foundation (supports families in crisis).
Victor A. Roque, 52. Executive Vice President and General Counsel. Formerly
Vice President, General Counsel and Secretary for Orange and Rockland Utilities.
Joined the company in 1994. Directorships include the Pennsylvania Business
Roundtable (economic development), the Hill House Association (provider of
social services), the Urban League of Pittsburgh, and the United Way Good
Neighbors Advisory Committee. Member, Salvation Army Greater Pittsburgh
Advisory Board.
William J. DeLeo, 48. Vice President and Chief Administrative Officer.
Previously held senior management positions with Duquesne Light, Gulf Oil and
Price Waterhouse. Joined the company in 1985. Directorships include the
Pittsburgh Civic Light Opera.
James D. Mitchell, 47. Vice President. Previously held senior financial
positions with Duquesne Light and U.S. West, Inc. Joined the company in 1988.
Directorships include Three Rivers Youth (helps troubled teenagers).
Morgan K. O'Brien, 38. Vice President, Controller and Treasurer. Previously
held senior financial positions at DQE, Duquesne Light, PNC Bank and Deloitte &
Touche. Joined the company in 1991.
Jack E. Saxer, Jr., 55. Vice President. Previously held senior financial
positions with Gulf Oil and Chevron. Joined the company in 1989. Directorships
include Point Venture (venture capital) and Pittsburgh Consumer Health Coalition
(healthcare advocacy for the disadvantaged).
Diane S. Eismont, 54
Corporate Secretary
- --------------------------------------------------------------------------------
Duquesne Light Company Officers
David D. Marshall, 46
President and Chief
Executive Officer
Gary L. Schwass, 53
Senior Vice President
and Chief Financial Officer
Victor A. Roque, 52
Senior Vice President
and General Counsel
James E. Cross, 52
President,
Generation Group
Gary R. Brandenberger, 61
Vice President and Assistant
to the President
William J. DeLeo, 48
Vice President, Corporate
Services
Edward N. Neal, 52
Vice President,
Customer Operations
Morgan K. O'Brien, 38
Vice President, Finance
Frosina C. Cordisco, 47
Treasurer
Diane S. Eismont, 54
Corporate Secretary and
Assistant General Counsel
James E. Wilson, 33
Controller
<PAGE>
1998 Financial Statements at A Glance
Detailed financial information can be found beginning on page 29.
Selected Financial Data
(in millions, except per share amounts)
<TABLE>
<CAPTION>
1998 1997 1996 1995
<S> <C> <C> <C> <C>
Selected Income Statement Items:
Revenues from sales of electricity $1,127 $1,124 $1,144 $1,149
Fuel and purchased power expenses 263 223 237 232
- ---------------------------------------------------------------------------
Net electric revenues 864 901 907 917
Other revenues 143 106 93 81
- ---------------------------------------------------------------------------
Net operating revenues 1,007 1,007 1,000 998
- ---------------------------------------------------------------------------
Operating and maintenance expenses 437 401 388 384
Depreciation and amortization 217 243 223 203
Taxes other than income taxes 81 83 86 89
- ---------------------------------------------------------------------------
Non-energy operating expenses 735 727 697 676
- ---------------------------------------------------------------------------
Operating income 272 280 303 322
Investment and other income 136 130 73 52
Interest and other charges 110 115 110 107
Income taxes 101 96 87 96
Pa restructuring charge (net of tax) 83 -- -- --
- ---------------------------------------------------------------------------
Net income $ 114 $ 199 $ 179 $ 171
===========================================================================
Basic EPS $ 2.52* $ 2.57 $ 2.32 $ 2.20
===========================================================================
Diluted EPS $ 2.48* $ 2.54 $ 2.29 $ 2.17
===========================================================================
Ratio of earnings to fixed
charges (pre-tax) 2.92* 2.76 2.69 2.73
===========================================================================
- ---------------------------------------------------------------------------
Selected Balance Sheet Items:
Long-term investments $ 760 $ 723 $ 519 $ 441
Property, plant and equipment $1,717 $2,662 $2,817 $3,060
Total assets $5,248 $4,694 $4,639 $4,459
Total capitalization $3,112 $3,103 $3,055 $2,801
===========================================================================
- ---------------------------------------------------------------------------
Capitalization Ratios:
Common shareholders' equity 47.8% 48.3% 45.6% 47.5%
Preferred and preference stock 8.4% 7.3% 7.3% 2.5%
Long-term debt 43.8% 44.4% 47.1% 50.0%
===========================================================================
- ---------------------------------------------------------------------------
Selected Common Stock Information:
Average shares outstanding 77.7 77.5 77.3 77.7
Shares outstanding at year-end 77.4 77.7 77.3 77.6
Market capitalization $3,400 $2,729 $2,241 $2,386
Dividends declared $ 113 $ 107 $ 101 $ 94
Dividends declared per share $ 1.46 $ 1.38 $ 1.30 $ 1.21
Book value per share at year-end $19.18 $19.30 $18.01 $17.13
Dividend payout ratio 57.1% 52.9% 55.2% 54.1%
Dividend yield at year-end 3.5% 4.1% 4.7% 4.2%
Return on average common equity 13.1% 13.8% 13.2% 13.1%
Price-earnings ratio at year-end 17.4 13.7 12.5 14.0
- ---------------------------------------------------------------------------
</TABLE>
* Basic EPS after Pennsylvania restructuring charge: $1.46; Diluted EPS after
Pennsylvania restructuring charge: $1.44;
Ratio of earnings to fixed charges (pre-tax) after Pennsylvania restructuring
charge: $2.39.
<PAGE>
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990 1989 1988
<S> <C> <C> <C> <C> <C> <C>
$1,146 $1,132 $1,127 $1,163 $1,110 $1,097 $1,047
244 238 239 254 229 220 231
- --------------------------------------------------------------
902 894 888 909 881 877 816
90 63 37 38 31 48 43
- --------------------------------------------------------------
992 957 925 947 912 925 859
- --------------------------------------------------------------
421 415 365 385 388 353 335
166 158 132 123 123 123 117
88 71 84 94 80 93 81
- --------------------------------------------------------------
675 644 581 602 591 569 533
- --------------------------------------------------------------
317 313 344 345 321 356 326
43 31 42 36 46 (3) 30
110 120 132 142 157 165 175
93 80 112 105 88 75 62
-- -- -- -- -- -- --
- --------------------------------------------------------------
$ 157 $ 144 $ 142 $ 134 $ 122 $ 113 $ 119
==============================================================
$ 1.98 $ 1.81 $ 1.78 $ 1.67 $ 1.49 $ 1.35 $ 1.24
==============================================================
$ 1.96 $ 1.79 $ 1.77 $ 1.65 $ 1.48 $ 1.34 $ 1.24
==============================================================
2.57 2.29 2.24 2.10 1.90 1.78 1.72
==============================================================
- --------------------------------------------------------------
$ 196 $ 126 $ 59 $ 44 $ 18 $ -- $ --
$3,140 $3,168 $3,037 $3,053 $3,048 $3,055 $3,066
$4,427 $4,550 $3,778 $3,851 $3,834 $3,921 $3,881
$2,750 $2,781 $2,716 $2,669 $2,770 $2,827 $2,866
==============================================================
- --------------------------------------------------------------
46.4% 44.2% 43.1% 41.6% 39.0% 37.7% 37.4%
3.5% 4.8% 4.9% 5.2% 6.8% 7.8% 8.5%
50.1% 51.0% 52.0% 53.2% 54.2% 54.5% 54.1%
==============================================================
- --------------------------------------------------------------
79.0 79.5 79.4 80.1 81.6 83.7 95.6
78.5 79.5 79.4 79.4 80.6 83.0 86.7
$1,550 $1,829 $1,708 $1,621 $1,337 $1,321 $1,084
$ 89 $ 86 $ 81 $ 78 $ 75 $ 73 $ 78
$ 1.13 $ 1.08 $ 1.03 $ 0.97 $ 0.92 $ 0.87 $ 0.81
$16.27 $15.47 $14.75 $14.00 $13.38 $12.85 $12.34
56.4% 58.8% 56.9% 57.6% 60.7% 63.1% 64.5%
5.7% 4.6% 5.0% 5.0% 5.8% 5.7% 6.8%
12.5% 12.0% 12.4% 12.2% 11.3% 10.6% 10.4%
9.9 12.7 12.1 12.3 11.1 11.8 10.1
- --------------------------------------------------------------
</TABLE>
<PAGE>
Shareholder Reference Guide
Common Stock
Trading Symbol: DQE
Stock Exchanges Listed and Traded:
New York, Philadelphia, Chicago
Number of Common Shareholders of Record
at Year-End: 68,270
DQE Internet Home Page
A variety of shareholder, customer service and economic development information
is available on DQE's home page on the World Wide Web. You also can interact
with us via electronic mail. Our address is www.dqe.com.
Shareholder Information Line
Shareholders and potential investors are invited to call
1-888-247-0401 for the latest information on earnings
and dividends.
Shareholder Services/Assistance
You can write to us at:
DQE Shareholder Relations
Box 68, Pittsburgh,PA 15230-0068
or call us at:
Toll-free: 1-800-247-0400
In Pittsburgh: 1-412-393-6167
Fax: 1-412-393-6087
By telephone, representatives are available from 7:30 a.m. to 4 p.m. (Eastern
time) to assist you with the following services:
Direct purchase of initial shares
Direct deposit of dividends
Automatic cash contributions
Dividend reinvestment
Stock transfer requirements
Dividend payment inquiries
Change of address
Lost stock certificate
Please feel free to call at other times. Our Message Center is available 24
hours a day. You can record a message, and our staff will follow up on the next
business day.
Financial Community Inquiries
Analysts, investment managers and brokers should direct their inquiries to 1-
412-393-4133; Fax: 1-412-393-4394. Written inquiries should be sent to the
Investor Relations Department at Box 68, Pittsburgh, PA 15230-0068.
Stock Certificate Transfers
Individuals who are not participants in the dividend reinvestment plan and who
want to transfer stock
certificates should send their certificates and related documents to our
transfer agent:
First National Bank of Boston
c/o Boston EquiServe
P.O. Box 8040
Boston, MA 02266-8040
Dividend reinvestment plan participants who want to transfer their shares should
send their certificates and related documents to DQE Shareholder Relations.
Direct Deposit of Dividends
Your DQE quarterly dividends can be deposited automatically into a personal
checking or savings account. Call Shareholder Relations toll-free for more
information.
Dividend Tax Status
The Company estimates that all common stock dividends paid in 1998 are taxable
as dividend income. This estimate is subject to audit by the Internal Revenue
Service.
Electri-Stock
The following investor services are available through DQE's dividend
reinvestment and stock purchase plan:
Direct Purchase of DQE Stock
DQE offers non-shareholders the ability to purchase common stock directly
through the Company. Call, write, or visit our home page at www.dqe.com for a
prospectus on this popular program.
Automatic Cash Contributions
Through this program, current reinvestment plan participants can make regular
cash contributions to purchase additional shares of DQE common stock by having
funds automatically withdrawn from their bank accounts.
Other Features and Services
. Purchase and sale of plan shares at nominal
commissions
. Acceptance of certificates for safekeeping
. Re-registration of some or all of a shareholder's holdings
. Creation of new accounts as gifts for family, friends or institutions you
support, including a complimentary gift
The DQE logo is a registered trademark of the Company.
E-FUEL(R) IS A REGISTERED TRADEMARK OF DUQUESNE ENERGY.
DQE AND ITS AFFILIATED COMPANIES ARE EQUAL OPPORTUNITY EMPLOYERS.
<PAGE>
DQE Exhibit 23.1
Independent Auditors' Consent
We consent to the incorporation by reference in Registration Statement No.
33-60966 of DQE, Inc. on Form S-3, Post Effective Amendment No. 3 to
Registration Statement No. 33-29147 of DQE, Inc. on Form S-8, Registration
Statement Nos. 33-66488 and 33-72582 of DQE, Inc. on Form S-8, Post Effective
Amendment No. 1 to Registration Statement No. 33-46773 and Post Effective
Amendment No. 1 to Registration Statement No. 33-87974 of DQE, Inc. on Form S-8
and Amendment No. 1 to Registration Statement No. 333-32433 of DQE, Inc. on Form
S-4 of our reports dated January 26, 1999, appearing in and incorporated by
reference in this Annual Report on Form 10-K of DQE, Inc. for the year ended
December 31, 1998.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Pittsburgh, Pennsylvania
March 25, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,447,299
<OTHER-PROPERTY-AND-INVEST> 1,029,949
<TOTAL-CURRENT-ASSETS> 374,752
<TOTAL-DEFERRED-CHARGES> 2,395,563
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 5,247,563
<COMMON> 73,119
<CAPITAL-SURPLUS-PAID-IN> 927,231
<RETAINED-EARNINGS> 869,671
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,484,045<F1>
4,500
259,056<F2>
<LONG-TERM-DEBT-NET> 1,364,879
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 4,525
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 79,685
0
<CAPITAL-LEASE-OBLIGATIONS> 36,596
<LEASES-CURRENT> 21,137
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,993,140
<TOT-CAPITALIZATION-AND-LIAB> 5,247,563
<GROSS-OPERATING-REVENUE> 1,269,598
<INCOME-TAX-EXPENSE> 100,982<F3>
<OTHER-OPERATING-EXPENSES> 997,732
<TOTAL-OPERATING-EXPENSES> 997,732
<OPERATING-INCOME-LOSS> 271,866
<OTHER-INCOME-NET> 136,005
<INCOME-BEFORE-INTEREST-EXPEN> 407,871
<TOTAL-INTEREST-EXPENSE> 110,201<F4>
<NET-INCOME> 196,688<F5>
866
<EARNINGS-AVAILABLE-FOR-COMM> 195,822
<COMMON-STOCK-DIVIDENDS> 114,218
<TOTAL-INTEREST-ON-BONDS> 81,076
<CASH-FLOW-OPERATIONS> 360,957
<EPS-PRIMARY> 2.52<F6>
<EPS-DILUTED> 2.48<F6>
<FN>
<F1>Includes $(385,976) of Treasury Stock at cost
<F2>Includes $12,674 of Preference Stock
<F3>Non-Operating Expense
<F4>Includes $16,748 of Preferred and Preference Stock Dividends
<F5>Excludes $82,548 extraordinary restructuring charge
<F6>Excludes $1.06 loss per share re: (F5)
</FN>
</TABLE>
